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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K

(Mark One) |  |
þ |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|  | For the fiscal year ended December 31, 2004
or
o |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|  | For the transition period from to

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.

(1) Designated portions of the Proxy Statement relating to the 2005 Annual Meeting of Shareholders |  | Part III (Items 10, 11, 12, 13 and 14)

FORM 10-K
ANNUAL REPORT
For the Year Ended December 31, 2004
TABLE OF CONTENTS

|  |  |  | Page |
PART I
Item 1. |  | Business |  |  | 3 |
Item 2. |  | Properties |  |  | 46 |
Item 3. |  | Legal Proceedings |  |  | 48 |
Item 4. |  | Submission of Matters to a Vote of Security Holders |  |  | 48 |
PART II
Item 5. |  | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  |  | 49 |
Item 6. |  | Selected Financial Data |  |  | 50 |
Item 7. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  |  | 54 |
Item 7A. |  | Quantitative and Qualitative Disclosures About Market Risk |  |  | 109 |
Item 8. |  | Financial Statements and Supplementary Data |  |  | 109 |
Item 9. |  | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |  |  | 109 |
Item 9A. |  | Controls and Procedures |  |  | 109 |
Item 9B. |  | Other Information |  |  | 111 |
PART III
Item 10. |  | Directors and Executive Officers of the Registrant |  |  | 111 |
Item 11. |  | Executive Compensation |  |  | 111 |
Item 12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |  |  | 111 |
Item 13. |  | Certain Relationships and Related Transactions |  |  | 112 |
Item 14. |  | Principal Accounting Fees and Services |  |  | 112 |
PART IV
Item 15. |  | Exhibits, Financial Statement Schedules |  |  | 112 |
Signatures and Power of Attorney |  |  | 125 |
Index to Consolidated Financial Statements and Other Information |  |  | F-1 |
EXHIBIT 10.1.9
EXHIBIT 10.1.10
EXHIBIT 10.1.11
EXHIBIT 10.3.6.1
EXHIBIT 10.3.13
EXHIBIT 12.1
EXHIBIT 21.1
EXHIBIT 23.1
EXHIBIT 23.2
EXHIBIT 23.3
EXHIBIT 23.4
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 99.1
EXHIBIT 99.2

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PART I

Item 1. | Business

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.

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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.

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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

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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:

| • | Continue to focus on our liquidity position as our second highest priority after integrity;
| • | Continue to improve our balance sheet through the extinguishment or repurchase of debt;
| • | Complete our current construction program and start construction of new projects in strategic locations only when power contracts and financing are available and attractive returns are expected;
| • | Put excess gas turbines to work in new projects, subject to the conditions stipulated above, or sell them;
| • | Continue to lower operating and overhead costs per megawatt hour (“MWh”) produced and improve operating performance with an increasingly efficient power plant fleet;
| • | Utilize our marketing and sales capabilities to selectively increase our power contract portfolio; and
| • | Grow our services businesses to complement our integrated power operations.

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

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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.

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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.

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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.

Air Pollutant Emission Rates — Pounds of Pollutant Emitted per MWh of Electricity Generated |
|  | Average US |  |  | Calpine Power Plants |
|  | Coal, Oil & |  |  |  |
|  | Gas-Fired |  |  | Combined-Cycle |  |  | % Less Than |  |  | Geothermal |  |  | % Less Than |
Air Pollutants |  | Power Plant (1) |  |  | Power Plant (2) |  |  | Avg US Plant |  |  | Power Plant (3) |  |  | Avg US Plant |
Nitrogen Oxides, NO x |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Acid rain, smog and fine particulate formation |  |  | 3.53 |  |  |  | 0.24 |  |  |  | 93.2% Less |  |  |  | 0.00074 |  |  |  | 99.9% Less |
Sulphur Dioxide, SO 2 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Acid rain and fine particulate formation |  |  | 8.51 |  |  |  | 0.005 |  |  |  | 99.9% Less |  |  |  | 0.00015 |  |  |  | 99.9% Less |
Mercury, Hg |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Neurotoxin |  |  | 0.000037 |  |  |  | 0 |  |  |  | 100% Less |  |  |  | 0.000008 |  |  |  | 78.4% Less |
Carbon Dioxide, CO 2 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Principal greenhouse gas — contributor to climate change |  |  | 1,930 |  |  |  | 890 |  |  |  | 53.9% Less |  |  |  | 85.6 |  |  |  | 95.6% Less |
Particulate Matter, PM |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Respiratory health effects |  |  | 0.5 |  |  |  | 0.038 |  |  |  | 92.4% Less |  |  |  | 0.014 |  |  |  | 97.2% Less |

(1) | The US fossil fuel fleet’s emission rates were obtained from the United States Department of Energy’s Electric Power Annual Report for 2003. Emission rates are based on 2003 emissions and net generation.
(2) | Calpine’s combined-cycle power plant emission rates are based on 2003 data.
(3) | Calpine’s geothermal power plant emission rates are based on 2003 data and include expected results from the mercury abatement program currently in process.

Calpine’s environmental record has been widely recognized.

| • | Calpine’s Board of Directors unanimously adopted a resolution restricting investments in low carbon dioxide emitting power plants.
| • | PSM is developing gas turbine components to improve turbine efficiency and to reduce emissions.
| • | Calpine Power Company has instituted a program of proprietary operating procedures to reduce gas consumption and lower air pollutant emissions per MWh of electricity generated.
| • | Calpine and its Chairman, President and CEO, Peter Cartwright, received the designation of “Clean Air Champion” from the New York League of Conservation Voters in recognition of our efforts to improve the quality of New York’s air.
| • | Peter Cartwright was recognized as the “Business Leader of the Year” by Scientific American Magazine for his commitment to low carbon technologies.

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| • | The American Lung Associations of the Bay Area selected Calpine and its Geysers geothermal operation for the 2004 Clean Air Award for Technology Development to recognize “Calpine’s commitment to clean renewable energy, which improves air quality and helps us all breathe easier.”
| • | Calpine and General Electric Co. teamed up for the North America launch of GE’s most advanced gas turbine technology, the H Systemtm, which will utilize a more efficient gas turbine combined-cycle system. The 775-MW project located in Southern California is expected to enter commercial operation in 2008.
| • | Calpine joined the US Environmental Protection Agency’s Climate Leaders Program, which is intended to encourage climate change strategies, help establish future greenhouse gas (“GHG”) emission reduction goals, and increase energy efficiency among participants. As part of Climate Leaders, Calpine will submit data on 2003 carbon dioxide (CO2) emissions from all its natural gas-fired power plants, for The Geysers — Calpine’s geothermal power generating plants in Northern California, and for Calpine natural gas production facilities located throughout the United States.
| • | Calpine became the first independent power producer to earn the distinction of Climate Action Leadertm by certifying its 2003 CO2 emissions inventory with the California Climate Action Registry. Calpine is now publicly and voluntarily reporting its CO2 emissions from generation of electricity in California under this rigorous registry program.

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 Systemtm. 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

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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.

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##### Table of Contents

DESCRIPTION OF POWER GENERATION FACILITIES

|  |  |  |  |  | Market Share |
NERC Region/ Country |  | Projects |  |  | Megawatts |  |  | (NERC/UK) |
WECC |  |  | 49 |  |  |  | 8,382 |  |  |  | 5 | %
ERCOT |  |  | 12 |  |  |  | 7,572 |  |  |  | 9 | %
SERC |  |  | 11 |  |  |  | 6,365 |  |  |  | 4 | %
MAIN |  |  | 5 |  |  |  | 2,292 |  |  |  | 3 | %
SPP |  |  | 3 |  |  |  | 1,674 |  |  |  | 4 | %
NEPOOL |  |  | 5 |  |  |  | 1,272 |  |  |  | 4 | %
FRCC |  |  | 3 |  |  |  | 875 |  |  |  | 2 | %
MAAC |  |  | 5 |  |  |  | 865 |  |  |  | 1 | %
ECAR |  |  | 1 |  |  |  | 700 |  |  |  | * |
MAPP |  |  | 1 |  |  |  | 375 |  |  |  | 1 | %
NYPOOL |  |  | 5 |  |  |  | 334 |  |  |  | 1 | %
NPCC |  |  | 1 |  |  |  | 7 |  |  |  | * |
TOTAL NERC |  |  | 101 |  |  |  | 30,713 |  |  |  | 3 | %
UK |  |  | 1 |  |  |  | 1,200 |  |  |  | 2 | %
Mexico |  |  | 1 |  |  |  | 236 |  |  |  | 1 | %
TOTAL |  |  | 103 |  |  |  | 32,149 |  |  |  | 3 | %

| * | less than 1%.

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##### Table of Contents

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.”

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

|  |  |  | Megawatts |
|  |  |  |  |  | Calpine Net |
|  |  |  |  |  | With |  |  | Calpine Net |  |  | Interest |
|  | Number |  |  | Baseload |  |  | Peaking |  |  | Interest |  |  | with |
|  | of Plants |  |  | Capacity |  |  | Capacity |  |  | Baseload |  |  | Peaking |
In operation |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Geothermal power plants |  |  | 19 |  |  |  | 750 |  |  |  | 750 |  |  |  | 750 |  |  |  | 750 |
| Gas-fired power plants |  |  | 73 |  |  |  | 21,930 |  |  |  | 27,189 |  |  |  | 20,753 |  |  |  | 25,899 |
Under construction |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| New facilities |  |  | 11 |  |  |  | 5,181 |  |  |  | 5,789 |  |  |  | 4,892 |  |  |  | 5,500 |
|  | Total |  |  | 103 |  |  |  | 27,861 |  |  |  | 33,728 |  |  |  | 26,395 |  |  |  | 32,149 |

Operating Power Plants

|  | Country, |  |  |  |  |  |  |  |  |  |  | Calpine Net |  |  |
|  | US |  |  |  |  | With |  |  |  |  | Calpine Net |  |  | Interest |  |  |
|  | State or |  |  | Baseload |  |  | Peaking |  |  | Calpine |  |  | Interest |  |  | with |  |  | Total 2004 |
|  | Can. |  |  | Capacity |  |  | Capacity |  |  | Interest |  |  | Baseload |  |  | Peaking |  |  | Generation |
Power Plant |  | Province |  |  | (MW) |  |  | (MW) |  |  | Percentage |  |  | (MW) |  |  | (MW) |  |  | MWh(1) |
Geothermal Power Plants |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sonoma County (12 plants) |  |  | CA |  |  |  | 456.0 |  |  |  | 456.0 |  |  |  | 100.0 | % |  |  | 456.0 |  |  |  | 456.0 |  |  |  | 4,135,181 |
Lake County (2 plants) |  |  | CA |  |  |  | 131.0 |  |  |  | 131.0 |  |  |  | 100.0 | % |  |  | 131.0 |  |  |  | 131.0 |  |  |  | 1,114,292 |
Calistoga |  |  | CA |  |  |  | 70.0 |  |  |  | 70.0 |  |  |  | 100.0 | % |  |  | 70.0 |  |  |  | 70.0 |  |  |  | 620,520 |
Sonoma |  |  | CA |  |  |  | 35.0 |  |  |  | 35.0 |  |  |  | 100.0 | % |  |  | 35.0 |  |  |  | 35.0 |  |  |  | 375,733 |
West Ford Flat |  |  | CA |  |  |  | 26.0 |  |  |  | 26.0 |  |  |  | 100.0 | % |  |  | 26.0 |  |  |  | 26.0 |  |  |  | 227,453 |
Bear Canyon |  |  | CA |  |  |  | 16.0 |  |  |  | 16.0 |  |  |  | 100.0 | % |  |  | 16.0 |  |  |  | 16.0 |  |  |  | 142,204 |
Aidlin |  |  | CA |  |  |  | 16.0 |  |  |  | 16.0 |  |  |  | 100.0 | % |  |  | 16.0 |  |  |  | 16.0 |  |  |  | 139,256 |
| Total Geothermal Power Plants (19) |  |  |  |  |  |  | 750.0 |  |  |  | 750.0 |  |  |  |  |  |  |  | 750.0 |  |  |  | 750.0 |  |  |  | 6,754,639 |
Gas-Fired Power Plants |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Saltend Energy Centre |  |  | UK |  |  |  | 1,200.0 |  |  |  | 1,200.0 |  |  |  | 100.0 | % |  |  | 1,200.0 |  |  |  | 1,200.0 |  |  |  | 9,008,046 |
Freestone Energy Center |  |  | TX |  |  |  | 1,022.0 |  |  |  | 1,022.0 |  |  |  | 100.0 | % |  |  | 1,022.0 |  |  |  | 1,022.0 |  |  |  | 4,569,089 |
Deer Park Energy Center |  |  | TX |  |  |  | 792.0 |  |  |  | 1,019.0 |  |  |  | 100.0 | % |  |  | 792.0 |  |  |  | 1,019.0 |  |  |  | 4,798,265 |
Oneta Energy Center |  |  | OK |  |  |  | 994.0 |  |  |  | 994.0 |  |  |  | 100.0 | % |  |  | 994.0 |  |  |  | 994.0 |  |  |  | 827,661 |
Delta Energy Center |  |  | CA |  |  |  | 799.0 |  |  |  | 882.0 |  |  |  | 100.0 | % |  |  | 799.0 |  |  |  | 882.0 |  |  |  | 5,765,080 |
Morgan Energy Center |  |  | AL |  |  |  | 722.0 |  |  |  | 852.0 |  |  |  | 100.0 | % |  |  | 722.0 |  |  |  | 852.0 |  |  |  | 848,933 |
Decatur Energy Center |  |  | AL |  |  |  | 793.0 |  |  |  | 852.0 |  |  |  | 100.0 | % |  |  | 793.0 |  |  |  | 852.0 |  |  |  | 311,531 |
Baytown Energy Center |  |  | TX |  |  |  | 742.0 |  |  |  | 830.0 |  |  |  | 100.0 | % |  |  | 742.0 |  |  |  | 830.0 |  |  |  | 4,632,478 |
Broad River Energy Center |  |  | SC |  |  |  | — |  |  |  | 847.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 847.0 |  |  |  | 426,705 |
Pasadena Power Plant |  |  | TX |  |  |  | 776.0 |  |  |  | 777.0 |  |  |  | 100.0 | % |  |  | 776.0 |  |  |  | 777.0 |  |  |  | 3,932,210 |
Magic Valley Generating Station |  |  | TX |  |  |  | 700.0 |  |  |  | 751.0 |  |  |  | 100.0 | % |  |  | 700.0 |  |  |  | 751.0 |  |  |  | 2,802,004 |
Hermiston Power Project |  |  | OR |  |  |  | 546.0 |  |  |  | 642.0 |  |  |  | 100.0 | % |  |  | 546.0 |  |  |  | 642.0 |  |  |  | 4,073,944 |
Columbia Energy Center |  |  | SC |  |  |  | 464.0 |  |  |  | 641.0 |  |  |  | 100.0 | % |  |  | 464.0 |  |  |  | 641.0 |  |  |  | 542,376 |
Rocky Mountain Energy Center |  |  | CO |  |  |  | 479.0 |  |  |  | 621.0 |  |  |  | 100.0 | % |  |  | 479.0 |  |  |  | 621.0 |  |  |  | 2,080,538 |
Osprey Energy Center |  |  | FL |  |  |  | 530.0 |  |  |  | 609.0 |  |  |  | 100.0 | % |  |  | 530.0 |  |  |  | 609.0 |  |  |  | 1,492,792 |
Acadia Energy Center |  |  | LA |  |  |  | 1,092.0 |  |  |  | 1,210.0 |  |  |  | 50.0 | % |  |  | 546.0 |  |  |  | 605.0 |  |  |  | 2,521,934 |
Riverside Energy Center |  |  | WI |  |  |  | 518.0 |  |  |  | 603.0 |  |  |  | 100.0 | % |  |  | 518.0 |  |  |  | 603.0 |  |  |  | 689,659 |

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##### Table of Contents

|  | Country, |  |  |  |  |  |  |  |  |  |  | Calpine Net |  |  |
|  | US |  |  |  |  | With |  |  |  |  | Calpine Net |  |  | Interest |  |  |
|  | State or |  |  | Baseload |  |  | Peaking |  |  | Calpine |  |  | Interest |  |  | with |  |  | Total 2004 |
|  | Can. |  |  | Capacity |  |  | Capacity |  |  | Interest |  |  | Baseload |  |  | Peaking |  |  | Generation |
Power Plant |  | Province |  |  | (MW) |  |  | (MW) |  |  | Percentage |  |  | (MW) |  |  | (MW) |  |  | MWh(1) |
Aries Power Project |  |  | MO |  |  |  | 523.0 |  |  |  | 590.0 |  |  |  | 100.0 | % |  |  | 523.0 |  |  |  | 590.0 |  |  |  | 839,176 |
Ontelaunee Energy Center |  |  | PA |  |  |  | 561.0 |  |  |  | 584.0 |  |  |  | 100.0 | % |  |  | 561.0 |  |  |  | 584.0 |  |  |  | 1,343,393 |
Channel Energy Center |  |  | TX |  |  |  | 527.0 |  |  |  | 574.0 |  |  |  | 100.0 | % |  |  | 527.0 |  |  |  | 574.0 |  |  |  | 3,467,759 |
Brazos Valley Power Plant |  |  | TX |  |  |  | 450.0 |  |  |  | 570.0 |  |  |  | 100.0 | % |  |  | 450.0 |  |  |  | 570.0 |  |  |  | 2,441,071 |
Los Medanos Energy Center |  |  | CA |  |  |  | 497.0 |  |  |  | 566.0 |  |  |  | 100.0 | % |  |  | 497.0 |  |  |  | 566.0 |  |  |  | 3,683,759 |
Sutter Energy Center |  |  | CA |  |  |  | 535.0 |  |  |  | 543.0 |  |  |  | 100.0 | % |  |  | 535.0 |  |  |  | 543.0 |  |  |  | 3,475,986 |
Corpus Christi Energy Center |  |  | TX |  |  |  | 414.0 |  |  |  | 537.0 |  |  |  | 100.0 | % |  |  | 414.0 |  |  |  | 537.0 |  |  |  | 2,297,928 |
Texas City Power Plant |  |  | TX |  |  |  | 457.0 |  |  |  | 534.0 |  |  |  | 100.0 | % |  |  | 457.0 |  |  |  | 534.0 |  |  |  | 2,389,041 |
Carville Energy Center |  |  | LA |  |  |  | 455.0 |  |  |  | 531.0 |  |  |  | 100.0 | % |  |  | 455.0 |  |  |  | 531.0 |  |  |  | 1,755,790 |
South Point Energy Center |  |  | AZ |  |  |  | 520.0 |  |  |  | 530.0 |  |  |  | 100.0 | % |  |  | 520.0 |  |  |  | 530.0 |  |  |  | 2,900,047 |
Westbrook Energy Center |  |  | ME |  |  |  | 528.0 |  |  |  | 528.0 |  |  |  | 100.0 | % |  |  | 528.0 |  |  |  | 528.0 |  |  |  | 3,451,414 |
Zion Energy Center |  |  | IL |  |  |  | — |  |  |  | 513.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 513.0 |  |  |  | 29,978 |
RockGen Energy Center |  |  | WI |  |  |  | — |  |  |  | 460.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 460.0 |  |  |  | 240,072 |
Clear Lake Power Plant |  |  | TX |  |  |  | 344.0 |  |  |  | 400.0 |  |  |  | 100.0 | % |  |  | 344.0 |  |  |  | 400.0 |  |  |  | 1,397,923 |
Hidalgo Energy Center |  |  | TX |  |  |  | 392.0 |  |  |  | 392.0 |  |  |  | 78.5 | % |  |  | 307.7 |  |  |  | 307.7 |  |  |  | 1,931,793 |
Blue Spruce Energy Center |  |  | CO |  |  |  | — |  |  |  | 285.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 285.0 |  |  |  | 149,316 |
Goldendale Energy Center |  |  | WA |  |  |  | 237.0 |  |  |  | 271.0 |  |  |  | 100.0 | % |  |  | 237.0 |  |  |  | 271.0 |  |  |  | 210,601 |
Tiverton Power Plant |  |  | RI |  |  |  | 267.0 |  |  |  | 267.0 |  |  |  | 100.0 | % |  |  | 267.0 |  |  |  | 267.0 |  |  |  | 1,860,478 |
Rumford Power Plant |  |  | ME |  |  |  | 263.0 |  |  |  | 263.0 |  |  |  | 100.0 | % |  |  | 263.0 |  |  |  | 263.0 |  |  |  | 1,664,835 |
Santa Rosa Energy Center |  |  | FL |  |  |  | 250.0 |  |  |  | 250.0 |  |  |  | 100.0 | % |  |  | 250.0 |  |  |  | 250.0 |  |  |  | 17,848 |
Hog Bayou Energy Center |  |  | AL |  |  |  | 235.0 |  |  |  | 237.0 |  |  |  | 100.0 | % |  |  | 235.0 |  |  |  | 237.0 |  |  |  | 120,000 |
Pine Bluff Energy Center |  |  | AR |  |  |  | 184.0 |  |  |  | 215.0 |  |  |  | 100.0 | % |  |  | 184.0 |  |  |  | 215.0 |  |  |  | 1,450,765 |
Los Esteros Critical Energy Center |  |  | CA |  |  |  | — |  |  |  | 188.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 188.0 |  |  |  | 278,873 |
Dighton Power Plant |  |  | MA |  |  |  | 170.0 |  |  |  | 170.0 |  |  |  | 100.0 | % |  |  | 170.0 |  |  |  | 170.0 |  |  |  | 639,784 |
Morris Power Plant |  |  | IL |  |  |  | 137.0 |  |  |  | 156.0 |  |  |  | 100.0 | % |  |  | 137.0 |  |  |  | 156.0 |  |  |  | 562,882 |
Auburndale Power Plant |  |  | FL |  |  |  | 150.0 |  |  |  | 150.0 |  |  |  | 100.0 | % |  |  | 150.0 |  |  |  | 150.0 |  |  |  | 901,206 |
Gilroy Peaking Energy Center |  |  | CA |  |  |  | — |  |  |  | 135.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 135.0 |  |  |  | 72,388 |
Gilroy Power Plant |  |  | CA |  |  |  | 117.0 |  |  |  | 128.0 |  |  |  | 100.0 | % |  |  | 117.0 |  |  |  | 128.0 |  |  |  | 274,311 |
King City Power Plant |  |  | CA |  |  |  | 120.0 |  |  |  | 120.0 |  |  |  | 100.0 | % |  |  | 120.0 |  |  |  | 120.0 |  |  |  | 952,050 |
Parlin Power Plant |  |  | NJ |  |  |  | 98.0 |  |  |  | 118.0 |  |  |  | 100.0 | % |  |  | 98.0 |  |  |  | 118.0 |  |  |  | 109,994 |
Auburndale Peaking Energy Center |  |  | FL |  |  |  | — |  |  |  | 116.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 116.0 |  |  |  | 9,495 |
Kennedy International Airport Power Plant (“KIAC”) |  |  | NY |  |  |  | 99.0 |  |  |  | 105.0 |  |  |  | 100.0 | % |  |  | 99.0 |  |  |  | 105.0 |  |  |  | 577,632 |
Pryor Power Plant |  |  | OK |  |  |  | 38.0 |  |  |  | 90.0 |  |  |  | 100.0 | % |  |  | 38.0 |  |  |  | 90.0 |  |  |  | 342,127 |
Grays Ferry Power Plant |  |  | PA |  |  |  | 166.0 |  |  |  | 175.0 |  |  |  | 50.0 | % |  |  | 83.0 |  |  |  | 87.5 |  |  |  | 618,319 |
Calgary Energy Centre |  |  | AB |  |  |  | 252.0 |  |  |  | 286.0 |  |  |  | 30.0 | % |  |  | 75.6 |  |  |  | 85.8 |  |  |  | 891,629 |
Island Cogeneration |  |  | BC |  |  |  | 219.0 |  |  |  | 250.0 |  |  |  | 30.0 | % |  |  | 65.7 |  |  |  | 75.0 |  |  |  | 1,663,518 |
Pittsburg Power Plant |  |  | CA |  |  |  | 64.0 |  |  |  | 64.0 |  |  |  | 100.0 | % |  |  | 64.0 |  |  |  | 64.0 |  |  |  | 211,005 |
Bethpage Power Plant |  |  | NY |  |  |  | 55.0 |  |  |  | 56.0 |  |  |  | 100.0 | % |  |  | 55.0 |  |  |  | 56.0 |  |  |  | 271,594 |
Newark Power Plant |  |  | NJ |  |  |  | 50.0 |  |  |  | 56.0 |  |  |  | 100.0 | % |  |  | 50.0 |  |  |  | 56.0 |  |  |  | 203,019 |
Greenleaf 1 Power Plant |  |  | CA |  |  |  | 49.5 |  |  |  | 49.5 |  |  |  | 100.0 | % |  |  | 49.5 |  |  |  | 49.5 |  |  |  | 341,427 |
Greenleaf 2 Power Plant |  |  | CA |  |  |  | 49.5 |  |  |  | 49.5 |  |  |  | 100.0 | % |  |  | 49.5 |  |  |  | 49.5 |  |  |  | 328,262 |

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|  | Country, |  |  |  |  |  |  |  |  |  |  | Calpine Net |  |  |
|  | US |  |  |  |  | With |  |  |  |  | Calpine Net |  |  | Interest |  |  |
|  | State or |  |  | Baseload |  |  | Peaking |  |  | Calpine |  |  | Interest |  |  | with |  |  | Total 2004 |
|  | Can. |  |  | Capacity |  |  | Capacity |  |  | Interest |  |  | Baseload |  |  | Peaking |  |  | Generation |
Power Plant |  | Province |  |  | (MW) |  |  | (MW) |  |  | Percentage |  |  | (MW) |  |  | (MW) |  |  | MWh(1) |
Wolfskill Energy Center |  |  | CA |  |  |  | — |  |  |  | 48.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 48.0 |  |  |  | 21,900 |
Yuba City Energy Center |  |  | CA |  |  |  | — |  |  |  | 47.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 47.0 |  |  |  | 18,558 |
Feather River Energy Center |  |  | CA |  |  |  | — |  |  |  | 47.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 47.0 |  |  |  | 17,034 |
Creed Energy Center |  |  | CA |  |  |  | — |  |  |  | 47.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 47.0 |  |  |  | 10,483 |
Lambie Energy Center |  |  | CA |  |  |  | — |  |  |  | 47.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 47.0 |  |  |  | 16,156 |
Goose Haven Energy Center |  |  | CA |  |  |  | — |  |  |  | 47.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 47.0 |  |  |  | 11,193 |
Riverview Energy Center |  |  | CA |  |  |  | — |  |  |  | 47.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 47.0 |  |  |  | 17,637 |
Stony Brook Power Plant |  |  | NY |  |  |  | 45.0 |  |  |  | 47.0 |  |  |  | 100.0 | % |  |  | 45.0 |  |  |  | 47.0 |  |  |  | 329,168 |
Bethpage Peaking Energy Center |  |  | NY |  |  |  | — |  |  |  | 46.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 46.0 |  |  |  | 112,033 |
King City Peaking Energy Center |  |  | CA |  |  |  | — |  |  |  | 45.0 |  |  |  | 100.0 | % |  |  | — |  |  |  | 45.0 |  |  |  | 21,545 |
Androscoggin Energy Center |  |  | ME |  |  |  | 136.0 |  |  |  | 136.0 |  |  |  | 32.3 | % |  |  | 44.0 |  |  |  | 44.0 |  |  |  | 680,898 |
Watsonville Power Plant |  |  | CA |  |  |  | 29.0 |  |  |  | 30.0 |  |  |  | 100.0 | % |  |  | 29.0 |  |  |  | 30.0 |  |  |  | 206,244 |
Agnews Power Plant |  |  | CA |  |  |  | 28.0 |  |  |  | 28.0 |  |  |  | 100.0 | % |  |  | 28.0 |  |  |  | 28.0 |  |  |  | 197,810 |
Philadelphia Water Project |  |  | PA |  |  |  | — |  |  |  | 23.0 |  |  |  | 83.0 | % |  |  | — |  |  |  | 19.1 |  |  |  | — |
Whitby Cogeneration |  |  | ON |  |  |  | 50.0 |  |  |  | 50.0 |  |  |  | 15.0 | % |  |  | 7.5 |  |  |  | 7.5 |  |  |  | — |
| Total Gas-Fired Power Plants(73) |  |  |  |  |  |  | 21,930.0 |  |  |  | 27,189.0 |  |  |  |  |  |  |  | 20,753.0 |  |  |  | 25,899.0 |  |  |  | 97,371,392 |
| Total Operating Power Plants(92) |  |  |  |  |  |  | 22,680.0 |  |  |  | 27,939.0 |  |  |  |  |  |  |  | 21,503.0 |  |  |  | 26,649.0 |  |  |  | 104,126,031 |
Consolidated Projects including plants with operating leases |  |  |  |  |  |  | 21,236.0 |  |  |  | 26,368.0 |  |  |  |  |  |  |  | 20,822.0 |  |  |  | 25,905.0 |  |  |  |  |
Equity (Unconsolidated) Projects |  |  |  |  |  |  | 1,444.0 |  |  |  | 1,571.0 |  |  |  |  |  |  |  | 681.0 |  |  |  | 744.0 |  |  |  |  |

(1) | Generation MWh is shown here as 100% of each plant’s gross generation in MWh.

Projects Under Construction (All gas-fired)

|  |  |  |  |  |  |  |  |  |  |  | Calpine Net |
|  |  |  |  |  | With |  |  |  |  | Calpine Net |  |  | Interest |
|  |  |  | Baseload |  |  | Peaking |  |  | Calpine |  |  | Interest |  |  | With |
|  |  |  | Capacity |  |  | Capacity |  |  | Interest |  |  | Baseload |  |  | Peaking |
Power Plant |  | US State |  |  | (MW) |  |  | (MW) |  |  | Percentage |  |  | (MW) |  |  | (MW) |
Projects Under Construction |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Hillabee Energy Center |  |  | AL |  |  |  | 710.0 |  |  |  | 770.0 |  |  |  | 100.0 | % |  |  | 710.0 |  |  |  | 770.0 |
Pastoria Energy Center |  |  | CA |  |  |  | 759.0 |  |  |  | 769.0 |  |  |  | 100.0 | % |  |  | 759.0 |  |  |  | 769.0 |
Fremont Energy Center |  |  | OH |  |  |  | 550.0 |  |  |  | 700.0 |  |  |  | 100.0 | % |  |  | 550.0 |  |  |  | 700.0 |
Metcalf Energy Center |  |  | CA |  |  |  | 556.0 |  |  |  | 602.0 |  |  |  | 100.0 | % |  |  | 556.0 |  |  |  | 602.0 |
Otay Mesa Energy Center |  |  | CA |  |  |  | 510.0 |  |  |  | 593.0 |  |  |  | 100.0 | % |  |  | 510.0 |  |  |  | 593.0 |
Washington Parish Energy Center |  |  | LA |  |  |  | 509.0 |  |  |  | 565.0 |  |  |  | 100.0 | % |  |  | 509.0 |  |  |  | 565.0 |
Fox Energy Center |  |  | WI |  |  |  | 490.0 |  |  |  | 560.0 |  |  |  | 100.0 | % |  |  | 490.0 |  |  |  | 560.0 |
Mankato Power Plant |  |  | MN |  |  |  | 292.0 |  |  |  | 375.0 |  |  |  | 100.0 | % |  |  | 292.0 |  |  |  | 375.0 |
Freeport Energy Center |  |  | TX |  |  |  | 200.0 |  |  |  | 250.0 |  |  |  | 100.0 | % |  |  | 200.0 |  |  |  | 250.0 |
Valladolid III Energy Center |  |  | Mexico |  |  |  | 525.0 |  |  |  | 525.0 |  |  |  | 45.0 | % |  |  | 236.3 |  |  |  | 236.3 |
Bethpage Energy Center 3 |  |  | NY |  |  |  | 79.9 |  |  |  | 79.9 |  |  |  | 100.0 | % |  |  | 79.9 |  |  |  | 79.9 |
| Total Projects Under Construction |  |  |  |  |  |  | 5,180.9 |  |  |  | 5,788.9 |  |  |  |  |  |  |  | 4,892.2 |  |  |  | 5,500.2 |

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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.

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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

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(“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

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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

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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

| PURPA

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

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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

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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

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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

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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.

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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

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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:

| • | limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our growth strategy, or other purposes;
| • | limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt;
| • | increasing our vulnerability to general adverse economic and industry conditions;
| • | limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in government regulation;
| • | limiting our ability or increasing the costs to refinance indebtedness; and
| • | limiting our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can transact as well as the volume of those transactions.

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:

| • | incur additional indebtedness and issue preferred stock;
| • | make prepayments on or purchase indebtedness in whole or in part;
| • | pay dividends and other distributions with respect to our capital stock or repurchase our capital stock or make other restricted payments;
| • | make certain investments;
| • | enter into transactions with affiliates;
| • | create or incur liens to secure debt;
| • | consolidate or merge with another entity, or allow one of our subsidiaries to do so;
| • | lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;

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| • | incur dividend or other payment restrictions affecting certain subsidiaries;
| • | make capital expenditures;
| • | engage in certain business activities; and
| • | acquire facilities or other businesses.

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

| • | Certain of our indentures place conditions on our ability to issue indebtedness if our interest coverage ratio (as defined in those indentures) is below 2:1. Currently, our interest coverage ratio (as so defined) is below 2:1 and, consequently, we generally would not be allowed to issue new debt, except for (i) certain types of new indebtedness that refinances or replaces existing indebtedness, and (ii) non-recourse debt and preferred equity interests issued by our subsidiaries for purposes of financing certain types of capital expenditures, including plant development, construction and acquisition expenses. In addition, if and so long as our interest coverage ratio is below 2:1, our ability to invest in unrestricted subsidiaries and non-subsidiary affiliates and make certain other types of restricted payments will be limited. Moreover, certain of our indentures will prohibit any further investments in non-subsidiary affiliates if and for so long as our interest coverage ratio (as defined therein) is below 1.75:1 and, as of December 31, 2004, such interest coverage ratio had fallen below 1.75:1.
| • | Certain of our indebtedness issued in the last half of 2004 was permitted under our indentures on the basis that the proceeds would be used to repurchase or redeem existing indebtedness. While we completed a portion of such repurchases during the fourth quarter of 2004 and the first quarter of 2005, we are still in the process of completing the required amount of repurchases. While the amount of indebtedness that must still be repurchased will ultimately depend on the market price of our outstanding indebtedness at the time the indebtedness is repurchased, based on current market conditions, we currently anticipate that we will spend up to approximately $202.9 million on additional repurchases in order to fully satisfy this requirement. Our bond purchase requirement was estimated to be approximately $270 million as of December 31, 2004, and this amount has been classified as a current liability on our consolidated balance sheet.
| • | When we or one of our subsidiaries sells a significant asset or issues preferred equity, our indentures generally require that the net proceeds of the transaction be used to make capital expenditures or to repurchase or repay certain types of subsidiary indebtedness, in each case within 365 days of the closing date of the transaction. In light of this requirement, and taking into account the amount of capital expenditures currently budgeted for 2005, we anticipate that we will need to use approximately $250.0 million of the net proceeds of the $360.0 million Two-Year Redeemable Preferred Shares issued on October 26, 2004 and approximately $200.0 million of the net proceeds of the $260.0 million Redeemable Preferred Shares issued on January 31, 2005, to repurchase or repay certain subsidiary indebtedness. The $250.0 million has been classified as a current liability on our consolidated balance sheet as of December 31, 2004. The actual amount of the net proceeds that will be required to be used to repurchase or repay subsidiary debt will depend upon the actual amount of the net proceeds that is used to make capital expenditures, which may be more or less than the amount currently budgeted.

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

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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

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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:

| • | general economic and capital market conditions;
| • | conditions in energy markets;
| • | regulatory developments;
| • | credit availability from banks or other lenders for us and our industry peers, as well as the economy in general;
| • | investor confidence in the industry and in us;
| • | the continued success of our current power generation facilities; and
| • | provisions of tax and securities laws that are conducive to raising capital.

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

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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.

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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

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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

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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:

| • | necessary power generation equipment;
| • | governmental permits and approvals;
| • | fuel supply and transportation agreements;
| • | sufficient equity capital and debt financing;
| • | electrical transmission agreements;
| • | water supply and wastewater discharge agreements; and
| • | site agreements and construction contracts.

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

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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:

| • | start-up problems;
| • | the breakdown or failure of equipment or processes; and
| • | performance below expected levels of output or efficiency.

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:

| • | the cessation or abandonment of the development, construction, maintenance or operation of the facility;
| • | failure of the facility to achieve construction milestones by agreed upon deadlines, subject to extensions due to force majeure events;
| • | failure of the facility to achieve commercial operation by agreed upon deadlines, subject to extensions due to force majeure events;
| • | failure of the facility to achieve certain output minimums;
| • | failure by the facility to make any of the payments owing to the utility under the PSA or to establish, maintain, restore, extend the term of, or increase the posted security if required by the PSA;
| • | a material breach of a representation or warranty or failure by the facility to observe, comply with or perform any other material obligation under the PSA;
| • | failure of the facility to obtain material permits and regulatory approvals by agreed upon deadlines; or
| • | the liquidation, dissolution, insolvency or bankruptcy of the project entity.

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.

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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:

| • | the heat content of the extractable steam or fluids;
| • | the geology of the reservoir;
| • | the total amount of recoverable reserves;
| • | operating expenses relating to the extraction of steam or fluids;
| • | price levels relating to the extraction of steam or fluids or power generated; and
| • | capital expenditure requirements relating primarily to the drilling of new wells.

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.

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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:

| • | fluctuations in currency valuation;
| • | currency inconvertibility;
| • | expropriation and confiscatory taxation;
| • | increased regulation; and
| • | approval requirements and governmental policies limiting returns to foreign investors.

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

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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

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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

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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

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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:

| • | seasonal variations in energy prices;
| • | variations in levels of production;
| • | the timing and size of acquisitions; and
| • | the completion of development and construction projects.

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:

| • | general conditions in our industry, the power markets in which we participate, or the worldwide economy;
| • | announcements of developments related to our business or sector;
| • | fluctuations in our results of operations;
| • | our debt-to-equity ratios and other leverage ratios;
| • | effects of significant events relating to the energy sector in general;

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| • | issuances, including though sales or lending facilities, of substantial amounts of our common stock or other securities into the marketplace;
| • | dilution or potential dilution caused by stock-for-debt exchanges or issuances of indebtedness convertible into our common stock, including any exchanges or convertible debt transactions relating to the outstanding HIGH TIDES III;
| • | an outbreak of war or hostilities;
| • | a shortfall in revenues or earnings compared to securities analysts’ expectations;
| • | changes in analysts’ recommendations or projections; and
| • | announcements of new acquisitions or development projects by us.

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.

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SUMMARY OF KEY ACTIVITIES

| Summary of Key Activities

| Finance — New Issuances and Amendments:

Date |  |  | Amount |  |  | Description
| 1/9/04 |  |  | $ | 250.0 million |  |  | An initial purchaser of the 4.75% Convertible Senior Notes due 2023 exercises in full its purchase option
| 2/20/04 |  |  | $ | 250.0 million |  |  | Complete a non-recourse project financing for Rocky Mountain Energy Center at a rate of LIBOR plus 250 basis points, refinanced in June 2004
| 3/23/04 |  |  | $ | 2.6 billion |  |  | CalGen completes its offering of secured institutional term loans, notes and revolving credit facility
| 4/26/04 |  |  |  |  |  |  | Successfully complete consent solicitation to effect certain amendments to the Indentures governing the Senior Notes issued between 1996 and 1999
| 6/2/04 |  |  | $ | 85.0 million |  |  | Power Contract Financing III, LLC issues zero coupon notes
| 6/29/04 |  |  | $ | 661.5 million |  |  | Rocky Mountain Energy Center, LLC, and Riverside Energy Center, LLC, close an offering of First Priority Secured Floating Rate Term Loans Due 2011 and a letter of credit-linked deposit facility
| 8/5/04 |  |  | $ | 250.0 million |  |  | Calpine Energy Management, L.P. enters into a letter of credit facility with Deutsche Bank that expires October 2005
| 9/30/04 |  |  | $ | 785.0 million |  |  | Receive funding on offering of 95/8% First Priority Senior Secured Notes due 2014, offered at 99.212% of par
| 9/30/04 |  |  | $ | 736.0 million |  |  | Receive funding on offering of Contingent Convertible Notes due 2014 offered at 83.9% of par
| 9/30/04 |  |  |  |  |  |  | Enter into a ten-year Share Lending Agreement, loaning 89 million shares of newly issued Calpine common stock to Deutsche Bank AG London in connection with the issuance of the Contingent Convertible Notes due 2014
| 9/30/04 |  |  | $ | 255.0 million |  |  | Establish a new Cash Collateralized Letter of Credit Facility with Bayerische Landesbank
| 10/26/04 |  |  | $ | 360.0 million |  |  | Calpine (Jersey) Limited completes an offering of Two-Year Redeemable Preferred Shares priced at 3-month US LIBOR plus 700 basis points

| Finance — Repurchases and Extinguishments:

Date |  |  | Amount |  |  | Description
| 5/04 |  |  | $ | 78.8 million |  |  | Retirement of Newark and Parlin Power Plants project financing
| 5/04 |  |  | $ | 82.0 million |  |  | Redemption of King City preferred interest due to lease restructuring
| 9/04 |  |  | $ | 266.2 million |  |  | Repurchase $266.2 million in principal amount of outstanding 4.75% Convertible Senior Notes due 2023 in exchange for $177.0 million in cash
| 9/04 |  |  | $ | 115.0 million |  |  | Repurchase $115.0 million par value of HIGH TIDES III for $111.6 million in cash
| 9/04 |  |  | $ | 199.5 million |  |  | Mandatory paydown of 51/8% First Priority Senior Secured Term Loan B due 2007 pursuant to debt covenants governing asset sales of natural gas reserves
| 9/04 |  |  | $ | 100.0 million |  |  | Mandatory paydown of 55/8% First Priority Letter of Credit Facility pursuant to covenants governing asset sales of natural gas reserves
| 10/04 |  |  | $ | 276.0 million |  |  | Redeem outstanding 53/4% HIGH TIDES I preferred securities
| 10/04 |  |  | $ | 360.0 million |  |  | Redeem outstanding 51/2% HIGH TIDES II preferred securities
| 4/04-7/04 |  |  | $ | 95.0 million |  |  | Exchange 24.3 million Calpine common shares in privately negotiated transactions for approximately $40.0 million par value of HIGH TIDES I and approximately $75.0 million par value of HIGH TIDES II
| 1/04-12/04 |  |  | $ | 658.7 million |  |  | Repurchase $658.7 million in principal amount of outstanding 2006 Convertible Senior Notes for $657.7 million in cash
| 1/04-12/04 |  |  |  | $743.4 million |  |  | Repurchase $743.4 million in principal of amount various Senior Notes issuances for $559.3 million in cash

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| Asset Sales and Other:

Date |  |  | Description
| 1/04 |  |  | Complete sale of 50% interest in Lost Pines 1 Power Project for a cash payment of $148.6 million
| 2/04 |  |  | Close on the sale of natural gas properties to CNGT for a net cash payment of Cdn$33.8 million (US$29.2 million)
| 2/04 |  |  | Enter into a one-year agreement with Cleco Power LLC to supply up to 500 MW of electricity
| 2/04 |  |  | Enter into five power sales contracts to supply approximately 350 MW of electricity to five New England- based electric distribution companies for delivery in 2004
| 3/04 |  |  | Enter into a 20-year purchase power agreement to provide 365 MW of electricity to Northern States Power
| 3/04 |  |  | Acquire the remaining 50% interest in the Aries Power Plant from Aquila, Inc.
| 3/04 |  |  | Complete the acquisition of the remaining 20% interest in Calpine Cogeneration Company for approximately $2.5 million
| 3/04 |  |  | Enter into a three-year power sales agreement with Safeway Inc. to supply up to 200 MW of electricity to Safeway facilities throughout California
| 3/04 |  |  | Close on the purchase of Brazos Valley Power Plant for approximately $181.1 million in a tax deferred like-kind exchange under IRS Section 1031, largely with the proceeds of the Lost Pines I Power Project sale
| 5/04 |  |  | Restructure King City lease
| 5/04 |  |  | Sign a 25-year agreement to sell up to 200 MW of electricity and 1 million pounds per hour of steam to The Dow Chemical Company
| 5/04 |  |  | Existing JCPL tolling arrangements with the Newark and Parlin Power Plants are terminated, resulting in a gain of $100.6 million before transaction costs
| 5/04 |  |  | Sell Utility Contract Funding II, a wholly-owned subsidiary of CES, which had entered into a long-term power purchase agreement related to Newark and Parlin Power Plants, for a pre-tax gain of $85.4 million before transaction costs
| 6/04 |  |  | Receive approval from the CPUC for a tolling agreement with San Diego Gas and Electric Company that provides for the delivery of up to 615 MW of capacity for ten years beginning in 2008
| 6/04 |  |  | Partially terminate the gas contract between Citrus Trading Corp. and the Auburndale facility for a net gain of $11.7 million
| 7/04 |  |  | Enter into a five and a half year agreement with Snapping Shoals EMC for 200 MW of capacity and electricity
| 7/04 |  |  | Announce the amendment of an eleven-year tolling agreement with Wisconsin Public Service for up to 500 MW of capacity, electricity and ancillary services, subject to approval by the Public Service Commission of Wisconsin
| 9/04 |  |  | Complete sale of natural gas reserves in Colorado Piceance Basin and New Mexico San Juan Basin for net cash payments of approximately $218.7 million
| 9/04 |  |  | Complete sale of all Canadian natural gas reserves and petroleum assets and interest in CNGT for cash payments of approximately Cdn$808.1 million (US$626.4 million)
| 10/04 |  |  | Announce energy service agreement with Newmarket Services Company, LLC
| 11/04 |  |  | Sign a letter of intent with GE Energy for joint construction of the world’s first power plant based on the 60-hertz version of GE’s most advanced gas turbine technology, the H Systemtm
| 11/04 |  |  | Announce CPSI awarded contract to operate and maintain two Hoosier Energy natural gas-fired power plants
| 12/04 |  |  | Announce two-year power sales contract with National Aeronautics and Space Administration Johnson Space Center in Houston, Texas, for an estimated peak load of up to 23 MW a day of electricity

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| Power Plant Development and Construction:

Date |  |  | Project |  | Description |
| 1/04 |  |  | Morgan Energy Center Expansion |  |  | Commercial operation |
| 5/04 |  |  | Osprey Energy Center |  |  | Commercial operation |
| 5/04 |  |  | Columbia Energy Center |  |  | Commercial operation |
| 5/04 |  |  | Rocky Mountain Energy Center |  |  | Commercial operation |
| 5/04 |  |  | Valladolid III IP |  |  | Construction began |
| 6/04 |  |  | Riverside Energy Center |  |  | Commercial operation |
| 6/04 |  |  | Deer Park Energy Center Expansion |  |  | Commercial operation |
| 6/04 |  |  | Freeport Energy Center |  |  | Construction began |
| 9/04 |  |  | Goldendale Energy Center |  |  | Commercial operation |

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

| Annual Meeting of Stockholders on May 26, 2004

| Stockholders’ Voting Results

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

| • | Proposal to amend the Company’s Amended and Restated Certificate of Incorporation to increase the number of authorized shares of Common Stock — approved
| • | Proposal to amend the Company’s 1996 Stock Incentive Plan to increase the number of shares of the Company’s Common Stock available for grants of options and other stock-based awards under such plan — approved
| • | Proposal to amend the Company’s 2000 Employee Stock Purchase Plan to increase the number of shares of the Company’s Common Stock available for grants of purchase rights under such plan — approved
| • | Proposal that the Company cease and desist geothermal development activities in the Medicine Lake Highlands and requesting the Company to adopt an indigenous peoples policy — rejected
| • | Proposal that the Company’s Compensation Committee of its Board of Directors utilize performance and time-based restricted share programs in lieu of stock options in developing future senior executive equity compensation plans — rejected
| • | Proposal requesting the Company’s Board of Directors to study and report on the feasibility of enabling stockholders to imitate the voting decisions of an institutional investor — rejected
| • | Ratification of the appointment of PricewaterhouseCoopers LLP as independent registered public accounting firm for the fiscal year ending December 31, 2004 — approved

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.

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Item 2. | Properties

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:

|  | As of December 31, 2004 |
|  | Oil and NGLs |  |  |
|  | (MMBbls) |  |  | Gas (Bcf) |
United States |  |  |  |  |  |  |  |
Proved developed |  |  | 1.4 |  |  |  | 255 |
Proved undeveloped |  |  | 1.2 |  |  |  | 118 |
| Total |  |  | 2.6 | (1) |  |  | 373 |

(1) | 2.6 MMBbls of oil is equivalent to 15.6 Bcf of gas using a conversion factor of six thousand cubic feet of gas to one barrel of crude oil and natural gas liquids. On an equivalent basis, proved reserves at year-end totaled 389 Bcfe.

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.

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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.

|  |  |  |  |  | Productive |
|  | Undeveloped Acres |  |  | Developed Acres |  |  | Wells |
|  | Gross |  |  | Net |  |  | Gross |  |  | Net |  |  | Gross |  |  | Net |
United States |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Arkansas |  |  | 80 |  |  |  | 80 |  |  |  | 3,759 |  |  |  | 1,555 |  |  |  | 32 |  |  |  | 15 |
California |  |  | 14,321 |  |  |  | 13,158 |  |  |  | 49,745 |  |  |  | 40,495 |  |  |  | 167 |  |  |  | 139 |
Colorado |  |  | 22,193 |  |  |  | 19,665 |  |  |  | 640 |  |  |  | 640 |  |  |  | 1 |  |  |  | 1 |
Kansas(1) |  |  | 94,746 |  |  |  | 93,809 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Louisiana |  |  | 2,998 |  |  |  | 647 |  |  |  | 9,023 |  |  |  | 1,947 |  |  |  | 27 |  |  |  | 5 |
Mississippi |  |  | 4,645 |  |  |  | 874 |  |  |  | 12,842 |  |  |  | 2,416 |  |  |  | 13 |  |  |  | 3 |
Missouri(1) |  |  | 23,848 |  |  |  | 21,892 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Montana |  |  | 37,260 |  |  |  | 35,377 |  |  |  | 960 |  |  |  | 240 |  |  |  | 2 |  |  |  | 1 |
Offshore |  |  | 5,000 |  |  |  | 5,000 |  |  |  | 23,260 |  |  |  | 16,141 |  |  |  | 34 |  |  |  | 24 |
Oklahoma |  |  | 185 |  |  |  | 52 |  |  |  | 9,321 |  |  |  | 2,625 |  |  |  | 43 |  |  |  | 12 |
Texas |  |  | 40,620 |  |  |  | 21,130 |  |  |  | 99,606 |  |  |  | 51,813 |  |  |  | 601 |  |  |  | 299 |
Utah |  |  | 315 |  |  |  | 315 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Wyoming |  |  | 50,430 |  |  |  | 50,430 |  |  |  | 600 |  |  |  | 2 |  |  |  | — |  |  |  | — |
Total United States |  |  | 296,641 |  |  |  | 262,429 |  |  |  | 209,756 |  |  |  | 117,874 |  |  |  | 920 |  |  |  | 499 |

(1) | Company has determined that it will not develop the acreage reflected and shall let such expire per lease terms. Acreage was fully impaired for accounting purposes.

The following table shows our interest in undeveloped acreage as of December 31, 2004 which is subject to expiration in 2005, 2006 and 2007.

|  | 2005 |  |  | 2006 |  |  | 2007 |  |  | Thereafter |
|  | Gross |  |  | Net |  |  | Gross |  |  | Net |  |  | Gross |  |  | Net |  |  | Gross |  |  | Net |
United States |  |  | 36,921 |  |  |  | 28,215 |  |  |  | 29,721 |  |  |  | 27,494 |  |  |  | 114,537 |  |  |  | 111,695 |  |  |  | 115,462 |  |  |  | 95,025 |

The following table sets forth the number of gross exploratory and gross development wells drilled in which we participated during the last three fiscal years. The number of wells drilled refers to the number of wells commenced at any time during the respective fiscal year. Productive wells are either producing wells or wells capable of commercial production. At December 31, 2004, we were in the process of drilling 4 wells (net 1.8).

|  | Exploratory |  |  | Development |
|  | Productive |  |  | Dry |  |  | Total |  |  | Productive |  |  | Dry |  |  | Total |
2004 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States |  |  | 8 |  |  |  | 2 |  |  |  | 10 |  |  |  | 40 |  |  |  | 2 |  |  |  | 42 |
Canada |  |  | 13 |  |  |  | 1 |  |  |  | 14 |  |  |  | 31 |  |  |  | 2 |  |  |  | 33 |
| Total |  |  | 21 |  |  |  | 3 |  |  |  | 24 |  |  |  | 71 |  |  |  | 4 |  |  |  | 75 |
2003 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States |  |  | 17 |  |  |  | 8 |  |  |  | 25 |  |  |  | 20 |  |  |  | 5 |  |  |  | 25 |
Canada |  |  | 1 |  |  |  | 2 |  |  |  | 3 |  |  |  | 158 |  |  |  | 3 |  |  |  | 161 |
| Total |  |  | 18 |  |  |  | 10 |  |  |  | 28 |  |  |  | 178 |  |  |  | 8 |  |  |  | 186 |
2002 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States |  |  | — |  |  |  | 6 |  |  |  | 6 |  |  |  | 41 |  |  |  | 4 |  |  |  | 45 |
Canada |  |  | 1 |  |  |  | 1 |  |  |  | 2 |  |  |  | 87 |  |  |  | 8 |  |  |  | 95 |
| Total |  |  | 1 |  |  |  | 7 |  |  |  | 8 |  |  |  | 128 |  |  |  | 12 |  |  |  | 140 |

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##### Table of Contents

The following table sets forth, for each of the last three fiscal years, the number of net exploratory and net development wells, drilled by us based on our proportionate working interest in such wells:

|  | Exploratory |  |  | Development |
|  | Productive |  |  | Dry |  |  | Total |  |  | Productive |  |  | Dry |  |  | Total |
2004 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States |  |  | 4.3 |  |  |  | 1.0 |  |  |  | 5.3 |  |  |  | 21.1 |  |  |  | 2.0 |  |  |  | 23.1 |
Canada |  |  | 8.7 |  |  |  | 0.5 |  |  |  | 9.2 |  |  |  | 14.7 |  |  |  | 1.5 |  |  |  | 16.2 |
| Total |  |  | 13.0 |  |  |  | 1.5 |  |  |  | 14.5 |  |  |  | 35.8 |  |  |  | 3.5 |  |  |  | 39.3 |
2003 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States |  |  | 14.0 |  |  |  | 4.5 |  |  |  | 18.5 |  |  |  | 18.5 |  |  |  | 3.4 |  |  |  | 21.9 |
Canada |  |  | 0.3 |  |  |  | 0.7 |  |  |  | 1.0 |  |  |  | 42.5 |  |  |  | 1.0 |  |  |  | 43.5 |
| Total |  |  | 14.3 |  |  |  | 5.2 |  |  |  | 19.5 |  |  |  | 61.0 |  |  |  | 4.4 |  |  |  | 65.4 |
2002 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
United States |  |  | — |  |  |  | 3.9 |  |  |  | 3.9 |  |  |  | 36.4 |  |  |  | 2.8 |  |  |  | 39.2 |
Canada |  |  | 0.5 |  |  |  | 0.5 |  |  |  | 1.0 |  |  |  | 38.9 |  |  |  | 4.2 |  |  |  | 43.1 |
| Total |  |  | 0.5 |  |  |  | 4.4 |  |  |  | 4.9 |  |  |  | 75.3 |  |  |  | 7.0 |  |  |  | 82.3 |

The following table shows our annual average wellhead sales prices and average production costs. The average sales prices with hedges include realized gains and losses for derivative contracts we enter into with non-affiliates to manage price risk related to our sales volumes. During 2004, all Canadian properties were divested and such operations were reclassed to discontinued operation. Thus, the majority of the following information primarily reflects United States activity.

|  | With Hedges |  |  | Without Hedges |
|  | 2004 |  |  | 2003 |  |  | 2002 |  |  | 2004 |  |  | 2003 |  |  | 2002 |
NORTH AMERICA |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Sales price |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Natural gas (per Mcf)(1) |  | $ | 6.02 |  |  | $ | 5.33 |  |  | $ | 2.78 |  |  | $ | 6.02 |  |  | $ | 5.33 |  |  | $ | 2.82 |
|  | Oil and condensate (per barrel) |  | $ | 39.08 |  |  | $ | 35.06 |  |  | $ | 51.22 |  |  | $ | 39.08 |  |  | $ | 35.06 |  |  | $ | 50.98 |
| Lease operating cost (per Mcfe)(2) |  | $ | 1.03 |  |  | $ | 0.78 |  |  | $ | 0.73 |  |  | $ | 1.03 |  |  | $ | 0.78 |  |  | $ | 0.73 |
| Production taxes (per Mcfe) |  | $ | 0.11 |  |  | $ | 0.06 |  |  | $ | 0.05 |  |  | $ | 0.11 |  |  | $ | 0.06 |  |  | $ | 0.05 |
| Total production cost (per Mcfe)(3) |  | $ | 1.14 |  |  | $ | 0.84 |  |  | $ | 0.78 |  |  | $ | 1.14 |  |  | $ | 0.84 |  |  | $ | 0.78 |

(1) | Thousand cubic feet.
(2) | Includes lifting costs, treating and transportation and workover costs.
(3) | Thousand cubic feet equivalent.

Item 3. | Legal Proceedings

See Note 25 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.

Item 4. | Submission of Matters to a Vote of Security Holders

None.

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PART II

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

Our common stock is traded on The New York Stock Exchange under the symbol “CPN.” Public trading of our common stock commenced on September 20, 1996. Prior to that, there was no public market for our common stock. The following table sets forth, for the periods indicated, the high and low sale price per share of our common stock on The New York Stock Exchange:

|  | High |  |  | Low |
2004 |  |  |  |  |  |  |  |
First Quarter |  | $ | 6.42 |  |  | $ | 4.35 |
Second Quarter |  |  | 4.98 |  |  |  | 3.04 |
Third Quarter |  |  | 4.46 |  |  |  | 2.87 |
Fourth Quarter |  |  | 4.08 |  |  |  | 2.24 |
2003 |  |  |  |  |  |  |  |
First Quarter |  | $ | 4.42 |  |  | $ | 2.51 |
Second Quarter |  |  | 7.25 |  |  |  | 3.33 |
Third Quarter |  |  | 8.03 |  |  |  | 4.76 |
Fourth Quarter |  |  | 5.25 |  |  |  | 3.28 |

As of March 30, 2005, there were approximately 2,380 holders of record of our common stock. On March 30, 2005, the last sale price reported on The New York Stock Exchange for our common stock was $2.64 per share.
We have not declared any cash dividends on our common stock during the past two fiscal years. We do not anticipate paying any cash dividends on our common stock in the foreseeable future because we intend to retain our earnings to finance the expansion of our business, to repay debt, and for general corporate purposes. In addition, our ability to pay cash dividends is restricted under certain of our indentures and our other debt agreements. Future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual restrictions and such other factors as the board of directors may deem relevant.
Security Repurchases
On October 20, 2004, Calpine Capital Trust (“Trust I”) and Calpine Capital Trust II (“Trust II”), respectively, redeemed all of the $636.0 million in aggregate principal amount outstanding of their HIGH TIDES I and HIGH TIDES II (which were exchangeable for Calpine common stock), and $19.7 million of their mandatorily redeemable common securities, upon our redemption of all of the related underlying debentures (which were convertible into Calpine common stock), for a total of $655.7 million plus accrued interest of $8.1 million; such redemption payment was immediately applied to redeem the HIGH TIDES I, HIGH TIDES II and common securities. In addition, on December 27, 2004, we repurchased $70.8 million in principle amount of our 2006 Convertible Senior Notes for $70.8 million plus accrued interest of $1.4 million.
The following table sets forth the total units of HIGH TIDES and 2006 Convertible Senior Notes we purchased in the fourth quarter of 2004.

|  |  |  |  |  | Total Number |  |  | Maximum |
|  |  |  |  |  | of Units/Notes |  |  | Number of |
|  |  |  |  |  | Purchased as |  |  | Units/Notes |
|  |  |  |  |  | Part of Publicly |  |  | that may yet be |
|  | Total Number of |  |  |  |  | Announced |  |  | Purchased |
|  | Units/Notes |  |  | Price Paid per |  |  | Plans or |  |  | under the Plans |
Period |  | Purchased |  |  | Unit/Note |  |  | Programs |  |  | or Programs |
10/1/04 – 10/31/04 |  |  | 13,112,660 |  |  | $ | 50 |  |  |  | — |  |  |  | — |
11/1/04 – 11/30/04 |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
12/1/04 – 12/31/04 |  |  | 70,800 |  |  | $ | 1,000 |  |  |  | — |  |  |  | — |

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Total number of units purchased in October were comprised of 5,690,228 units of HIGH TIDES I and 7,422,432 units of HIGH TIDES II, and units purchased in December are comprised of the 2006 Convertible Senior Notes. In addition to par or face value purchased, accrued interest paid was approximately $.63 per share on HIGH TIDES I, $.60 per share on HIGH TIDES II, and $20 per note on the 2006 Convertible Senior Notes. 100% of the common securities issued by Trust I and Trust II and a portion of the HIGH TIDES I and II were owned by Calpine and, accordingly, the cash paid to redeem such common securities and HIGH TIDES was returned to Calpine.

Item 6. | Selected Financial Data

Selected Consolidated Financial Data

|  | Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |  |  | 2001 |  |  | 2000 |
|  | (In thousands, except earnings per share) |
Statement of Operations data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total revenue |  | $ | 9,229,888 |  |  | $ | 8,871,033 |  |  | $ | 7,349,753 |  |  | $ | 6,565,893 |  |  | $ | 2,264,495 |
Income before discontinued operations and cumulative effect of a change in accounting principle |  | $ | (440,826 | ) |  | $ | 86,110 |  |  | $ | 26,722 |  |  | $ | 527,772 |  |  | $ | 315,148 |
Discontinued operations, net of tax |  |  | 198,365 |  |  |  | 14,969 |  |  |  | 91,896 |  |  |  | 94,684 |  |  |  | 53,936 |
Cumulative effect of a change in accounting principle |  |  | — |  |  |  | 180,943 |  |  |  | — |  |  |  | 1,036 |  |  |  | — |
Net income |  | $ | (242,461 | ) |  | $ | 282,022 |  |  | $ | 118,618 |  |  | $ | 623,492 |  |  | $ | 369,084 |
Basic earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income before discontinued operations and cumulative effect of a change in accounting principle |  | $ | (1.02 | ) |  | $ | 0.22 |  |  | $ | 0.07 |  |  | $ | 1.74 |  |  | $ | 1.12 |
| Discontinued operations, net of tax |  |  | 0.46 |  |  |  | 0.04 |  |  |  | 0.26 |  |  |  | 0.31 |  |  |  | 0.19 |
| Cumulative effect of a change in accounting principle, net of tax |  |  | — |  |  |  | 0.46 |  |  |  | — |  |  |  | — |  |  |  | — |
| Net income |  | $ | (0.56 | ) |  | $ | 0.72 |  |  | $ | 0.33 |  |  | $ | 2.05 |  |  | $ | 1.31 |
Diluted earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income before discontinued operations and cumulative effect of a change in accounting principle |  | $ | (1.02 | ) |  | $ | 0.22 |  |  | $ | 0.07 |  |  | $ | 1.54 |  |  | $ | 1.02 |
| Discontinued operations, net of tax provision |  |  | 0.46 |  |  |  | 0.04 |  |  |  | 0.26 |  |  |  | 0.26 |  |  |  | 0.16 |
| Cumulative effect of a change in accounting principle, net of tax |  |  | — |  |  |  | 0.45 |  |  |  | — |  |  |  | — |  |  |  | — |
| Net income |  | $ | (0.56 | ) |  | $ | 0.71 |  |  | $ | 0.33 |  |  | $ | 1.80 |  |  | $ | 1.18 |
Balance Sheet data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total assets |  | $ | 27,216,088 |  |  | $ | 27,303,932 |  |  | $ | 23,226,992 |  |  | $ | 21,937,227 |  |  | $ | 10,610,232 |
Short-term debt and capital lease obligations |  |  | 1,033,956 |  |  |  | 349,128 |  |  |  | 1,651,448 |  |  |  | 903,307 |  |  |  | 64,525 |
Long-term debt and capital lease obligations |  |  | 16,940,809 |  |  |  | 17,328,181 |  |  |  | 12,462,290 |  |  |  | 12,490,175 |  |  |  | 5,018,044 |
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts(1) |  | $ | — |  |  | $ | — |  |  | $ | 1,123,969 |  |  | $ | 1,122,924 |  |  | $ | 1,122,390 |

(1) | Included in long-term debt as of December 31, 2003 and 2004. See Note 12 of the Notes to Consolidated Financial Statements for more information.

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|  | Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |  |  | 2001 |  |  | 2000 |
|  | (In thousands) |
Reconciliation of GAAP cash provided from operating activities to EBITDA, as adjusted(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash provided by operating activities |  | $ | 9,895 |  |  | $ | 290,559 |  |  | $ | 1,068,466 |  |  | $ | 423,569 |  |  | $ | 875,751 |
Less: Changes in operating assets and liabilities, excluding the effects of acquisitions(2) |  |  | (137,614 | ) |  |  | (609,840 | ) |  |  | 480,193 |  |  |  | (359,640 | ) |  |  | 277,696 |
Less: Additional adjustments to reconcile net income to net cash provided by operating activities, net(2) |  |  | 389,970 |  |  |  | 618,377 |  |  |  | 469,655 |  |  |  | 159,717 |  |  |  | 228,971 |
GAAP net income |  | $ | (242,461 | ) |  | $ | 282,022 |  |  | $ | 118,618 |  |  | $ | 623,492 |  |  | $ | 369,084 |
(Income) loss from unconsolidated investments in power projects and oil and gas properties |  |  | 13,525 |  |  |  | (75,804 | ) |  |  | 16,552 |  |  |  | 16,946 |  |  |  | 28,796 |
Distributions from unconsolidated investments in power projects and oil and gas properties |  |  | 29,869 |  |  |  | 141,627 |  |  |  | 14,117 |  |  |  | 5,983 |  |  |  | 29,979 |
| Adjusted net income |  | $ | (199,067 | ) |  | $ | 347,845 |  |  | $ | 116,183 |  |  | $ | 612,529 |  |  | $ | 370,267 |
Interest expense |  |  | 1,140,802 |  |  |  | 706,307 |  |  |  | 402,677 |  |  |  | 190,971 |  |  |  | 78,373 |
1/3 of operating lease expense |  |  | 35,295 |  |  |  | 37,357 |  |  |  | 37,007 |  |  |  | 33,173 |  |  |  | 21,154 |
Distributions on trust preferred securities |  |  | — |  |  |  | 46,610 |  |  |  | 62,632 |  |  |  | 62,412 |  |  |  | 45,076 |
Provision (benefit) for income taxes |  |  | (276,549 | ) |  |  | 8,495 |  |  |  | 10,835 |  |  |  | 273,137 |  |  |  | 211,670 |
Depreciation, depletion and amortization expense |  |  | 840,916 |  |  |  | 568,204 |  |  |  | 423,102 |  |  |  | 275,396 |  |  |  | 169,278 |
Interest expense, provision for income taxes and depreciation from discontinued operations |  |  | 112,487 |  |  |  | 84,489 |  |  |  | 128,900 |  |  |  | 165,217 |  |  |  | 127,914 |
EBITDA, as adjusted(1) |  | $ | 1,653,885 |  |  | $ | 1,799,307 |  |  | $ | 1,181,336 |  |  | $ | 1,612,835 |  |  | $ | 1,023,732 |

(1) | This non-GAAP measure is presented not as a measure of operating results, but rather as a measure of our ability to service debt and to raise additional funds. It should not be construed as an alternative to either (i) income from operations or (ii) cash flows from operating activities. It is defined as net income less income from unconsolidated investments, plus cash received from unconsolidated investments, plus provision for tax, plus interest expense (including distributions on trust preferred securities and one-third of operating lease expense, which is management’s estimate of the component of operating lease expense that constitutes interest expense,) plus depreciation, depletion and amortization. The interest, tax and depreciation and amortization components of discontinued operations are added back in calculating EBITDA, as adjusted.

| For the year ended December 31, 2004, EBITDA, as adjusted, includes a $246.9 million gain from the repurchase of debt, offset by approximately $223.4 million of certain charges, consisting primarily of foreign currency transaction losses, write-off of deferred financing costs not related to the bonds repurchased, equipment cancellation and impairment costs, certain mark-to-market activity, and minority interest expense, some of which required, or will require cash settlement.
| For the year ended December 31, 2003, EBITDA, as adjusted, includes a $180.9 million (net of tax) gain from the cumulative effect of a change in accounting principle and a $278.6 million gain from the repurchase of debt, offset by approximately $273.0 million of certain charges, consisting primarily of foreign currency transaction losses, equipment cancellation and impairment costs, certain mark-to-

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| market activity, and minority interest expense, some of which required, or will require cash settlement. EBITDA, as adjusted for the year ended December 31, 2002, includes a non-cash equipment cancellation charge of $404.7 million, a $118.0 million gain on the repurchase of debt, and approximately $55.0 million of certain charges, some of which required, or will require cash settlement.

(2) | See the Consolidated Statements of Cash Flows for further detail of these items.

Selected Operating Information

|  | Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |  |  | 2001 |  |  | 2000 |
|  | (Dollars in thousands, except production and pricing data) |
Power Plants(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electricity and steam (“E&S”) revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Energy |  | $ | 4,224,463 |  |  | $ | 3,361,095 |  |  | $ | 2,273,524 |  |  | $ | 1,701,533 |  |  | $ | 1,220,684 |
| Capacity |  |  | 991,142 |  |  |  | 844,195 |  |  |  | 781,127 |  |  |  | 525,174 |  |  |  | 376,085 |
| Thermal and other |  |  | 467,458 |  |  |  | 475,107 |  |  |  | 182,859 |  |  |  | 158,617 |  |  |  | 99,297 |
|  | Subtotal |  | $ | 5,683,063 |  |  | $ | 4,680,397 |  |  | $ | 3,237,510 |  |  | $ | 2,385,324 |  |  | $ | 1,696,066 |
Spread on sales of purchased power(2) |  |  | 164,747 |  |  |  | 24,118 |  |  |  | 527,546 |  |  |  | 345,834 |  |  |  | 11,262 |
Adjusted E&S revenues |  | $ | 5,847,810 |  |  | $ | 4,704,515 |  |  | $ | 3,765,056 |  |  | $ | 2,731,158 |  |  | $ | 1,707,328 |
MWh produced |  |  | 96,488,984 |  |  |  | 82,423,422 |  |  |  | 72,767,280 |  |  |  | 42,393,726 |  |  |  | 22,749,588 |
All-in electricity price per MWh generated |  | $ | 60.61 |  |  | $ | 57.08 |  |  | $ | 51.74 |  |  | $ | 64.42 |  |  | $ | 75.05 |

(1) | From continuing operations only. Discontinued operations are excluded.
(2) | From hedging, balancing and optimization activities related to our generating assets.

Set forth above is certain selected operating information for our power plants for which results are consolidated in our statements of operations. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenues include, besides traditional capacity payments, other revenues such as Reliability Must Run and Ancillary Service revenues. The information set forth under thermal and other revenue consists of host steam sales and other thermal revenue.

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##### Table of Contents

Set forth below is a table summarizing the dollar amounts and percentages of our total revenue for the years ended December 31, 2004, 2003, and 2002, that represent purchased power and purchased gas sales for hedging and optimization and the costs we incurred to purchase the power and gas that we resold during these periods (in thousands, except percentage data):

|  | Year Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |
Total revenue |  | $ | 9,229,888 |  |  | $ | 8,871,033 |  |  | $ | 7,349,753 |
Sales of purchased power for hedging and optimization(1) |  |  | 1,651,767 |  |  |  | 2,714,187 |  |  |  | 3,145,991 |
As a percentage of total revenue |  |  | 17.9 | % |  |  | 30.6 | % |  |  | 42.8 | %
Sale of purchased gas for hedging and optimization |  |  | 1,728,301 |  |  |  | 1,320,902 |  |  |  | 870,466 |
As a percentage of total revenue |  |  | 18.7 | % |  |  | 14.9 | % |  |  | 11.8 | %
Total cost of revenue (“COR”) |  |  | 8,874,795 |  |  |  | 8,106,796 |  |  |  | 6,388,269 |
Purchased power expense for hedging and optimization(1) |  |  | 1,487,020 |  |  |  | 2,690,069 |  |  |  | 2,618,445 |
As a percentage of total COR |  |  | 16.8 | % |  |  | 33.2 | % |  |  | 41.0 | %
Purchased gas expense for hedging and optimization |  |  | 1,716,714 |  |  |  | 1,279,568 |  |  |  | 821,065 |
As a percentage of total COR |  |  | 19.3 | % |  |  | 15.8 | % |  |  | 12.9 | %

(1) | On October 1, 2003, we adopted on a prospective basis EITF Issue No. 03-11 and netted purchases of power against sales of purchased power. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of our application of EITF Issue No. 03-11.

The primary reasons for the significant levels of these sales and costs of revenue items include: (a) significant levels of hedging, balancing and optimization activities by our CES risk management organization; (b) particularly volatile markets for electricity and natural gas, which prompted us to frequently adjust our hedge positions by buying power and gas and reselling it; (c) the accounting requirements under Staff Accounting Bulletin (“SAB”) No. 101, “Revenue Recognition in Financial Statements,” and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” under which we show most of our hedging contracts on a gross basis (as opposed to netting sales and cost of revenue); and (d) rules in effect associated with the NEPOOL market in New England, which require that all power generated in NEPOOL be sold directly to the ISO in that market; we then buy from the ISO to serve our customer contracts. GAAP required us to account for this activity, which applies to three of our merchant generating facilities, as the aggregate of two distinct sales and one purchase until our prospective adoption of EITF Issue No. 03-11 on October 1, 2003. This gross basis presentation increased revenues but not gross profit. The table below details the financial extent of our transactions with NEPOOL for financial periods prior to the adoption of EITF Issue No. 03-11. Our entrance into the NEPOOL market began with our acquisition of the Dighton, Tiverton and Rumford facilities on December 15, 2000.

|  | Nine Months |  |  |
|  | Ended |  |  | Year Ended |
|  | September 30, |  |  | December 31, |
|  | 2003 |  |  | 2002 |
|  | (In thousands) |
Sales to NEPOOL from power we generated |  | $ | 258,945 |  |  | $ | 294,634 |
Sales to NEPOOL from hedging and other activity |  |  | 117,345 |  |  |  | 106,861 |
| Total sales to NEPOOL |  | $ | 376,290 |  |  | $ | 401,495 |
Total purchases from NEPOOL |  | $ | 310,025 |  |  | $ | 360,113 |

(The statement of operations data information and the balance sheet data information contained in the Selected Financial Data is derived from the audited Consolidated Financial Statements of Calpine Corporation and Subsidiaries. See the Notes to the Consolidated Financial Statements and Item 7. “Management’s

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Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations” for additional information.)

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

Overview
Our core business and primary source of revenue is the generation and delivery of electric power. We provide power to our U.S., Canadian and U.K. customers through the integrated development, construction or acquisition, and operation of efficient and environmentally friendly electric power plants fueled primarily by natural gas and, to a much lesser degree, by geothermal resources. We own and produce natural gas and to a lesser extent oil, which we use primarily to lower our costs of power production and provide a natural hedge of fuel costs for a portion of our electric power plants, but also to generate some revenue through sales to third parties. We protect and enhance the value of our electric and gas assets with a sophisticated risk management organization. We also protect our power generation assets and control certain of our costs by producing certain of the combustion turbine replacement parts that we use at our power plants, and we generate revenue by providing combustion turbine parts to third parties. Finally, we offer services to third parties to capture value in the skills we have honed in building, commissioning, repairing and operating power plants.
Our key opportunities and challenges include:

| • | preserving and enhancing our liquidity while spark spreads (the differential between power revenues and fuel costs) are depressed,
| • | selectively adding new load-serving entities and power users to our customer list as we increase our power contract portfolio,
| • | continuing to add value through prudent risk management and optimization activities, and
| • | lowering our costs of production through various efficiency programs.

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 near-term surplus supply of electric generating capacity in certain market areas. These factors coupled with a three-year period of decreased spark spreads have adversely impacted our liquidity and earnings. While we have generally been able to continue to access the capital and bank credit markets on terms acceptable to us, we recognize that the 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 2004 we completed several strategic financings including the refinancing of our CalGen, formerly Calpine Construction Finance Company II, LLC (“CCFC II”), revolving construction facility indebtedness of approximately $2.5 billion, and the issuance of $785 million of 95/8% First Priority Senior Secured Notes Due 2014 and $736 million of Contingent Convertible Notes Due 2014 (“2014 Convertible Notes”), all of which are further discussed in Note 17 of the Notes to Consolidated Financial Statements. Debt maturities are relatively modest in 2005 and 2006 as shown in Note 11 of the Notes to Consolidated Financial Statements, but we face several challenges over the next two to three years as our cash requirements (including our refinancing obligations) are expected to exceed our unrestricted cash on hand and cash from operations. Accordingly, we have in place a liquidity-enhancing program which includes possible sales or monitizations of certain of our assets.
Set forth below are the Results of Operations for the years ending December 31, 2004, 2003, and 2002 (in millions, except for unit pricing information, percentages and MW volumes; in the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets. Decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets). Prior year amounts have been reclassified for discontinued operations.

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Results of Operations

| Year Ended December 31, 2004, Compared to Year Ended December 31, 2003

| Revenue

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Total revenue |  | $ | 9,230.0 |  |  | $ | 8,871.0 |  |  | $ | 359.0 |  |  |  | 4.0 | %

The increase in total revenue is explained by category below.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Electricity and steam revenue |  | $ | 5,683.1 |  |  | $ | 4,680.4 |  |  | $ | 1,002.7 |  |  |  | 21.4 | %
Transmission sales revenue |  |  | 20.0 |  |  |  | 15.3 |  |  |  | 4.7 |  |  |  | 30.7 | %
Sales of purchased power for hedging and optimization |  |  | 1,651.8 |  |  |  | 2,714.2 |  |  |  | (1,062.4 | ) |  |  | (39.1 | )%
| Total electric generation and marketing revenue |  | $ | 7,354.9 |  |  | $ | 7,409.9 |  |  | $ | (55.0 | ) |  |  | (1 | )%

Electricity and steam revenue increased as we completed construction and brought into operation five new baseload power plants and two project expansions in 2004. Average MW in operation of our consolidated plants increased by 23% to 24,690 MW while generation increased by 17%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 50% in 2004 from 53% in 2003 primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas due in part to mild weather, which caused us to cycle off certain of our merchants plants without contracts in off peak hours, and also due to oversupply conditions which are expected to gradually work off over the next several years. Average realized electricity prices, before the effects of hedging, balancing and optimization, increased to $58.90/ MWh in 2004 from $56.79/ MWh in 2003.
Transmission sales revenue increased in 2004 due to the increased emphasis in optimizing our portfolio through the resale of our underutilized transmission positions in the short- to mid-term markets.
Sales of purchased power for hedging and optimization decreased during 2004 due primarily to netting of approximately $1,676.0 of sales of purchased power with purchased power expense in 2004 compared to $256.6 in 2003 (netting in 2003 occurred only in the fourth quarter) in connection with the adoption of EITF Issue No. 03-11 on a prospective basis in the fourth quarter of 2003, partly offset by higher volumes and higher realized prices on hedging, balancing and optimization activities. Without this netting, sales of purchased power would have increased by $357.0, or 12.0%.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Oil and gas sales |  | $ | 63.2 |  |  | $ | 59.2 |  |  | $ | 4.0 |  |  |  | 6.8 | %
Sales of purchased gas for hedging and optimization |  |  | 1,728.3 |  |  |  | 1,320.9 |  |  |  | 407.4 |  |  |  | 30.8 | %
| Total oil and gas production and marketing revenue |  | $ | 1,791.5 |  |  | $ | 1,380.1 |  |  | $ | 411.4 |  |  |  | 29.8 | %

Oil and gas sales are net of internal consumption, which is eliminated in consolidation. Internal consumption decreased from $285.0 in 2003 to $208.2 in 2004 as a result of lower production following asset sales of our Canadian natural gas reserves and petroleum assets and our Rocky Mountain gas reserves. Before intercompany eliminations, oil and gas sales decreased by $72.8 to $271.4 in 2004 from $344.2 in 2003 due primarily to a reduction in production volumes.

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Sales of purchased gas for hedging and optimization increased during 2004 due primarily to higher volumes and higher prices of natural gas as compared to the same period in 2003.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Realized gain on power and gas mark-to-market transactions, net |  | $ | 48.2 |  |  | $ | 24.3 |  |  | $ | 23.9 |  |  |  | 98.4 | %
Unrealized (loss) on power and gas mark-to-market transactions, net |  |  | (34.7 | ) |  |  | (50.7 | ) |  |  | 16.0 |  |  |  | 31.6 | %
| Mark-to-market activities, net |  | $ | 13.5 |  |  | $ | (26.4 | ) |  | $ | 39.9 |  |  |  | 151.1 | %

Mark-to-market activities, which are shown on a net basis, result from general market price movements against our open commodity derivative positions, including positions accounted for as trading under EITF Issue No. 02-03 and other mark-to-market activities. These commodity positions represent a small portion of our overall commodity contract position. Realized revenue represents the portion of contracts actually settled and is offset by a corresponding change in unrealized gains or losses as unrealized derivative values are converted from unrealized forward positions to cash at settlement. Unrealized gains and losses include the change in fair value of open contracts as well as the ineffective portion of our cash flow hedges.
During 2004, we recognized a net gain from mark-to-market activities compared to net losses in 2003. In 2004 our exposure to mark-to-market earnings volatility declined commensurate with a corresponding decline in the volume of open commodity positions underlying the exposure. As a result, the magnitude of earnings volatility attributable to changes in prices declined. We recorded a hedge ineffectiveness gain of approximately $7.6 in 2004 versus a hedge ineffectiveness loss of $1.8 for the corresponding period in 2003. Additionally, during 2004 we recorded gains of $9.2 on a mark-to-market derivative contract that was terminated during 2004 versus a mark-to-market loss of $15.5 on the same contract in 2003.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Other revenue |  | $ | 70.1 |  |  | $ | 107.5 |  |  | $ | (37.4 | ) |  |  | (34.8 | )%

Other revenue decreased during 2004 primarily due to a one-time pre-tax gain of $67.3 realized during 2003, in connection with our settlement with Enron, principally related to the final negotiated settlement of claims and amounts owed under terminated commodity contracts. The decrease in 2004 was partially offset by increases of $13.3 and $12.0 from combustion turbine parts sales and repair and maintenance services performed by TTS and construction management and operating services performed by CPSI, respectively.

| Cost of Revenue

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Cost of revenue |  | $ | 8,874.8 |  |  | $ | 8,106.8 |  |  | $ | (768.0 | ) |  |  | (9.5 | )%

The increase in total cost of revenue is explained by category below.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Plant operating expense |  | $ | 796.0 |  |  | $ | 663.0 |  |  | $ | (133.0 | ) |  |  | (20.1 | )%
Royalty expense |  |  | 28.7 |  |  |  | 24.9 |  |  |  | (3.8 | ) |  |  | (15.3 | )%
Transmission purchase expense |  |  | 85.5 |  |  |  | 46.5 |  |  |  | (39.0 | ) |  |  | (83.9 | )%
Purchased power expense for hedging and optimization |  |  | 1,487.0 |  |  |  | 2,690.1 |  |  |  | 1,203.1 |  |  |  | 44.7 | %
| Total electric generation and marketing expense |  | $ | 2,397.2 |  |  | $ | 3,424.5 |  |  | $ | 1,027.3 |  |  |  | 30.0 | %

Plant operating expense increased as five new baseload power plants and two expansion projects were completed during 2004, and due to higher major maintenance expense on existing plants as many of our newer power plants performed their initial major maintenance work. In North America, 25 of our gas-fired plants performed major maintenance work, an increase of 67% over the number of plants that did so in 2003. In addition, during 2004 we incurred $54.3 for equipment failure costs compared to $11.0 in 2003.

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Transmission purchase expense increased primarily due to additional power plants achieving commercial operation in 2004.
Approximately 76% of the royalty expense for 2004 vs. 78% for 2003 is attributable to royalties paid to geothermal property owners at The Geysers, mostly as a percentage of geothermal electricity revenues. The increase in royalty expense in 2004 was due primarily to a $2.5 increase in royalties at The Geysers, and the remainder was due to an increase in the accrual of contingent purchase price payments to the previous owners of the Texas City and Clear Lake Power Plants based on a percentage of gross revenues at these two plants.
Purchased power expense for hedging and optimization decreased during 2004 as compared to 2003 due primarily to netting of approximately $1,676.0 of purchased power expense against sales of purchased power in 2004 compared to $256.6 in 2003, in connection with the adoption of EITF Issue No. 03-11 in the fourth quarter of 2003, partly offset by higher volumes and higher realized prices on hedging, balancing and optimization activities. Without this netting, purchased power expense would have increased by $216.4 or 7.3%.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Oil and gas production expense |  | $ | 48.9 |  |  | $ | 56.3 |  |  | $ | 7.4 |  |  |  | 13.1 | %
Oil and gas exploration expense |  |  | 7.9 |  |  |  | 19.2 |  |  |  | 11.3 |  |  |  | 58.9 | %
| Oil and gas operating expense |  | $ | 56.8 |  |  | $ | 75.5 |  |  | $ | 18.7 |  |  |  | 24.8 | %
Purchased gas expense for hedging and optimization |  |  | 1,716.7 |  |  |  | 1,279.6 |  |  |  | (437.1 | ) |  |  | (34.2 | )%
|  | Total oil and gas operating and marketing expense |  | $ | 1,773.5 |  |  | $ | 1,355.1 |  |  | $ | (418.4 | ) |  |  | (30.9 | )%

Oil and gas production expense decreased during 2004 as compared to the same period in 2003 primarily due to lower lease operating expense resulting from lower production volumes due to the sales of oil and gas properties completed in the fourth quarter of 2003 and third quarter of 2004.
Oil and gas exploration expense decreased primarily as a result of a decrease in dry hole costs resulting from declines in capital expenditures driven by a lower operating base due to sales of oil and gas properties completed in the fourth quarter of 2003 and third quarter of 2004.
Purchased gas expense for hedging and optimization increased during 2004 due to higher volumes and higher prices for gas in 2004.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Fuel expense |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost of oil and gas burned by power plants |  | $ | 3,732.6 |  |  | $ | 2,677.2 |  |  | $ | (1,055.4 | ) |  |  | (39.4 | )%
Recognized (gain) on gas hedges |  |  | (1.5 | ) |  |  | (11.6 | ) |  |  | (10.1 | ) |  |  | (87.1 | )%
| Total fuel expense |  | $ | 3,731.1 |  |  | $ | 2,665.6 |  |  | $ | (1,065.5 | ) |  |  | (40.0 | )%

Cost of oil and gas burned by power plants increased during 2004 as compared to 2003 due to a 17.4% increase in gas consumption as we increased our MW production and higher prices for gas excluding the effects of hedging, balancing and optimization.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Depreciation, depletion and amortization expense |  | $ | 574.2 |  |  | $ | 504.4 |  |  | $ | (69.8 | ) |  |  | (13.8 | )%

Depreciation, depletion and amortization expense increased in 2004 primarily due to additional power plants achieving commercial operation subsequent to 2003.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Oil and gas impairment |  | $ | 202.1 |  |  | $ | 2.9 |  |  | $ | (199.2 | ) |  |  | (6,869.0 | )%

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As a result of decreases in proved undeveloped reserves located in South Texas and proved developed non-producing reserves in Offshore Gulf of Mexico a non-cash impairment charge of approximately $202.1 was recorded as of December 31, 2004.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Operating lease expense |  | $ | 105.9 |  |  | $ | 112.1 |  |  | $ | 6.2 |  |  |  | 5.5 | %

Operating lease expense decreased during 2004 as compared to 2003 primarily because the King City lease terms were restructured and the lease began to be accounted for as a capital lease. As a result, we ceased incurring operating lease expense on that lease and instead began to incur depreciation and interest expense.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Other cost of revenue |  | $ | 90.7 |  |  | $ | 42.3 |  |  | $ | (48.4 | ) |  |  | (114.4 | )%

Other cost of revenue increased during 2004 as compared to 2003 primarily due to $29.0 of amortization expense in 2004 versus $10.6 in 2003 incurred from the adoption of DIG Issue No. C20. In the fourth quarter of 2003, we recorded a pre-tax mark-to-market gain of $293.4 as a cumulative effect of a change in accounting principle. This gain is amortized as expense over the respective lives of the two power sales contracts from which the mark-to-market gains arose. We also incurred $11.3 of additional expense from TTS in 2004, as the entity had a full year of activity (we acquired TTS in late February of 2003). Additionally, CPSI cost of revenue increased $10.8 in 2004 compared to 2003 due to an increase in services contract activity.

| (Income)/ Expense

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
(Income) loss from unconsolidated investments in power projects and oil and gas properties |  | $ | 13.5 |  |  | $ | (75.8 | ) |  | $ | (89.3 | ) |  |  | (117.8 | )%

The reduction in income was primarily due to a non-recurring $52.8 gain in 2003, representing our 50% share, on the termination of the tolling arrangement with Aquila Merchant Services, Inc. (“AMS”) at the Acadia Energy Center and a loss of $11.6 realized in 2004, representing our share of a jury award to International Paper Company (“IP”) in a litigation relating to Androscoggin Energy LLC (“AELLC”) together with a $5 impairment charge recorded when Androscoggin filed for bankruptcy protection in the fourth quarter of 2004. Also, we did not have any income on our Gordonsville investment in 2004, compared to $12.0 in 2003, as we sold our interest in this facility in November 2003. For further information, see Note 7 of the Notes to Consolidated Financial Statements.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Equipment cancellation and impairment cost |  | $ | 42.4 |  |  | $ | 64.4 |  |  | $ | 22.0 |  |  |  | 34.2 | %

In 2004, the pre-tax equipment cancellation and impairment charge was primarily a result of charges of $33.7 related to cancellation costs of six heat recovery steam generators (“HRSG”) orders and HRSG component parts cancellations and impairments. In 2003 the pre-tax equipment cancellation and impairment charge was primarily a result of cancellation costs related to three turbines and three HRSGs and impairment charges related to four turbines.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Long-term service agreement cancellation charge |  | $ | 11.3 |  |  | $ | 16.4 |  |  | $ | 5.1 |  |  |  | 31.1 | %

Long-term service agreement (“LTSA”) cancellation charges decreased primarily due to $14.1 in cancellation costs incurred in 2003 associated with LTSAs with General Electric related to our Rumford, Tiverton and Westbrook facilities. In 2004 the decrease was offset by a $7.7 adjustment as a result of settlement negotiations related to the cancellation of LTSAs with Siemens-Westinghouse Power Corporation at our Hermiston, Ontelaunee, South Point and Sutter facilities and a $3.8 adjustment as a result of LTSA

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cancellation settlement negotiations with General Electric regarding cancellation charges at our Los Medanos facility.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Project development expense |  | $ | 24.4 |  |  | $ | 21.8 |  |  | $ | (2.6 | ) |  |  | (11.9 | )%

Project development expense increased during 2004 primarily due to higher costs associated with cancelled projects, and due to costs incurred in 2004 on oil and gas storage, pipeline and liquid natural gas projects.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Research and development expense |  | $ | 18.4 |  |  | $ | 10.6 |  |  | $ | (7.8 | ) |  |  | (73.6 | )%

Research and development expense increased in 2004 as compared to 2003 primarily due to increased personnel expense related to gas turbine component research and development programs at our PSM subsidiary.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Sales, general and administrative expense |  | $ | 239.3 |  |  | $ | 216.5 |  |  | $ | (22.8 | ) |  |  | (10.5 | )%

Sales, general and administrative expense increased in 2004 due primarily to an increase of $20.4 of Sarbanes-Oxley 404 internal control project costs. Sales, general and administrative expense expressed per MWh of generation decreased to $2.48/MWh in 2004 from $2.63/MWh in 2003, due to a 17% increase in MWh generated as more plants entered commercial operation.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Interest expense |  | $ | 1,140.8 |  |  | $ | 706.3 |  |  | $ | (434.5 | ) |  |  | (61.5 | )%

Interest expense increased as a result of higher average debt balances, higher average interest rates and lower capitalization of interest expense. Interest capitalized decreased from $444.5 in 2003 to $376.1 in 2004 as a result of new plants that entered commercial operations (at which point capitalization of interest expense ceases). We expect that the amount of interest capitalized will continue to decrease in future periods as our plants in construction are completed. Additionally during 2004, (i) interest expense related to our senior notes and term loans increased $125.8; (ii) interest expense related to our CalGen financing was responsible for an increase of $113.7; (iii) interest expense related to our notes payable and borrowings under lines of credit increased $40.0; (iv) interest expense related to our CCFC I financing increased $26.1; and (v) interest expense related to our preferred interests increased $28.7. The majority of the remaining increase relates to an increase in average indebtedness due primarily to the deconsolidation of our three Calpine Capital Trust subsidiaries (the “Trusts”) which issued the HIGH TIDES I, II and III and recording of debt to the Trusts due to the adoption of Financial Accounting Standards Board (“FASB”) Interpretation No. (“FIN”) 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (“FIN 46”) prospectively on October 1, 2003 (see Note 2 of the Notes to Consolidated Financial Statements for a discussion of our adoption of FIN 46). Interest expense related to the notes payable to the Trusts during 2004 was $58.6. The distributions were excluded from the interest expense caption on our Consolidated Statements of Operations through the nine months ended September 30, 2003, while $15.1 of interest expense related to the Trusts was recorded for the quarter ending December 31, 2003. The HIGH TIDES I and II and the related notes payable to the Trusts were redeemed in October 2004.

|  | 2004 |  | 2003 |  |  | $ Change |  |  | % Change |
Distributions on trust preferred securities |  | $ | — |  |  | $ | 46.6 |  |  | $ | 46.6 |  |  |  | (100 | )%

As discussed above, as a result of the deconsolidation of the Trusts upon adoption of FIN 46 as of October 1, 2003, the distributions paid on the HIGH TIDES I, II and III during 2004 were no longer recorded on our books and were replaced prospectively by interest expense on our debt to the Trusts.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Interest (income) |  | $ | (56.4 | ) |  | $ | (39.7 | ) |  | $ | 16.7 |  |  |  | 42.1 | %

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The increase in interest (income) in 2004 is due to an increase in cash and cash equivalents and restricted cash balances during the year. Additionally, we generated interest income on the repurchases of our HIGH TIDES I, II and III. For further information, see Note 3 of the Notes to Consolidated Financial Statements.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Minority interest expense |  | $ | 34.7 |  |  | $ | 27.3 |  |  | $ | (7.4 | ) |  |  | (27.1 | )%

Minority interest expense increased during 2004 as compared to 2003 due to our reduced ownership percentage in the Calpine Power Limited Partnership (“CPLP”) following the sale of our interest in the Calpine Power Income Fund (“CPIF”) which owns 70% of CPLP. Our 30% interest is subordinate to CPIF’s interest.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
(Income) from the repurchase of various issuances of debt |  | $ | (246.9 | ) |  | $ | (278.6 | ) |  | $ | (31.7 | ) |  |  | (11.4 | )%

Income from repurchases of various issuances of debt during 2004 decreased by $31.7 from the corresponding period primarily as a result of lower face amounts of debt repurchased in open market and privately negotiated transactions.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Other (income), net |  | $ | (149.1 | ) |  | $ | (46.1 | ) |  | $ | 103.0 |  |  |  | 223.4 | %

Other income increased in 2004 as compared to 2003 primarily due to (a) pre-tax income in 2004 in the amount of $171.5 associated with the restructuring of power purchase agreements for our Newark and Parlin power plants and the sale of Utility Contract Funding II, LLC, net of transaction costs and the write-off of unamortized deferred financing costs, (b) $16.4 pre-tax gain from the restructuring of a long-term gas supply contract net of transaction costs and (c) $12.3 pre-tax gain from the King City restructuring transaction related to the sale of our debt securities that had served as collateral under the King City lease, net of transaction costs. In addition, during 2004, foreign currency transaction losses totaled $25.1, compared to losses of $33.3 in the corresponding period in 2003. See further discussion of our currency transaction losses under “Financial Market Risks”.
In 2003, we recorded a gain of $62.2 on the sale of oil and gas properties and a gain of $57.0 from a contract termination of the RockGen facility.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Provision (benefit) for income taxes |  | $ | (276.5 | ) |  | $ | 8.5 |  |  | $ | 285.0 |  |  |  | 3,352.9 | %

For 2004, the effective rate was 38.6% as compared to 9.0% for 2003. The variance in the effective rate is primarily due to the sale of oil and gas assets in Canada, resulting in reclassifying certain permanent difference deduction items primarily related to cross border financings to discontinued operations.

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Discontinued operations, net of tax |  | $ | 198.4 |  |  | $ | 15.0 |  |  | $ | (183.4 | ) |  |  | (1,222.7 | )%

The 2004 discontinued operations activity includes the effects of the sale of our 50% interest in the Lost Pines 1 Power Project, the sale of our oil and gas reserves in the Colorado Piceance Basin and New Mexico San Juan Basin and the sale of our Canadian natural gas reserves and petroleum assets, all of which resulted in a gain on sale, pre-tax, of $239.6. The 2003 discontinued operations activity includes the operational reclasses to discontinued operations related to Lost Pines 1 Power Project, the sale of our Alvin South Field oil and gas assets, the sale of our oil and gas reserves in the United States and Canada, and the sale of our specialty data center engineering business. For more information about discontinued operations, see Note 10 of the Notes to Consolidated Financial Statements.

|  | 2004 |  | 2003 |  |  | $ Change |  |  | % Change |
Cumulative effect of a change in accounting principle, net of tax |  | $ | — |  |  | $ | 180.9 |  |  | $ | (180.9 | ) |  |  | (100.0 | )%

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The 2003 gain from the cumulative effect of a change in accounting principle included three items: (1) a gain of $181.9, net of tax effect, from the adoption of DIG Issue No. C20; (2) a loss of $1.5 associated with the adoption of FIN 46, as revised (“FIN 46-R”) and the deconsolidation of the Trusts which issued the HIGH TIDES. The loss of $1.5 represents the reversal of a gain, net of tax effect, recognized prior to the adoption of FIN 46-R on our repurchase of $37.5 of the value of HIGH TIDES by issuing shares of our common stock valued at $35.0; and (3) a gain of $0.5, net of tax effect, from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations” (“SFAS No. 143”).

| Net Income (Loss)

|  | 2004 |  |  | 2003 |  |  | $ Change |  |  | % Change |
Net income (loss) |  | $ | (242.5 | ) |  | $ | 282.0 |  |  | $ | (524.5 | ) |  |  | (186.0 | )%

Throughout 2004 we continued to focus on opportunities to add value by adding to and increasing the performance of our power plant portfolio. We added 3,655 MW to our fleet by completing construction on five power plants and two expansion projects at existing plants. Five of these seven facilities have much of their output under long-term contracts. In March 2004 we acquired the 570 MW Brazos Valley Power Plant. Currently our fleet includes 92 power plants in operation, totaling 26,649 MW.
We generated 96.5 million MWh in 2004, which equated to a baseload capacity factor of 49.8%, and realized an average spark spread of $21.24/MWh. In 2003 we generated 82.4 million MWh, which equated to a capacity factor of 53.2%, and realized an average spark spread of $23.90/MWh.
Gross profit decreased by $409.1, or 54%, to $355.1 in 2004, primarily due to: (i) $202.1 of impairment charges for certain oil and gas reserves; (ii) non-recurring other revenue of $67.3 recognized in 2003 from the settlement of contract disputes with, and claims against, Enron; (iii) the recording in 2004 of approximately $54.3 for equipment failure costs within plant operating expense, compared to $11.0 in 2003; (iv) the amortization of $29.0 in 2004 of the DIG Issue No. C20 gain recorded in the fourth quarter of 2003 due to the cumulative effect of a change in accounting principle; and (v) soft market fundamentals, which caused total spark spread, despite an increase of $79.2, or 4%, to not increase commensurate with additional plant operating expense, transmission purchase expense and depreciation costs associated with new power plants coming on-line.
During 2004, financial results were also affected by a $387.9 increase in interest expense and distributions on our debt, as compared to the same period in 2003. This occurred as a result of higher debt balances, higher average interest rates and lower capitalization of interest as new plants entered commercial operation. Prior year results benefited from recording $52.8 (in income from unconsolidated investments in power projects) due to the termination of a power purchase agreement by the Acadia joint venture.
Other income increased by $103.0 to $149.1 during 2004, as compared to 2003, primarily due to: (i) pre-tax income in the amount of $171.5, net of transaction costs and the write-off of unamortized deferred financing costs, associated with the restructuring of power purchase agreements for our Newark and Parlin power plants and the sale of an entity holding a power purchase agreement; (ii) a $16.4 pre-tax gain from the restructuring of a long-term supply contract net of transaction costs; and (iii) a $12.3 pre-tax gain from the King City restructuring transaction related to the sale of our debt securities that had served as collateral under the King City lease, net of transaction costs. In 2003 we recorded a gain of $62.2 on the sale of oil and gas properties and a gain of $57.0 from a contract termination at our RockGen facility. See further discussion of our currency transaction losses under “Financial Market Risks.”
In 2004, we recorded a charge of $42.4 for equipment cancellation costs, primarily related to cancellation of HRSG orders on two of our development projects. In 2003 there were $64.4 in equipment cancellation charges. Also during 2004 foreign currency transaction losses were $25.1 compared to losses of $33.3 in the corresponding period in 2003. We recognized gains totaling $246.9 on repurchases of debt in 2004 compared to $278.6 in 2003 and loss before discontinued operations and cumulative effect of a change in accounting principle was $416.3 in 2004.

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Discontinued operations, net of tax increased by $183.4 in 2004, compared to 2003, as a result of the sale of our Canadian, and certain of our U.S. oil and gas assets during the third quarter of 2004 and the sale of our interest in the Lost Pines facility in the first quarter of 2004.

| Year Ended December 31, 2003, Compared to Year Ended December 31, 2002

| Revenue

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Total revenue |  | $ | 8,871.0 |  |  | $ | 7,349.8 |  |  | $ | 1,521.2 |  |  |  | 20.7 | %

The increase in total revenue is explained by category below.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Electricity and steam revenue |  | $ | 4,680.4 |  |  | $ | 3,237.5 |  |  | $ | 1,442.9 |  |  |  | 44.6 | %
Transmission sale revenue |  |  | 15.3 |  |  |  | — |  |  |  | 15.3 |  |  |  | 100.0 | %
Sales of purchased power for hedging and optimization |  |  | 2,714.2 |  |  |  | 3,146.0 |  |  |  | (431.8 | ) |  |  | (13.7 | )%
| Total electric generation and marketing revenue |  | $ | 7,409.9 |  |  | $ | 6,383.5 |  |  | $ | 1,026.4 |  |  |  | 16.1 | %

Electricity and steam revenue increased as we completed construction and brought into operation five new baseload power plants, seven new peaker facilities and three project expansions in 2003. Average MW in operation of our consolidated plants increased by 40% to 20,092 MW while generation increased by 13%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 53% in 2003 from 65% in 2002 primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas reflecting oversupply conditions which are expected to gradually work off over the next several years (this caused us to cycle off certain of our merchant plants without contracts in off-peak hours) and to a lesser extent due to unscheduled outages caused by equipment problems at certain of our plants in the first half of 2003. Average realized electricity prices, before the effects of hedging, balancing and optimization, increased to $56.79/ MWh in 2003 from $44.49/ MWh in 2002.
We generated transmission sales revenue in 2003 due to the resale of some of our underutilized positions in the short- to mid-term markets.
Sales of purchased power for hedging and optimization decreased during 2003, due primarily to adoption of EITF Issue No. 03-11 and lower realized prices on term power hedges.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Oil and gas sales |  | $ | 59.2 |  |  | $ | 63.5 |  |  | $ | (4.3 | ) |  |  | (6.8 | )%
Sales of purchased gas for hedging and optimization |  |  | 1,320.9 |  |  |  | 870.5 |  |  |  | 450.4 |  |  |  | 51.7 | %
| Total oil and gas production and marketing revenue |  | $ | 1,380.1 |  |  | $ | 934.0 |  |  | $ | 446.1 |  |  |  | 47.8 | %

Oil and gas sales are net of internal consumption, which is eliminated in consolidation. Internal consumption increased by $143.7 to $285.0 in 2003. Before intercompany eliminations, oil and gas sales increased by $139.4 to $344.2 in 2003 from $204.8 in 2002 due primarily to 68% higher average realized natural gas pricing in 2003.
Sales of purchased gas for hedging and optimization increased during 2003 due to higher prices for natural gas.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Realized gain on power and gas transactions, net |  | $ | 24.3 |  |  | $ | 26.1 |  |  | $ | (1.8 | ) |  |  | (6.9 | )%
Unrealized loss on power and gas transactions, net |  |  | (50.7 | ) |  |  | (4.6 | ) |  |  | (46.1 | ) |  |  | (1,002.2 | )%
| Mark-to-market activities, net |  | $ | (26.4 | ) |  | $ | 21.5 |  |  | $ | (47.9 | ) |  |  | (222.8 | )%

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Realized revenue on power and gas mark-to-market activity represents the portion of mark-to-market contracts actually settled.
Mark-to-market activities, which are shown on a net basis, result from general market price movements against our open commodity derivative positions, including positions accounted for as trading under EITF Issue No. 02-03, and other mark-to-market activities. These commodity positions represent a small portion of our overall commodity contract position. Realized revenue represents the portion of contracts actually settled, while unrealized revenue represents changes in the fair value of open contracts, and the ineffective portion of cash flow hedges. The decrease in mark-to-market activities revenue in 2003 is due primarily to a $27.3 reduction in value of option contracts associated with a spark spread protection arrangement for the CCFC I financing and a decline in the value of a long-term spark spread option contract accounted for on a mark-to-market basis under SFAS No. 133.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Other revenue |  | $ | 107.5 |  |  | $ | 10.8 |  |  | $ | 96.7 |  |  |  | 895.4 | %

Other revenue increased during 2003 primarily due to $67.3 recorded in connection with our settlement with Enron, primarily related to the termination of commodity contracts following the Enron bankruptcy. We also realized $23.6 of revenue from TTS, which we acquired in late February 2003. PSM revenues increased $6.2 in 2003 as compared to 2002.

| Cost of Revenue

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Total cost of revenue |  | $ | 8,106.8 |  |  | $ | 6,388.3 |  |  | $ | (1,718.5 | ) |  |  | (26.9 | )%

The increase in total cost of revenue is explained by category below.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Plant operating expense |  | $ | 663.0 |  |  | $ | 522.9 |  |  | $ | (140.1 | ) |  |  | (26.8 | )%
Royalty expense |  |  | 24.9 |  |  |  | 17.6 |  |  |  | (7.3 | ) |  |  | (41.5 | )%
Transmission purchase expense |  |  | 46.5 |  |  |  | 25.5 |  |  |  | (21.0 | ) |  |  | (82.4 | )%
Purchased power expense for hedging and optimization |  |  | 2,690.1 |  |  |  | 2,618.4 |  |  |  | (71.7 | ) |  |  | (2.7 | )%
| Total electric generation and marketing expense |  | $ | 3,424.5 |  |  | $ | 3,184.4 |  |  | $ | (240.1 | ) |  |  | (7.5 | )%

Plant operating expense increased due to five new baseload power plants, seven new peaker facilities and three expansion projects completed during 2003. Additionally, we experienced higher transmission expenses and higher maintenance expense as several newer plants underwent their first scheduled hot gas path overhauls which generally first occur after a plant has been in operation for three years.
Transmission purchase expense increased as additional plants were brought on line in 2003.
Royalty expense increased primarily due to the accrual of $5.3 in 2003 vs. $0 in 2002 for payments to the previous owner of the Texas City and Clear Lake Power Plants based on a percentage of gross revenues at these two natural gas-fired plants. Additionally, royalties increased by $2.0 due to an increase in electric revenues at The Geysers geothermal plants, where we pay royalties to geothermal property owners, mostly as a percentage of geothermal electricity revenues. Approximately 78% of the royalty expense for 2003 is attributable to such geothermal royalties.

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The increase in purchased power expense for hedging and optimization was due primarily to increased spot market costs to purchase power for hedging and optimization activities partially offset by netting in the fourth quarter of 2003 due to the adoption of EITF Issue No. 03-11.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Oil and gas production expense |  | $ | 56.3 |  |  | $ | 56.8 |  |  | $ | 0.5 |  |  |  | 1.0 | %
Oil and gas exploration expense |  |  | 19.2 |  |  |  | 13.0 |  |  |  | (6.2 | ) |  |  | (47.7 | )%
| Oil and gas operating expense |  | $ | 75.5 |  |  | $ | 69.8 |  |  | $ | (5.7 | ) |  |  | (8.2 | )%
Purchased gas expense for hedging and optimization |  |  | 1,279.6 |  |  |  | 821.1 |  |  |  | (458.5 | ) |  |  | (55.8 | )%
|  | Total oil and gas operating and marketing expense |  | $ | 1,355.1 |  |  | $ | 890.9 |  |  | $ | (464.2 | ) |  |  | (52.1 | )%

Oil and gas production expense was flat compared to 2002; excluding the effects of discontinued operations (see Note 10 of the Notes to Consolidated Financial Statements for further information), oil and gas production expense would have increased primarily due to higher production taxes and higher gas treating and transportation costs, which were primarily the result of higher oil and gas prices plus an increase in operating cost and an increase in the average Canadian dollar foreign exchange rate in 2003.
Oil and gas exploration expense increased primarily as a result of $9.5 in dry hole drilling expenses in 2003 compared to $5.0 in 2002.
Purchased gas expense for hedging and optimization increased during 2003 due to higher prices for gas in 2003.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Fuel expense |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost of oil and gas burned by power plants |  | $ | 2,677.2 |  |  | $ | 1,659.3 |  |  | $ | (1,017.9 | ) |  |  | (61.3 | )%
Recognized (gain) loss on gas hedges |  |  | (11.6 | ) |  |  | 133.0 |  |  |  | 144.6 |  |  |  | 108.7 | %
| Total fuel expense |  | $ | 2,665.6 |  |  | $ | 1,792.3 |  |  | $ | (873.3 | ) |  |  | (48.7 | )%

Fuel expense increased in 2003, due to a 15% increase in gas-fired MWh generated and 33% higher prices excluding the effects of hedging, balancing and optimization. This was partially offset by an increased value of internally produced gas, which is eliminated in consolidation.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Depreciation, depletion and amortization expense |  | $ | 504.4 |  |  | $ | 398.9 |  |  | $ | (105.5 | ) |  |  | (26.4 | )%

Depreciation, depletion and amortization expense increased in 2003 primarily due to additional power plants achieving commercial operation subsequent to 2002.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Oil and gas impairment |  | $ | 2.9 |  |  | $ | 3.4 |  |  | $ | 0.5 |  |  |  | 14.7 | %

In 2003, oil and gas impairment charges decreased slightly due primarily to the fact that in 2002 we incurred higher impairments on properties located throughout Texas and Oklahoma.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Operating lease expense |  | $ | 112.1 |  |  | $ | 111.0 |  |  | $ | (1.1 | ) |  |  | (1.0 | )%

Operating lease expense was flat as the number of operating leases did not change in 2003 as compared to 2002.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Other cost of revenue |  | $ | 42.3 |  |  | $ | 7.3 |  |  | $ | (35.0 | ) |  |  | (479.5 | )%

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Approximately half of this increase is due to $17.3 of TTS expense. TTS was acquired in late February 2003 so there is no comparable expense in the prior period. Additionally, PSM expense increased $9.0 in 2003 as compared to 2002 due primarily to an increase in sales.

| (Income)/ Expenses

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
(Income) from unconsolidated investments in power projects and oil and gas properties |  | $ | (75.8 | ) |  | $ | (16.6 | ) |  | $ | 59.2 |  |  |  | 356.6 | %

The increase in income is primarily due to a $52.8 gain recognized on the termination of the tolling agreement with AMS on the Acadia Energy Center (see Note 7 of the Notes to Consolidated Financial Statements). Additionally, we realized a pre-tax gain of $7.1 from the sale of our interest in the Gordonsville Energy Center to Dominion Virginia Power.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Equipment cancellation and impairment cost |  | $ | 64.4 |  |  | $ | 404.7 |  |  | $ | 340.3 |  |  |  | 84.1 | %

In 2003, the pre-tax equipment cancellation and impairment charge was primarily a result of cancellation costs related to three turbines and three HRSGs and impairment charges related to four turbines. The pre-tax charge of $404.7 in 2002 was the result of turbine and other equipment order cancellation charges and related write-offs as a result of our scale-back in construction and development activities. For further information, see Note 25 of the Notes to Consolidated Financial Statements.

|  | 2003 |  |  | 2002 |  | $ Change |  |  | % Change |
Long-term service agreement cancellation charges |  | $ | 16.4 |  |  | $ | — |  |  | $ | (16.4 | ) |  |  | (100.0 | )%

Of the $16.4 in charges incurred in 2003, $14.1 occurred as a result of the cancellation of LTSAs with General Electric related to our Rumford, Tiverton and Westbrook facilities. The other $2.3 occurred as a result of the cancellation of LTSAs with Siemens-Westinghouse Power Corporation related to our Sutter, South Point, Hermiston and Ontelaunee facilities.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Project development expense |  | $ | 21.8 |  |  | $ | 67.0 |  |  | $ | 45.2 |  |  |  | 67.5 | %

Project development expense decreased as we placed certain existing development projects on hold and scaled back new development activity. Additionally, write-offs of terminated and suspended development projects decreased to $3.7 in 2003 from $34.8 in 2002.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Research and development expense |  | $ | 10.6 |  |  | $ | 10.0 |  |  | $ | (0.6 | ) |  |  | (6.0 | )%

The modest increase in research and development is attributed to increased personnel expenses related to research and development programs at our PSM subsidiary.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Sales, general and administrative expense |  | $ | 216.5 |  |  | $ | 186.1 |  |  | $ | (30.4 | ) |  |  | (16.3 | )%

Sales, general and administrative expense increased due to $10.7 of stock-based compensation expense associated with our adoption of SFAS No. 123, “Accounting for Stock-Based Compensation,” effective January 1, 2003, on a prospective basis while $7.1 of the increase is attributable to the acquisition of TTS in late February 2003. Other increases include $7.3 in insurance costs and a write-off of excess office space. Sales, general and administrative expense expressed per MWh of generation increased to $2.63/ MWh in 2003 from $2.56/ MWh in 2002, due to a lower average capacity factor in 2003.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Interest expense |  | $ | 706.3 |  |  | $ | 402.7 |  |  | $ | (303.6 | ) |  |  | (75.4 | )%

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Interest expense increased primarily due to the new plants entering commercial operations (at which point capitalization of interest expense ceases). Interest capitalized decreased from $575.5 for the year ended December 31, 2002, to $444.5 for the year ended December 31, 2003. We expect that interest expense will continue to increase and the amount of interest capitalized will decrease in future periods as our plants in construction are completed, and, to a lesser extent, as a result of suspension of certain of our development projects and suspension of capitalization of interest thereon. The remaining increase relates to an increase in average indebtedness, an increase in the amortization of terminated interest rate swaps and the recording of interest expense on debt to the three Trusts due to the adoption of FIN 46-R prospectively on October 1, 2003. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of our adoption of FIN 46-R.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Distributions on trust preferred securities |  | $ | 46.6 |  |  | $ | 62.6 |  |  | $ | (16.0 | ) |  |  | (25.6 | )%

As a result of the deconsolidation of the Trusts upon adoption of FIN 46-R as of October 1, 2003, the distributions paid on the HIGH TIDES during the fourth quarter of 2003 were no longer recorded on our books and were replaced by interest expense on our debt to the Trusts, thus explaining the decrease in distributions on the HIGH TIDES in 2003.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Interest income |  | $ | (39.7 | ) |  | $ | (43.1 | ) |  | $ | (3.4 | ) |  |  | (7.9 | )%

The decrease is primarily due to lower cash balances and lower interest rates in 2003.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Minority interest expense |  | $ | 27.3 |  |  | $ | 2.7 |  |  | $ | (24.6 | ) |  |  | (911.1 | )%

The increase is primarily due to an increase of $24.4 of minority interest expense associated with CPIF, which had an initial public offering in August 2002 to fund its interest in CPLP. During 2003 as a result of a secondary offering of Calpine’s interests in CPIF, we decreased our ownership interests in CPLP in February 2003 to 30%, thus increasing minority interest expense. Additionally, prior to fourth quarter of 2003, we presented minority interest expense related to CPIF net of taxes, but we reclassed $13.4 of tax benefit from minority interest expense to tax expense in the fourth quarter of 2003, thus increasing minority interest expense by that amount.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
(Income) from repurchase of various issuances of debt |  | $ | (278.6 | ) |  | $ | (118.0 | ) |  | $ | 160.6 |  |  |  | 136.1 | %

The 2003 pre-tax gain of $278.6 was recorded in connection with the repurchase of various issuances of debt at a discount. In 2002 the primary contribution was a gain of $114.8 from the receipt of Senior Notes, which were trading at a discount to face value, as partial consideration for British Columbia oil and gas asset sales.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Other (income), net |  | $ | (46.1 | ) |  | $ | (34.2 | ) |  | $ | 11.9 |  |  |  | 34.8 | %

Other income during 2003 is comprised primarily of gains of $62.2 on the sale of oil and gas assets to the CNGT and $57.0 from the termination of a power contract at our RockGen Energy Center. This income was offset primarily by $33.3 of foreign exchange transaction losses and $12.5 of letter of credit fees. The foreign exchange transaction losses recognized into income were mainly due to a strong Canadian dollar during 2003. In 2002 the primary contribution to other income was a $41.5 gain on the termination of a power sales agreement. See “Financial Market Risks” for a further discussion of our currency transaction losses.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Provision for income taxes |  | $ | 8.5 |  |  | $ | 10.8 |  |  | $ | 2.3 |  |  |  | 21.3 | %

During 2003, the effective tax rate decreased to 9.0% from 28.8% in 2002. This effective rate variance is due to the inclusion of significant permanent items in the calculation of the effective rate, which are fixed in

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amount and have a significant effect on the effective tax rates as such items become more material to net income.

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Discontinued operations, net of tax |  | $ | 15.0 |  |  | $ | 91.9 |  |  | $ | 76.9 |  |  |  | 83.7 | %

The 2003 discontinued operations activity included the effects of our sales of the Lost Pines 1 Power Project (in which we held a 50% undivided interest), and the sales of our Rocky Mountain gas reserves, Canadian natural gas reserves and petroleum assets, Alvin South Field oil and gas assets and our specialty data center engineering business. The sale of our interest in the Lost Pines 1 Power Project closed in January of 2004, and both the Rocky Mountain gas reserves and the Canadian natural gas reserves and petroleum assets closed in September of 2004. The 2002 discontinued operations activity included, in addition to all of the 2003 discontinued operations, the sales of DePere Energy Center, Drakes Bay Field, British Columbia and Medicine River oil and gas assets, all of which were completed by December 31, 2002; therefore, their results are not included in the 2003 activity. For more information about discontinued operations, see Note 10 of the Notes to Consolidated Financial Statements.

|  | 2003 |  |  | 2002 |  | $ Change |  |  | % Change |
Cumulative effect of a change in accounting principle, net of tax |  | $ | 180.9 |  |  | $ | — |  |  | $ | 180.9 |  |  |  | 100.0 | %

The gain from the cumulative effect of a change in accounting principle includes three items: (1) a gain of $181.9, net of tax effect, from the adoption of DIG Issue No. C20; (2) a loss of $1.5 associated with the adoption of FIN 46-R and the deconsolidation of the three Trusts which issued the HIGH TIDES. The loss of $1.5 represents the reversal of a gain, net of tax effect, recognized prior to the adoption of FIN 46-R on our repurchase of $37.5 of the value of HIGH TIDES by issuing shares of our common stock valued at $35.0; and (3) a gain of $0.5, net of tax effect, from the adoption of SFAS No. 143.

| Net Income

|  | 2003 |  |  | 2002 |  |  | $ Change |  |  | % Change |
Net income |  | $ | 282.0 |  |  | $ | 118.6 |  |  | $ | 163.4 |  |  |  | 137.8 | %

Our growing portfolio of operating power generation facilities contributed to a 13% increase in electric generation production for the year ended December 31, 2003, compared to the same period in 2002. Electric generation and marketing revenue increased 16.1% for the year ended December 31, 2003, as electricity and steam revenue increased by $1,442.9 or 44.6%, as a result of the higher production and higher electricity prices. This was partially offset by a decline in sales of purchased power for hedging and optimization. Operating results for the year ended December 31, 2003, reflect a decrease in average spark spreads per MWh compared with the same period in 2002. While we experienced an increase in realized electricity prices in 2003, this was more than offset by higher fuel expense. At the same time, higher realized oil and gas pricing resulted in an increase in oil and gas production margins compared to the prior period. In 2003 we recorded other revenue of $67.3 in connection with our settlement with Enron, primarily related to the termination of commodity contracts following the Enron bankruptcy.
Plant operating expense, interest expense and depreciation were higher due to the additional plants in operation. In 2003 generation did not increase commensurately with new average capacity coming on line (lower baseload capacity factor). Because of that and due to lower spark spreads per MWh, our spark spread margins did not keep pace with the additional operating and depreciation costs associated with the new capacity, and gross profit for the year ended December 31, 2003, decreased approximately 20.5%, compared to the same period in 2002. During 2003 overall financial results significantly benefited from $278.6 of net pre-tax gains recorded in connection with the repurchase of various issuances of debt and preferred securities at a discount, and a gain of $52.8 from the termination of the AMS power contract at the Acadia Energy Center, a gain of $57.0 from the termination of a power contract at the RockGen Energy Center, a gain of $62.2 from the sale of oil and gas assets to the CNGT and an after-tax gain of $180.9 due to the cumulative effect of changes in accounting principle.

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Liquidity and Capital Resources
Our business is capital intensive. Our ability to capitalize on growth opportunities and to service the debt we incurred in order to construct and operate our current fleet of power plants is dependent on the continued availability of capital on attractive terms. The availability of such capital in today’s environment is uncertain. To date, we have obtained cash from our operations; borrowings under credit facilities; issuances 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 financings. We have utilized this cash to fund our operations, service or prepay debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing, optimization and trading activities, and meet our other cash and liquidity needs. We also reinvest our cash from operations into our business development and construction program or use it to reduce debt, rather than to pay cash dividends. As discussed below, we have a liquidity-enhancing program underway for funding the completion of, and in some cases extending the completion of, the projects remaining in our current construction portfolio, for refinancing and for general corporate purposes.
In March 2004, we refinanced our $2.5 billion secured revolving construction financing facility through our CalGen subsidiary (formerly CCFC II) which was scheduled to mature in November 2004. CalGen completed a secured institutional term loans, notes and revolving credit facility financing, which replaced the old CCFC II facility. We realized total proceeds from the financing in the amount of $2.6 billion, before transaction costs and fees. As of December 31, 2004, there was an aggregate principal amount outstanding of $2.6 billion on the secured institutional term loans, notes and revolving credit facility.
In 2003 and 2004, we repurchased $1.2 billion of the outstanding principal amount of 2006 Convertible Senior Notes, with proceeds of financings we consummated in July 2003, through equity swaps and with the proceeds of our offering of 4.75% Contingent Convertible Senior Notes due 2023 (“2023 Convertible Senior Notes”) in November 2003 and January 2004. The repurchases were made in open market and privately negotiated transactions and, in February 2004, we initiated a cash tender offer for all of the outstanding 2006 Convertible Senior Notes for a price of par plus accrued interest. Approximately $409.4 million aggregate principal amount of the 2006 Convertible Senior Notes were tendered pursuant to the tender offer, for which we paid a total of $412.8 million (including accrued interest of $3.4 million). On December 27, 2004, we repurchased $70.8 million of the remaining outstanding 2006 Convertible Senior Notes for par plus accrued interest in connection with the holders’ exercise of their right to require us to repurchase their notes. At December 31, 2004, only $1.3 million in aggregate principal amount of 2006 Convertible Senior Notes remains outstanding.
In October 2004, all of our outstanding HIGH TIDES I and HIGH TIDES II were redeemed. At December 31, 2004, $517.5 million of principal amount of HIGH TIDES III remained outstanding, including $115.0 million held by Calpine. The HIGH TIDES III are scheduled to be remarketed no later than August 1, 2005. In the event of a failed remarketing, the relevant HIGH TIDES III 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. While a failed remarketing of our HIGH TIDES III would not have a material effect on our liquidity position, it would impact our calculation of diluted earnings per share (“EPS”) and increase our interest expense. Even with a successful remarketing, we would expect to have an increased dilutive impact on our EPS based on a revised conversion ratio. See Note 12 of the Notes to Consolidated Financial Statements for a summary of HIGH TIDES repurchased or redeemed by the Company through December 31, 2004.
See Note 12 of the Notes to Consolidated Condensed Financial Statement for more information related to other financings and repurchases of various issuances of debt in 2004.
We expect to have sufficient liquidity from cash flow from operations, borrowings available under lines of credit, access to sale/leaseback and project financing markets, sale or monetization of certain assets and cash balances to satisfy all obligations under our outstanding indebtedness, and to fund anticipated capital

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expenditures and working capital requirements for the next twelve months, but, as described above, we face several challenges over the next two to three years as our cash requirements (including our refinancing obligations) are expected to exceed our unrestricted cash on hand and cash from operations. Accordingly, we have in place a liquidity-enhancing program which includes possible sales or monitizations of certain of our assets, and whether we will have sufficient liquidity will depend, to a certain extent, on the success of that program. On December 31, 2004, our liquidity totaled approximately $1.6 billion. This includes cash and cash equivalents on hand of $0.8 billion, current portion of restricted cash of approximately $0.6 billion and approximately $0.2 billion of borrowing capacity under our various credit facilities.
Factors that could affect our liquidity and capital resources are also discussed below in “Capital Spending” and above in Item 1. “Business — Risk Factors.”
Cash Flow Activities — The following table summarizes our cash flow activities for the periods indicated:

|  | Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |
|  | (In thousands) |
Beginning cash and cash equivalents |  | $ | 991,806 |  |  | $ | 579,486 |  |  | $ | 1,594,144 |
Net cash provided by: |  |  |  |  |  |  |  |  |  |  |  |
| Operating activities |  | $ | 9,895 |  |  | $ | 290,559 |  |  | $ | 1,068,466 |
| Investing activities |  |  | (401,426 | ) |  |  | (2,515,365 | ) |  |  | (3,837,827 | )
| Financing activities |  |  | 167,052 |  |  |  | 2,623,986 |  |  |  | 1,757,396 |
| Effect of exchange rates changes on cash and cash equivalents |  |  | 16,101 |  |  |  | 13,140 |  |  |  | (2,693 | )
| Net increase (decrease) in cash and cash equivalents |  | $ | (208,378 | ) |  | $ | 412,320 |  |  | $ | (1,014,658 | )
Ending cash and cash equivalents |  | $ | 783,428 |  |  | $ | 991,806 |  |  | $ | 579,486 |

Operating activities for the year ended December 31, 2004, provided net cash of $9.9 million, compared to $290.6 million for the same period in 2003. Operating cash flows in 2004 benefited from the receipt of $100.6 million from the termination of power purchase agreements for two of our New Jersey power plants and $16.4 million from the restructuring of a long-term gas supply contract. During the year ended December 31, 2004, operating assets and liabilities used approximately $137.6 million, as compared to having used $609.8 million in the same period in 2003. Uses of funds included accounts receivable, which increased by $99.4 million as our total revenues in 2004 (after the netting of approximately $1.7 billion of purchase power expense with sales of purchased power pursuant to EITF Issue No. 03-11) increased by approximately $358.9 million. Also, cash operating lease payments exceeded recognized expense by $83.7 million and accrued liabilities were reduced, through payments, for sales and property taxes and net margin deposits posted to support CES trading activity increased by $60.9 million. These uses of funds were partially offset by an increase of $231.8 million in accounts payable and accrued expense (including an increase in interest expense payable of $64.5 million). The increase in such deposits, which serve as collateral for certain of our commodity transactions that have a net exposure to a counterparty on a mark-to-market basis, is reflective of movements in commodity prices and a higher mix of margin deposits posted relative to letters of credit.
Investing activities for the year ended December 31, 2004, consumed net cash of $401.4 million, as compared to $2,515.4 million in the same period of 2003. Capital expenditures for the completion of our power facilities decreased in 2004, as there were fewer projects under construction. Investing activities in 2004 reflect the receipt of $148.6 million from the sale of our 50% interest in the Lost Pines I Power Plant, $626.6 million from the sale of our Canadian oil and gas reserves, $218.7 million from the sale of our Rocky Mountain oil and gas reserves, plus $85.4 million of proceeds from the sale of a subsidiary holding power purchase agreements for two of our New Jersey power plants. We also reported a $181.0 million increase in cash used for acquisitions in 2004 compared to 2003, as we used the proceeds from the Lost Pines sale and cash to purchase the Los Brazos Power Plant, and we used cash on hand to purchase the remaining 50% interest in the Aries

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Power Plant and the remaining 20% interest in Calpine Cogeneration Corporation. Also, we used $110.6 million to purchase a portion of HIGH TIDES III outstanding and provided $210.8 million by decreasing restricted cash during 2004.
Financing activities for the year ended December 31, 2004, provided net cash of $167.1 million, compared to $2,624.0 million in the prior year. We continued our refinancing program in 2004 by raising $2.6 billion to refinance $2.5 billion of CalGen project financing before payment for fees and expenses of the refinancing. In 2004 we also raised $250 million from the issuance of the 2023 Convertible Senior Notes pursuant to an option exercise by one of the initial purchasers and $617.5 from the issuance of the 2014 Convertible Notes. We raised $878.8 million from the issuance of Senior Notes, $360.0 million from a preferred security offering and $1,179.4 million from various project financings. Also, we repaid $635.4 million in project financing debt, and we used $657.7 million to repurchase the outstanding 2006 Convertible Senior Notes that could be put to us in December 2004. We used $177.0 million to repurchase a portion of the 2023 Convertible Senior Notes, $871.3 million to repay and repurchase various Senior Notes and $483.5 million to redeem the remainder of HIGH TIDES I and II. In 2003, cash inflows primarily included $3.9 billion from the issuance of senior secured notes and institutional term loans, $802.2 million from the PCF financing transaction, $785.5 million from the refinancing of our CCFC I credit facility, $301.7 million from the issuance of secured notes by our wholly owned subsidiary Gilroy Energy Center, LLC (“GEC”), $159.7 million from secondary trust unit offerings from our CPIF, $82.8 million from the monetization of one of our PSAs, $244.0 million from the sales of preferred interests in the cash flows from certain of our facilities and additional borrowings under our revolvers. This was partially offset by financing costs and $5.0 billion in debt repayments and repurchases.
Liquidity and Finance Program Update — Enhancing liquidity, reducing corporate debt and addressing near-term debt maturities continued to drive our financing program in 2004. During the year, we successfully enhanced our financial position through a significant number of transactions:

| • | Refinanced CCFC II project debt through the issuance of $2.6 billion of Calpine Generating Company secured institutional term loans, notes and revolving credit facility;
| • | Completed approximately $2.1 billion of liquidity transactions including the sale of our Canadian and certain U.S. natural gas reserves for $870.1 million;
| • | Redeemed in full $598.5 million of HIGH TIDES I and II, and purchased a portion of HIGH TIDES III, totaling $115.0 million; and
| • | Repurchased approximately $1.8 billion of existing corporate debt, resulting in a net gain of $246.9 million after the write-off of unamortized discounts and deferred financing costs.

Also, in early 2005, we:

| • | Obtained a $100 million, non-recourse credit facility to complete construction of the Metcalf Energy Center in San Jose, California. This was the first single-asset, merchant project financing in California since the 2000-2001 energy crisis;
| • | Received funding on Calpine European Funding (Jersey) Limited’s $260 million offering of Redeemable Preferred Shares due on July 30, 2005. The net proceeds from this offering will ultimately be used as permitted by our existing bond indentures;
| • | Completed a $400 million, 25-year, non-recourse sale/leaseback transaction for the 560-MW Fox Energy Center under construction in Kaukauna, Wisconsin; and
| • | Completed a $195 million, non-recourse project financing for construction of the 525-MW Valladolid III Energy Center in Valladolid, Mexico.

Our liquidity constraints have delayed the pace at which we have developed our oil and gas proved undeveloped (“PUD”) reserves from what we would otherwise have preferred; however, given the current demand for low risk PUD drilling opportunities, we expect the Company to be able to secure third-party funding of capital expenditures through farm-outs, joint ventures and similar arrangements in amounts sufficient to develop our PUD properties in a manner that preserves their projected value. As part of any such

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farm-out, joint venture or similar arrangement, we would typically be required to convey a portion of our interest in the relevant properties to the third party in exchange for the third party’s commitment to fund capital expenditures. These conveyances to third parties will reduce the amount of PUDs and other undeveloped assets owned by us.
So long as we are successful in obtaining such third-party funding at levels projected, we expect to have sufficient capital resources available to preserve, protect and enhance the value of our existing PUD reserves, subject to any reduction in our interests due to conveyances as part of the third-party funding arrangements described above. Taking into account the funding we expect to obtain through farm-outs, joint ventures and similar arrangements, we believe that capital expenditures will be consistent with the levels and development schedule we have disclosed.
Counterparties and Customers — Our customer and supplier base is concentrated within the energy industry. Additionally, we have exposure to trends within the energy industry, including declines in the creditworthiness of our marketing counterparties. Currently, multiple companies within the energy industry are in bankruptcy or have below investment grade credit ratings. However, we do not currently have any significant exposures to counterparties that are not paying on a current basis.
Letter of Credit Facilities — At December 31, 2004 and 2003, we had approximately $586.5 million and $410.8 million, respectively, in letters of credit outstanding under various credit facilities to support our risk management and other operational and construction activities. Of the total letters of credit outstanding, $233.3 million and $272.1 million, respectively, were in aggregate issued under the cash collateralized letter of credit facility and the corporate revolving credit facility at December 31, 2004 and 2003, respectively.
Commodity Margin Deposits and Other Credit Support — As of December 31, 2004 and 2003, to support commodity transactions we had deposited net amounts of $248.9 million and $188.0 million, respectively, in cash as margin deposits with third parties, and we made gas and power prepayments of $78.0 million, and $60.6 million, respectively, and had letters of credit outstanding of $115.9 million and $14.5 million, respectively. We use margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market. While we believe that we have adequate liquidity to support our operations at this time, it is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations.
Revised Capital Expenditure Program — Following a comprehensive review of our power plant development program, we announced in January 2002 the adoption of a revised capital expenditure program which contemplated the completion of 27 power projects (representing 15,200 MW) then under construction. As of December 31, 2004, 24 of these facilities have subsequently achieved full or partial commercial operation. Construction of advanced stage development projects is expected to proceed only when there is an established market need through power purchase agreements for additional generating resources at prices that will allow us to meet our investment criteria, and when capital is available to us on attractive terms. Our entire development and construction program is flexible and subject to continuing review and revision based upon such criteria. Since the adoption of the revised capital expenditure program, we have added several projects now in development and construction and, currently, work on three construction projects, Hillabee, Washington Parish and Fremont, has been largely postponed until market conditions improve in the Southeast and Midwest market areas. See “Capital Spending — Development and Construction” below for more information on our capital expenditure program.
Asset Sales — As a result of the significant contraction in the availability of capital for participants in the energy sector, we have adopted a strategy of conserving our core strategic assets and disposing of certain less strategically important assets, which serves primarily to strengthen our balance sheet through repayment of debt. Set forth below are the completed asset disposals:
On January 15, 2004, we completed the sale of our 50-percent undivided interest in the 545-megawatt Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the Lower Colorado River Authority.

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Under the terms of the agreement, we received a cash payment of $148.6 million and recorded a pre-tax gain of $35.3 million. We subsequently closed on the purchase of the Brazos Valley Power Plant for approximately $181.1 million in a tax deferred like-kind exchange under IRS Section 1031, largely with the proceeds of the Lost Pines I Power Project sale.
On February 18, 2004, one of our wholly owned subsidiaries closed on the sale of natural gas properties to CNGT. We received net consideration of Cdn$38.8 million ($29.2 million) and recorded a pre-tax gain of approximately $6.8 million.
On September 1, 2004, in combination with CNGLP, a Delaware limited partnership, we completed the sale of our Rocky Mountain gas reserves that were primarily concentrated in two geographic areas: the Colorado Piceance Basin and the New Mexico San Juan Basin. Together, these assets represent approximately 120 Bcfe of proved gas reserves, producing approximately 16.3 Mmcfe per day of gas. Under the terms of the agreement we received net cash payments of approximately $218.7 million, and recorded a pre-tax gain of approximately $103.7 million.
On September 2, 2004, we completed the sale of our Canadian natural gas reserves and petroleum assets. These Canadian assets represented approximately 221 Bcfe of proved reserves, producing approximately 61 Mmcfe per day. Included in this sale was our 25% interest in approximately 80 Bcfe of proved reserves (net of royalties) and 32 Mmcfe per day of production owned by CNGT. Under the terms of the agreement, we received cash payments of approximately Cdn$802.9 million, or approximately $622.2 million. We recorded a pre-tax gain of approximately $100.6 million on the sale of our Canadian assets.
We are also evaluating the potential sale of our Saltend Energy Centre. We acquired the 1,200-MW power plant, located in Hull, England, in August 2001 for approximately $800 million. Net proceeds from any sale of the facility would be used to redeem the existing $360 million Two-Year Redeemable Preferred Shares and then to redeem the $260 million Redeemable Preferred Shares Due July 30, 2005. Any remaining proceeds would be used in accordance with the asset sale provisions of our existing bond indentures.
We believe that our completion of the financing and liquidity transactions described above in the current difficult conditions affecting capital availability in the market, and our sector in particular, demonstrate our probable ability to raise capital on acceptable terms in the future, although availability of capital has tightened significantly throughout the power generation industry and, therefore, there can be no assurance that we will have access to capital in the future as and when we may desire.
Credit Considerations — On September 23, 2004, 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 they rate 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.
Performance Indicators — We believe the following factors are important in assessing our ability to continue to fund our growth in the capital markets: (a) our debt-to-capital ratio; (b) various interest coverage ratios; (c) our credit and debt ratings by the rating agencies; (d) the trading prices of our senior notes in the capital markets; (e) the price of our common stock on The New York Stock Exchange; (f) our anticipated capital requirements over the coming quarters and years; (g) the profitability of our operations; (h) the non-GAAP financial measures and other performance metrics discussed in “Performance Metrics” below; (i) our

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cash balances and remaining capacity under existing revolving credit construction and general purpose credit facilities; (j) compliance with covenants in existing debt facilities; (k) progress in raising new or replacement capital; and (l) the stability of future contractual cash flows.
Off-Balance Sheet Commitments — In accordance with SFAS No. 13 and SFAS No. 98, “Accounting for Leases” our operating leases, which include certain sale/leaseback transactions, are not reflected on our balance sheet. All counterparties in these transactions are third parties that are unrelated to us except as disclosed for Acadia in Note 7 of the Notes to Consolidated Financial Statements. The sale/leaseback transactions utilize special-purpose entities formed by the equity investors with the sole purpose of owning a power generation facility. Some of our operating leases contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance debt instruments. We guarantee $ billion of the total future minimum lease payments of our consolidated subsidiaries related to our operating leases. We have no ownership or other interest in any of these special-purpose entities. See Note 22 of the Notes to Consolidated Financial Statements for the future minimum lease payments under our power plant operating leases.
In accordance with Accounting Principles Board (“APB”) Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FIN 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18),” the debt on the books of our unconsolidated investments in power projects is not reflected on our balance sheet (see Note 7 of the Notes to Consolidated Financial Statements). At December 31, 2004, investee debt was approximately $126.3 million. Of the $126.3 million, $60.3 million related to our investment in AELLC, for which we used the cost method of accounting as of December 31, 2004. Based on our pro rata ownership share of each of the investments, our share would be approximately $43.3 million, which includes our share for AELLC of $19.5 million. Please see Note 7 of the Notes to Consolidated Financial Statements for more information on the cost method of accounting used for AELLC. However, all such debt is non-recourse to us. For the Aries Power Plant construction debt, Aquila Inc. and Calpine provided support arrangements until construction was completed to cover any cost overruns. See Note 7 of the Notes to Consolidated Financial Statements for additional information on our equity method and cost method unconsolidated investments in power projects and oil and gas properties.
Commercial Commitments — Our primary commercial obligations as of December 31, 2004, are as follows (in thousands):

|  | Amounts of Commitment Expiration per Period |
|  |  |  | Total |
|  |  |  | Amounts |
Commercial Commitments |  | 2005 |  |  | 2006 |  |  | 2007 |  |  | 2008 |  |  | 2009 |  |  | Thereafter |  |  | Committed |
Guarantee of subsidiary debt |  | $ | 18,333 |  |  | $ | 16,284 |  |  | $ | 18,798 |  |  | $ | 1,930,657 |  |  | $ | 19,848 |  |  | $ | 1,133,896 |  |  | $ | 3,137,817 |
Standby letters of credit |  |  | 579,607 |  |  |  | 3,641 |  |  |  | 2,802 |  |  |  | 400 |  |  |  | — |  |  |  | — |  |  |  | 586,450 |
Surety bonds |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 12,531 |  |  |  | 12,531 |
Guarantee of subsidiary operating lease payments |  |  | 83,169 |  |  |  | 81,772 |  |  |  | 82,487 |  |  |  | 115,604 |  |  |  | 113,977 |  |  |  | 1,163,783 |  |  |  | 1,640,792 |
| Total |  | $ | 681,109 |  |  | $ | 101,697 |  |  | $ | 104,087 |  |  | $ | 2,046,661 |  |  | $ | 133,825 |  |  | $ | 2,310,210 |  |  | $ | 5,377,589 |

Our commercial commitments primarily include guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments. The debt guarantees consist of parent guarantees for the finance subsidiaries and project financing for the Broad River Energy Center and the Pasadena Power Plant. The debt guarantees and operating lease payments are also included in the contractual obligations table above. We also issue guarantees for normal course of business activities.
We have guaranteed the principal payment of $2,139.7 million and $2,448.6 million, respectively, of senior notes as of December 31, 2004 and 2003, for two wholly owned finance subsidiaries of Calpine, Calpine Canada Energy Finance ULC and Calpine Canada Energy Finance II ULC. As of December 31, 2004, we have guaranteed $275.1 million and $72.4 million, respectively, of project financing for the Broad River

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Energy Center and Pasadena Power Plant and $291.6 million and $71.8 million, respectively, as of December 31, 2003, for these power plants. In 2004 and 2003 we have debenture obligations in the amount of $517.5 million and $1,153.5 million, respectively, the payment of which will fund the obligations of the Trusts (see Note 12 for more information). We agreed to indemnify Duke Capital Corporation $101.4 million and $101.7 million as of December 31, 2004 and 2003, respectively, in the event Duke Capital Corporation is required to make any payments under its guarantee of the lease of the Hidalgo Energy Center. As of December 31, 2004 and 2003, we have also guaranteed $31.7 million and $35.6 million, respectively, of other miscellaneous debt. All of the guaranteed debt is recorded on our Consolidated Balance Sheet.
Contractual Obligations — Our contractual obligations as of December 31, 2004, are as follows (in thousands):

|  | 2005 |  |  | 2006 |  |  | 2007 |  |  | 2008 |  |  | 2009 |  |  | Thereafter |  |  | Total |
Other Contractual Obligations |  | $ | 60,418 |  |  | $ | 7,995 |  |  | $ | 2,089 |  |  | $ | 2,096 |  |  | $ | 2,500 |  |  | $ | 85,408 |  |  | $ | 160,506 |
Total operating lease obligations(1) |  | $ | 266,399 |  |  | $ | 252,511 |  |  | $ | 252,849 |  |  | $ | 250,238 |  |  | $ | 244,601 |  |  | $ | 2,321,106 |  |  | $ | 3,588,199 |
Debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unsecured Senior Notes(2) |  | $ | 705,949 |  |  | $ | 264,258 |  |  | $ | 360,878 |  |  | $ | 1,968,660 |  |  | $ | 221,539 |  |  | $ | 1,273,333 |  |  | $ | 4,794,617 |
Second Priority Senior Secured Notes(2) |  |  | 12,500 |  |  |  | 12,500 |  |  |  | 1,209,375 |  |  |  | — |  |  |  | — |  |  |  | 2,443,150 |  |  |  | 3,677,525 |
First Priority Senior Secured Notes(2) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 778,971 |  |  |  | 778,971 |
| Total Senior Notes |  | $ | 718,449 |  |  | $ | 276,758 |  |  | $ | 1,570,253 |  |  | $ | 1,968,660 |  |  | $ | 221,539 |  |  | $ | 4,495,454 |  |  | $ | 9,251,113 |
CCFC 1(4) |  |  | 3,208 |  |  |  | 3,208 |  |  |  | 3,208 |  |  |  | 3,208 |  |  |  | 365,349 |  |  |  | 408,569 |  |  |  | 786,750 |
CALGEN(4) |  |  | — |  |  |  | — |  |  |  | 4,174 |  |  |  | 12,050 |  |  |  | 829,875 |  |  |  | 1,549,233 |  |  |  | 2,395,332 |
Convertible Senior Notes Due 2006, 2014 and 2023(2) |  |  | — |  |  |  | 1,326 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,253,972 |  |  |  | 1,255,298 |
Notes payable and borrowings under lines of credit(4)(5) |  |  | 197,016 |  |  |  | 188,756 |  |  |  | 143,962 |  |  |  | 104,555 |  |  |  | 106,221 |  |  |  | 108,277 |  |  |  | 848,787 |
Notes payable to Calpine Capital Trusts(2) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 517,500 |  |  |  | 517,500 |
Preferred interests(4) |  |  | 8,641 |  |  |  | 369,480 |  |  |  | 8,990 |  |  |  | 12,236 |  |  |  | 16,228 |  |  |  | 90,962 |  |  |  | 506,537 |
Capital lease obligation(4) |  |  | 5,490 |  |  |  | 6,538 |  |  |  | 7,428 |  |  |  | 9,765 |  |  |  | 10,925 |  |  |  | 248,773 |  |  |  | 288,919 |
Construction/project financing(4)(6) |  |  | 93,393 |  |  |  | 89,355 |  |  |  | 103,423 |  |  |  | 100,340 |  |  |  | 105,299 |  |  |  | 1,507,241 |  |  |  | 1,999,051 |
| Total debt(5)(9)(3) |  | $ | 1,026,197 |  |  | $ | 935,421 |  |  | $ | 1,841,438 |  |  | $ | 2,210,814 |  |  | $ | 1,655,436 |  |  | $ | 10,179,981 |  |  | $ | 17,849,287 |
Interest payments on debt obligations |  | $ | 1,473,629 |  |  | $ | 1,462,291 |  |  | $ | 1,356,035 |  |  | $ | 1,130,214 |  |  | $ | 1,003,534 |  |  | $ | 3,422,874 |  |  | $ | 9,848,577 |
Interest rate swap agreement payments |  |  | 20,964 |  |  |  | 13,945 |  |  |  | 11,770 |  |  |  | 10,051 |  |  |  | 9,036 |  |  |  | 14,102 |  |  |  | 79,868 |
Purchase obligations: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Turbine commitments |  |  | 27,463 |  |  |  | 4,862 |  |  |  | 977 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 33,302 |
Commodity purchase obligations(7) |  |  | 1,659,425 |  |  |  | 1,071,778 |  |  |  | 965,222 |  |  |  | 805,946 |  |  |  | 680,345 |  |  |  | 1,003,102 |  |  |  | 6,185,818 |
Land leases |  |  | 4,592 |  |  |  | 4,786 |  |  |  | 4,967 |  |  |  | 5,504 |  |  |  | 5,998 |  |  |  | 375,114 |  |  |  | 400,961 |
Long-term service agreements |  |  | 73,541 |  |  |  | 93,675 |  |  |  | 120,385 |  |  |  | 74,448 |  |  |  | 70,544 |  |  |  | 710,137 |  |  |  | 1,142,730 |
Costs to complete construction projects |  |  | 699,174 |  |  |  | 449,312 |  |  |  | 189,806 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,338,292 |
Other purchase obligations |  |  | 55,202 |  |  |  | 26,853 |  |  |  | 25,481 |  |  |  | 25,172 |  |  |  | 24,985 |  |  |  | 470,524 |  |  |  | 628,217 |
| Total purchase obligations(8) |  | $ | 2,469,397 |  |  | $ | 1,651,266 |  |  | $ | 1,306,838 |  |  | $ | 911,070 |  |  | $ | 781,872 |  |  | $ | 2,558,877 |  |  | $ | 9,729,320 |

| (1) | Included in the total are future minimum payments for power plant operating leases, office and equipment leases and two tolling agreements with Acadia Energy Center accounted for as leases (See Note 7 of the Notes to Consolidated Financial Statements for more information).
| (2) | An obligation of or with recourse to Calpine Corporation.

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| (3) | The table above does not reflect the repurchases of $80.6 million convertible Senior Notes and Senior Notes subsequent to December 31, 2004.
| (4) | Structured as an obligation(s) of certain subsidiaries of Calpine Corporation without recourse to Calpine Corporation. However, default on these instruments could potentially trigger cross-default provisions in certain other debt instruments.
| (5) | A note payable totaling $125.5 million associated with the sale of the PG&E note receivable to a third party is excluded from notes payable and borrowings under lines of credit for this purpose as it is a noncash liability. If the $125.5 million is summed with the $848.8 (total notes payable and borrowings under lines of credit) million from the table above, the total notes payable and borrowings under lines of credit would be $974.3 million, which agrees to the Consolidated Balance Sheet sum of the current and long-term notes payable and borrowings under lines of credit balances on the Consolidated Balance Sheet. See Note 8 of the Notes to Consolidated Financial Statements for more information concerning this note. Total debt of $17,849.3 million from the table above summed with the $125.5 million totals $17,974.8 million, which agrees to the total debt amount in Note 11 of the Notes to Consolidated Financial Statements.
| (6) | Included in the total are guaranteed amounts of $275.1 million and $282.9 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant.
| (7) | The amounts presented here include contracts for the purchase, transportation, or storage of commodities accounted for as executory contracts or normal purchase and sales and, therefore, not recognized as liabilities on our Consolidated Balance Sheet. See “Financial Market Risks” for a discussion of our commodity derivative contracts recorded at fair value on our Consolidated Balance Sheet.
| (8) | The amounts included above for purchase obligations include the minimum requirements under contract. Also included in purchase obligations are employee agreements. Agreements that we can cancel without significant cancellation fees are excluded.
| (9) | See Item 1. “Business — Risk Factors” for a discussion of the estimated amount of debt that must be repurchased pursuant to our indentures.

(10) | Interest payments on debt obligations have not been decreased for the requirement to repurchase or redeem approximately $520 million of indebtedness, per current estimates, pursuant to our indentures, as the specific debt instruments are not known. However, the $520 million of indebtedness is reflected in this table as due in 2005.

Debt securities repurchased by Calpine during 2004 and 2003 totaled $1,668.3 million and $1,853.4 million, respectively, in aggregate outstanding principal amount for a repurchase price of $1,394.0 million and $1,575.3 million, respectively, plus accrued interest. In 2004 we recorded a pre-tax gain on these transactions in the amount of $274.4 million which was $254.8 million, net of write-offs of $19.1 million of unamortized deferred financing costs and $0.5 million of unamortized premiums or discounts. In 2003 we recorded a pre-tax gain on these transactions in the amount of $278.1 million, which was $256.9 million, net of write-offs of $18.9 million of unamortized deferred financing costs and $2.3 million of unamortized premiums or discounts. HIGH TIDES III repurchased by Calpine during 2004 totaled $115.0 million in aggregate outstanding principle amount at a repurchase price of $111.6 million plus accrued interest. These exchanged HIGH TIDES III are reflected on the balance sheets as an asset, versus being netted against the balance outstanding,

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due to the deconsolidation of the Calpine Capital Trusts, which issued the HIGH TIDES III, upon the adoption of FIN 46-R. The following table summarizes the total debt securities repurchased (in millions):

|  | 2004 |  |  | 2003 |
|  | Principal |  |  | Amount |  |  | Principal |  |  | Amount |
Debt Security and HIGH TIDES |  | Amount |  |  | Paid |  |  | Amount |  |  | Paid |
2006 Convertible Senior Notes |  | $ | 658.7 |  |  | $ | 657.7 |  |  | $ | 474.9 |  |  | $ | 458.8 |
2023 Convertible Senior Notes |  |  | 266.2 |  |  |  | 177.0 |  |  |  | — |  |  |  | — |
81/4% Senior Notes Due 2005 |  |  | 38.9 |  |  |  | 34.9 |  |  |  | 25.0 |  |  |  | 24.5 |
101/2% Senior Notes Due 2006 |  |  | 13.9 |  |  |  | 12.4 |  |  |  | 5.2 |  |  |  | 5.1 |
75/8% Senior Notes Due 2006 |  |  | 103.1 |  |  |  | 96.5 |  |  |  | 35.3 |  |  |  | 32.5 |
83/4% Senior Notes Due 2007 |  |  | 30.8 |  |  |  | 24.4 |  |  |  | 48.9 |  |  |  | 45.0 |
77/8% Senior Notes Due 2008 |  |  | 78.4 |  |  |  | 56.5 |  |  |  | 74.8 |  |  |  | 58.3 |
81/2% Senior Notes Due 2008 |  |  | 344.3 |  |  |  | 249.4 |  |  |  | 48.3 |  |  |  | 42.3 |
83/8% Senior Notes Due 2008 |  |  | 6.1 |  |  |  | 4.0 |  |  |  | 59.2 |  |  |  | 46.6 |
73/4% Senior Notes Due 2009 |  |  | 11.0 |  |  |  | 8.1 |  |  |  | 97.2 |  |  |  | 75.9 |
85/8% Senior Notes Due 2010 |  |  | — |  |  |  | — |  |  |  | 210.4 |  |  |  | 170.7 |
81/2% Senior Notes Due 2011 |  |  | 116.9 |  |  |  | 73.1 |  |  |  | 648.4 |  |  |  | 521.3 |
87/8% Senior Notes Due 2011 |  |  | — |  |  |  | — |  |  |  | 125.8 |  |  |  | 94.3 |
HIGH TIDES III |  |  | 115.0 |  |  |  | 111.6 |  |  |  | — |  |  |  | — |
|  | $ | 1,783.3 |  |  | $ | 1,505.6 |  |  | $ | 1,853.4 |  |  | $ | 1,575.3 |

During 2004 we exchanged 24.3 million shares of Calpine common stock in privately negotiated transactions for approximately $115.0 million par value of HIGH TIDES I and HIGH TIDES II. During 2003, debt securities, exchanged for 23.5 million shares of Calpine common stock in privately negotiated transactions, totaled $145.0 million in aggregate outstanding principal amount plus accrued interest. We recorded a pre-tax gain on these transactions in the amount of $20.2 million, net of write-offs of unamortized deferred financing costs and the unamortized premiums or discounts. Additionally, during 2003, we exchanged 6.5 million shares of Calpine common stock in privately negotiated transactions for approximately $37.5 million par value of HIGH TIDES I. These repurchased HIGH TIDES I were reflected on the balance sheet as an asset, versus being netted against the balance outstanding, due to the deconsolidation of the Trusts, which issued the HIGH TIDES, upon the adoption of FIN 46-R.
On October 20, 2004, the Company repaid $636 million of convertible subordinate debentures held by Calpine Capital Trusts which used those proceeds to redeem its outstanding HIGH TIDES I and HIGH TIDES II. The redemption of the HIGH TIDES I and HIGH TIDES II included securities previously purchased and held by the Company and resulted in a realized gain of approximately $6.1 million.
The following table summarizes the total debt securities and HIGH TIDES exchanged for common stock (in millions):

|  | 2004 |  |  | 2003 |
|  |  |  | Common |  |  |  |  | Common |
|  | Principal |  |  | Stock |  |  | Principal |  |  | Stock |
Debt Securities and HIGH TIDES |  | Amount |  |  | Issued |  |  | Amount |  |  | Issued |
2006 Convertible Senior Notes |  | $ | — |  |  |  | — |  |  | $ | 65.0 |  |  |  | 12.0 |
81/2% Senior Notes Due 2008 |  |  | — |  |  |  | — |  |  |  | 55.0 |  |  |  | 8.1 |
81/2% Senior Notes Due 2011 |  |  | — |  |  |  | — |  |  |  | 25.0 |  |  |  | 3.4 |
HIGH TIDES I |  |  | 40.0 |  |  |  | 8.5 |  |  |  | 37.5 |  |  |  | 6.5 |
HIGH TIDES II |  |  | 75.0 |  |  |  | 15.8 |  |  |  | — |  |  |  | — |
|  | $ | 115.0 |  |  |  | 24.3 |  |  | $ | 182.5 |  |  |  | 30.0 |

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Debt Covenant and Indenture Compliance
Our senior notes indentures and our credit facilities contain financial and other restrictive covenants that limit or prohibit our ability to incur indebtedness, make prepayments on or purchase indebtedness in whole or in part, pay dividends, make investments, lease properties, engage in transactions with affiliates, create liens, consolidate or merge with another entity or allow one of our subsidiaries to do so, sell assets, and acquire facilities or other businesses. We are currently in compliance with all of such financial and other restrictive covenants, except as discussed below. Any failure to comply could give holders of debt under the relevant instrument the right to accelerate the maturity of all debt outstanding thereunder if the default was not cured or waived. In addition, holders of debt under other instruments typically would have cross-acceleration provisions, which would permit them also to elect to accelerate the maturity of their debt if another debt instrument was accelerated upon the occurrence of such an uncured event of default.
Indenture Compliance — Our various indentures place conditions on our ability to issue indebtedness, including further limitations on the issuance of additional debt if our interest coverage ratio (as defined in the various indentures) is below 2:1. Currently, our interest coverage ratio (as so defined) is below 2:1 and, consequently, our indentures generally would not allow us to issue new debt, except for (i) certain types of new indebtedness that refinances or replaces existing indebtedness, and (ii) non-recourse debt and preferred equity interests issued by our subsidiaries for purposes of financing certain types of capital expenditures, including plant development, construction and acquisition expenses. In addition, if and so long as our interest coverage ratio is below 2:1, our indentures will limit our ability to invest in unrestricted subsidiaries and non-subsidiary affiliates and make certain other types of restricted payments. Moreover, certain of our indentures will prohibit any further investments in non-subsidiary affiliates if and for so long as our interest coverage ratio (as defined therein) is below 1.75:1 and, as of December 31, 2004, such interest coverage ratio had fallen below 1.75:1.
In September 2004, we resolved a dispute with Credit Suisse First Boston (“CSFB”), by amending and restating a Letter of Credit and Reimbursement Agreement pursuant to which CSFB issues a letter of credit with a maximum face amount of $78.3 million for our account. CSFB had previously advised us that it believed that we may have failed to comply with certain covenants under the Letter of Credit and Reimbursement Agreement related to our ability to incur indebtedness and grant liens.
Calpine has guaranteed the payment of a portion of the rents due under the lease of the Greenleaf generating facilities in California, which lease is between an owner trustee acting on behalf of Union Bank of California, as lessor, and a Calpine subsidiary, Calpine Greenleaf, Inc., as lessee. Calpine does not currently meet the requirements of a financial covenant contained in the guarantee agreement. The lessor has waived this non-compliance through April 30, 2005, and Calpine is currently in discussions with the lessor concerning the possibility of modifying the lease and/or Calpine’s guarantee thereof so as to eliminate or modify the covenant in question. In the event the lessor’s waiver were to expire prior to completion of this amendment, the lessor could at that time elect to accelerate the payment of certain amounts owing under the lease, totaling approximately $15.9 million. In the event the lessor were to elect to require Calpine to make this payment, the lessor’s remedy under the guarantee and the lease would be limited to taking steps to collect damages from Calpine; the lessor would not be entitled to terminate or exercise other remedies under the Greenleaf lease.
In connection with several of our subsidiaries’ lease financing transactions (Greenleaf, Pasadena, Broad River, RockGen and South Point) the insurance policies we have in place do not comply in every respect with the insurance requirements set forth in the financing documents. We have requested from the relevant financing parties, and are expecting to receive, waivers of this noncompliance. While failure to have the required insurance in place is listed in the financing documents as an event of default, the financing parties may not unreasonably withhold their approval of our waiver request so long as the required insurance coverage is not reasonably available or commercially feasible and we deliver a report from our insurance consultant to that effect. We have delivered the required insurance consultant reports to the relevant financing parties and therefore anticipate that the necessary waivers will be executed shortly.
We own a 32.3% interest in AELLC. AELLC owns the 136 MW Androscoggin Energy Center located in Maine and is a joint venture between us, and affiliates of Wisvest Corporation and IP. AELLC had

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construction debt of $60.3 million outstanding as of December 31, 2004. The debt is non-recourse to Calpine Corporation (the “AELLC Non-Recourse Financing”). On November 3, 2004, a jury verdict was rendered against AELLC in a breach of contract dispute with IP. See Note 25 of the Notes to Consolidated Financial Statements for more information about this legal proceeding. We recorded our $11.6 million share of the award amount in the third quarter of 2004. On November 26, 2004, AELLC filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. As a result of the bankruptcy, we lost significant influence and control of the project and have adopted the cost method of accounting for our investment in Androscoggin. Also, in December 2004, we determined that our investment in Androscoggin was impaired and recorded a $5.0 million impairment charge.
Unrestricted Subsidiaries — The information in this paragraph is required to be provided under the terms of the indentures and credit agreement governing the various tranches of our second-priority secured indebtedness (collectively, the “Second Priority Secured Debt Instruments”). We have designated certain of our subsidiaries as “unrestricted subsidiaries” under the Second Priority Secured Debt Instruments. A subsidiary with “unrestricted” status thereunder generally is not required to comply with the covenants contained therein that are applicable to “restricted subsidiaries.” The Company has designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as “unrestricted subsidiaries” for purposes of the Second Priority Secured Debt Instruments. The following table sets forth selected balance sheet information of Calpine Corporation and restricted subsidiaries and of such unrestricted subsidiaries at December 31, 2004, and selected income statement information for the year ended December 31, 2004 (in thousands):

|  | Calpine |  |  |  |  |  |  |
|  | Corporation |  |  |  |  |  |  |
|  | and Restricted |  |  | Unrestricted |  |  |  |  |
|  | Subsidiaries |  |  | Subsidiaries |  |  | Eliminations |  |  | Total |
Assets |  | $ | 27,020,662 |  |  | $ | 438,955 |  |  | $ | (224,385 | ) |  | $ | 27,235,232 |
Liabilities |  | $ | 22,000,516 |  |  | $ | 253,598 |  |  | $ | — |  |  | $ | 22,254,114 |
Total revenue |  | $ | 9,225,922 |  |  | $ | 19,213 |  |  | $ | (15,247 | ) |  | $ | 9,229,888 |
Total cost of revenue |  |  | (8,867,987 | ) |  |  | (23,927 | ) |  |  | 17,119 |  |  |  | (8,874,795 | )
Interest income |  |  | 45,760 |  |  |  | 25,824 |  |  |  | (15,172 | ) |  |  | 56,412 |
Interest expense |  |  | (1,127,009 | ) |  |  | (13,793 | ) |  |  | — |  |  |  | (1,140,802 | )
Other |  |  | 490,224 |  |  |  | (3,388 | ) |  |  | — |  |  |  | 486,836 |
Net income (loss) |  | $ | (233,090 | ) |  | $ | 3,929 |  |  | $ | (13,300 | ) |  | $ | (242,461 | )

Bankruptcy-Remote Subsidiaries — Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine and our other subsidiaries. At December 31, 2004, these entities included: Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside Holdings, LLC, Calpine Energy Management, L.P., CES GP, LLC, Power Contract Financing, LLC, Power Contract Financing III, LLC, Calpine Northbrook Energy Marketing, LLC, Calpine Northbrook Energy Marketing Holdings, LLC, Gilroy Energy Center, LLC, Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), Calpine Fox Holdings, LLC and Calpine Fox LLC. The following disclosures are required under certain applicable agreements and pertain to some of these entities.
On May 15, 2003, our wholly owned indirect subsidiary, Calpine Northbrook Energy Marketing, LLC (“CNEM”), completed an offering of $82.8 million secured by an existing power sales agreement with the Bonneville Power Administration (“BPA”). CNEM borrowed $82.8 million secured by the BPA contract, a spot market power purchase agreement, a fixed price swap agreement and the equity interest in CNEM. The $82.8 million loan is recourse only to CNEM’s assets and the equity interest in CNEM and is not guaranteed by us. CNEM was determined to be a Variable Interest Entity (“VIE”) in which we were the primary beneficiary. Accordingly, the entity’s assets and liabilities are consolidated into our accounts.

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Pursuant to the applicable transaction agreements, each of CNEM and its parent, CNEM Holdings, LLC, has been established as an entity with its existence separate from Calpine and our other subsidiaries. In accordance with FIN 46-R, we consolidate these entities. See Note 2 of the Notes to Consolidated Financial Statements for more information on FIN 46-R. The power sales agreement with BPA has been acquired by CNEM from CES and the spot market power purchase agreement with a third party and the swap agreement have been entered into by CNEM and, together with the $82.8 million loan, are assets and liabilities of CNEM, separate from the assets and liabilities of Calpine and our other subsidiaries. The only significant asset of CNEM Holdings, LLC is its equity interest in CNEM. The proceeds of the $82.8 million loan were primarily used by CNEM to purchase the power sales agreement with BPA.
The following table sets forth selected financial information of CNEM as of and for the year ended December 31, 2004 (in thousands):

|  | 2004 |
Assets |  | $ | 72,367 |
Liabilities |  | $ | 56,222 |
Total revenue(1) |  | $ | 667 |
Total cost of revenue |  | $ | — |
Interest expense |  | $ | 7,378 |
Net (loss) |  | $ | (56,167 | )

(1) | CNEM’s contracts are derivatives and are recorded on a net mark-to-market basis on our financial statements under SFAS No. 133, notwithstanding that economically they are fully hedged.

See Note 12 of the Notes to Consolidated Financial Statements for further information.
On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of CES, completed an offering of two tranches of Senior Secured Notes due 2006 and 2010 (collectively called the “PCF Notes”), totaling $802.2 million. PCF’s assets and liabilities consist of cash, certain transferred power purchase and sales agreements and the PCF Notes. PCF was determined to be a VIE in which we were the primary beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into our accounts.
Pursuant to the applicable transaction agreements, PCF has been established as an entity with its existence separate from Calpine and our other subsidiaries. In accordance with FIN 46-R, we consolidate this entity. See Note 2 of the Notes to Consolidated Financial Statements for more information on FIN 46-R. The above mentioned power purchase and sales agreements, which were acquired by PCF from CES, and the PCF Notes are assets and liabilities of PCF, separate from the assets and liabilities of Calpine and our other subsidiaries. The proceeds of the PCF Notes were primarily used by PCF to purchase the power purchase and sales agreements. The following table sets forth selected financial information of PCF as of and for the year ended December 31, 2004 (in thousands):

|  | 2004 |
Assets |  | $ | 1,109,825 |
Liabilities |  | $ | 1,245,538 |
Total revenue |  | $ | 513,832 |
Total cost of revenue |  | $ | 469,632 |
Interest expense |  | $ | 66,116 |
Net (loss) |  | $ | (21,188 | )

See Note 12 of the Notes to Consolidated Financial Statements for further information.
On September 30, 2003, GEC, a wholly owned subsidiary of our indirect subsidiary GEC Holdings, LLC, completed an offering of $301.7 million of 4% Senior Secured Notes Due 2011 (the “GEC Notes”). See Note 18 of the Notes to Consolidated Financial Statements for more information on this secured financing. In connection with the offering of the GEC Notes, we received funding on a third party preferred equity

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investment in GEC Holdings, LLC totaling $74.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” due to certain preferential distributions to the third party. The preferential distributions are due semi-annually beginning in March 2004 through September 2011 and total approximately $113.3 million over the eight-year period. As of December 31, 2004 and 2003, there was $67.4 and $74.0 million, respectively, outstanding under the preferred interest.
Pursuant to the applicable transaction agreements, GEC has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate these entities. One of our long-term power sales agreements with CDWR has been acquired by GEC by means of a series of capital contributions by CES and certain of its affiliates and is an asset of GEC, and the GEC Notes and the preferred interest are liabilities of GEC, separate from the assets and liabilities of Calpine and our other subsidiaries. In addition to seven peaker power plants owned directly by GEC and the power sales agreement, GEC’s assets include cash and a 100% equity interest in each of Creed Energy Center, LLC (“Creed”) and Goose Haven Energy Center, LLC (“Goose Haven”) each of which is a wholly owned subsidiary of GEC. Each of Creed and Goose Haven has been established as an entity with its existence separate from Calpine and our other subsidiaries of the Company. GEC consolidates these entities. Creed and Goose Haven each have assets consisting of various power plants and other assets. The following table sets forth selected financial information of GEC as of and for the year ended December 31, 2004 (in thousands):

|  | 2004 |
Assets |  | $ | 624,132 |
Liabilities |  | $ | 285,604 |
Total revenue |  | $ | 110,532 |
Total cost of revenue |  | $ | 54,214 |
Interest expense |  | $ | 20,567 |
Net income |  | $ | 36,864 |

See Note 12 of the Notes to Consolidated Financial Statements for further information.
On April 29, 2003, we sold a preferred interest in a subsidiary that leases and operates the 120 MW King City Power Plant to GE Structured Finance for $82.0 million. The preferred interest holder will receive approximately 60% of future cash flow distributions based on current projections. We will continue to provide O&M services. As of December 31, 2003, there was $82.0 million outstanding under the preferred interest.
Pursuant to the applicable transaction agreements, each of Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), and Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate these entities. The following table sets forth certain financial information relating to these three entities as of December 31, 2004 (in thousands):

|  | 2004 |
Assets |  | $ | 481,482 |
Liabilities |  | $ | 102,742 |

See Note 12 of the Notes to Consolidated Financial Statements for further information.
On December 4, 2003, we announced that we had sold to a group of institutional investors our right to receive payments from PG&E under the Agreement between PG&E and Calpine Gilroy Cogen, L.P. (“Gilroy”), a California Limited Partnership (PG&E Log No. 08C002) For Termination and Buy-Out of Standard Offer 4 Power Purchase Agreement, executed by PG&E on July 1, 1999 (the “Gilroy Receivable”) for $133.4 million in cash. Because the transaction did not satisfy the criteria for sales treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of

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Liabilities — a Replacement of FASB Statement No. 125,” it is reflected in the Consolidated Financial Statements as a secured financing, with a note payable of $133.4 million. The receivable balance and note payable balance are both reduced as PG&E makes payments to the buyer of the Gilroy Receivable. The $24.1 million difference between the $157.5 million book value of the Gilroy Receivable at the transaction date and the cash received will be recognized as additional interest expense over the repayment term. We will continue to book interest income over the repayment term and interest expense will be accreted on the amortizing note payable balance.
Pursuant to the applicable transaction agreements, each of Gilroy and Calpine Gilroy 1, Inc. (the general partner of Gilroy), has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate these entities. The following table sets forth the assets and liabilities of Gilroy as of December 31, 2004 (in thousands):

|  | 2004 |
Assets |  | $ | 438,955 |
Liabilities |  | $ | 253,598 |

See Note 8 of the Notes to Consolidated Financial Statements for further information.
On June 2, 2004, our wholly-owned indirect subsidiary, Power Contract Financing III, LLC (“PCF III”), issued $85.0 million of zero coupon notes collateralized by PCF III’s ownership of PCF. PCF III owns all of the equity interests in PCF, which holds the CDWR contract monetized in June 2003 and maintains a debt reserve fund, which had a balance of approximately $94.4 million at December 31, 2004. We received cash proceeds of approximately $49.8 million from the issuance of the zero coupon notes.
Pursuant to the applicable transaction agreements, PCF III has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate this entity. The following table sets forth the assets and liabilities of PCF III as of December 31, 2004, which does not include the balances of PCF III’s subsidiary, PCF (in thousands):

|  | 2004 |
Assets |  | $ | 2,701 |
Liabilities |  | $ | 52,388 |

On August 5, 2004, our wholly-owned indirect subsidiary, Calpine Energy Management, L.P. (“CEM”), entered into a $250.0 million letter of credit facility with Deutsche Bank whereby Deutsche Bank will support CEM’s power and gas obligations by issuing letters of credit. The facility expires in October 2005.
Pursuant to the applicable transaction agreements, CEM has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate this entity. The following table sets forth the assets and liabilities of CEM as of December 31, 2004 (in thousands):

|  | 2004 |
Assets |  | $ | 35,851 |
Liabilities |  | $ | 34,816 |

On June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC, wholly owned stand-alone subsidiaries of the Company’s Calpine Riverside Holdings, LLC subsidiary, received funding in the aggregate amount of $661.5 million comprising $633.4 million of First Priority Secured Floating Rate Term Loans Due 2011 and a $28.1 million letter of credit-linked deposit facility.
Pursuant to the applicable transaction agreements, each of Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, and Calpine Riverside Holdings, LLC has been established as an entity with

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its existence separate from Calpine and our other subsidiaries. We consolidate these entities. The following tables set forth the assets and liabilities of these entities as of December 31, 2004 (in thousands):

|  | Rocky Mountain |
|  | 2004 |
Assets |  | $ | 416,662 |
Liabilities |  | $ | 277,157 |

|  | Riverside |
|  | 2004 |
Assets |  | $ | 909,687 |
Liabilities |  | $ | 431,700 |

|  | Calpine Riverside |
|  | Holdings, LLC |
|  | 2004 |
Assets |  | $ | 241,893 |
Liabilities |  | $ | — |

On November 19, 2004, our wholly-owned indirect subsidiaries, Calpine Fox LLC and its immediate parent company, Calpine Fox Holdings, LLC, entered into a $400 million, 25-year, non-recourse sale/ leaseback transaction with affiliates of GE Commercial Finance Energy Financial Services (“GECF”) for the 560-megawatt Fox Energy Center under construction in Wisconsin. Due to significant continuing involvement, as defined in SFAS No. 98, “Accounting for Leases,” the transaction does not currently qualify for sale/ leaseback accounting under that statement and has been accounted for as a financing. The proceeds received from GECF are recorded as debt in our consolidated balance sheet. The power plant assets will be depreciated over their estimated useful life and the lease payments will be applied to principal and interest expense using the effective interest method until such time as our continuing involvement is removed, expires or is otherwise eliminated. Once we no longer have significant continuing involvement in the power plant assets, the legal sale will be recognized for accounting purposes and the underlying lease will be evaluated and classified in accordance with SFAS No. 13, “Accounting for Leases.”
Pursuant to the applicable transaction agreements, each of Calpine Fox, LLC and Calpine Fox Holdings, LLC, has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate these entities. The following tables set forth the assets and liabilities of Calpine Fox, LLC and Calpine Fox Holdings, LLC, respectively, as of December 31, 2004 (in thousands):

|  | Calpine Fox, LLC |
|  | 2004 |
Assets |  | $ | 480,685 |
Liabilities |  | $ | 274,724 |

|  | Calpine Fox |
|  | Holdings, LLC |
|  | 2004 |
Assets |  | $ | 102,980 |
Liabilities |  | $ | — |

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Capital Spending — Development and Construction
Construction and development costs in process consisted of the following at December 31, 2004 (dollars in thousands):

|  |  |  |  |  | Equipment |  |  | Project |  |  |
|  | # of |  |  |  |  | Included in |  |  | Development |  |  | Unassigned |
|  | Projects |  |  | CIP(1) |  |  | CIP |  |  | Costs |  |  | Equipment |
Projects in construction(2) |  |  | 10 |  |  | $ | 3,194,530 |  |  | $ | 1,094,490 |  |  | $ | — |  |  | $ | — |
Projects in advanced development |  |  | 10 |  |  |  | 670,806 |  |  |  | 520,036 |  |  |  | 102,829 |  |  |  | — |
Projects in suspended development |  |  | 6 |  |  |  | 421,547 |  |  |  | 168,985 |  |  |  | 38,398 |  |  |  | — |
Projects in early development |  |  | 2 |  |  |  | — |  |  |  | — |  |  |  | 8,952 |  |  |  | — |
Other capital projects |  |  | NA |  |  |  | 35,094 |  |  |  | — |  |  |  | — |  |  |  | — |
Unassigned equipment |  |  | NA |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 66,073 |
Total construction and development costs |  |  |  |  |  | $ | 4,321,977 |  |  | $ | 1,783,511 |  |  | $ | 150,179 |  |  | $ | 66,073 |

(1) | Construction in Progress (“CIP”).
(2) | We have a total of 11 projects in construction. This includes the 10 projects above that are recorded in CIP and 1 project that is recorded in investments in power projects. Work and the capitalization of interest on one of the construction projects has been suspended or delayed due to current market conditions. The CIP balance on this project was $461.5 million as of December 31, 2004. Subsequent to December 31, 2004, work and the capitalization of interest on two additional construction projects was suspended or delayed. Total CIP on these two projects was $683.0 million as of December 31, 2004.

Projects in Construction — The ten projects in construction are projected to come on line from March 2005 to November 2007 or later. These projects will bring on line approximately 4,656 MW of base load capacity (5,264 MW with peaking capacity). Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized, unless work has been suspended, in which case capitalization of interest expense is suspended until active construction resumes. At December 31, 2004, the estimated funding requirements to complete these projects, net of expected project financing proceeds, is approximately $84.6 million.
Projects in Advanced Development — There are an additional ten projects in advanced development. These projects will bring on line approximately 5,307 MW of base load capacity (6,095 MW with peaking capacity). Interest and other costs related to the development activities necessary to bring these projects to their intended use are being capitalized. However, the capitalization of interest has been suspended on 2 projects for which development activities are substantially complete but construction will not commence until a power purchase agreement and financing are obtained. The estimated cost to complete the 10 projects in advanced development is approximately $3.0 billion. Our current plan is to project finance these costs as power purchase agreements are arranged.
Suspended Development Projects — Due to current electric market conditions, we have ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met indicating that it is again highly probable that the costs will be recovered through future operations. As is true for all projects, the suspended projects are reviewed for impairment whenever there is an indication of potential reduction in a project’s fair value. Further, if it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value. These projects would bring on line approximately 2,956 MW of base load capacity (3,409 MW with peaking capacity). The estimated cost to complete these projects is approximately $1.8 billion.

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Projects in Early Development — Costs for projects that are in early stages of development are capitalized only when it is highly probable that such costs are ultimately recoverable and significant project milestones are achieved. Until then, all costs, including interest costs, are expensed. The projects in early development with capitalized costs relate to two projects and include geothermal drilling costs and equipment purchases.
Other Capital Projects — Other capital projects primarily consist of enhancements to operating power plants, oil and gas and geothermal resource and facilities development as well as software developed for internal use.
Unassigned Equipment — As of December 31, 2004, we had made progress payments on four turbines and other equipment with an aggregate carrying value of $66.1 million. This unassigned equipment is classified on the balance sheet as other assets, because it is not assigned to specific development and construction projects. We are holding this equipment for potential use on future projects. It is possible that some of this unassigned equipment may eventually be sold, potentially in combination with our engineering and construction services. For equipment that is not assigned to advanced development or construction projects, interest is not capitalized.
Impairment Evaluation — All construction and development projects and unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in fair value. Equipment assigned to such projects is not evaluated for impairment separately, as it is integral to the assumed future operations of the project to which it is assigned. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value in accordance with the provisions of SFAS No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”). We review our unassigned equipment for potential impairment based on probability-weighted alternatives of utilizing it for future projects versus selling it. Utilizing this methodology, we do not believe that the equipment not committed to sale is impaired. However, during the year ended December 31, 2004, we recorded to the “Equipment cancellation and impairment cost” line of the Consolidated Statement of Operations $3.2 million in net losses in connection with equipment sales. During the year ended December 31, 2003, we recorded to the same line $29.4 million in losses in connection with the sale of four turbines, and we may incur further losses should we decide to sell more unassigned equipment in the future.
Performance Metrics
In understanding our business, we believe that certain non-GAAP operating performance metrics are particularly important. These are described below:

| • | Total deliveries of power. We both generate power that we sell to third parties and purchase power for sale to third parties in hedging, balancing and optimization (“HBO”) transactions. The former sales are recorded as electricity and steam revenue and the latter sales are recorded as sales of purchased power for hedging and optimization. The volumes in MWh for each are key indicators of our respective levels of generation and HBO activity and the sum of the two, our total deliveries of power, is relevant because there are occasions where we can either generate or purchase power to fulfill contractual sales commitments. Prospectively beginning October 1, 2003, in accordance with EITF Issue No. 03-11, certain sales of purchased power for hedging and optimization are shown net of purchased power expense for hedging and optimization in our consolidated statement of operations. Accordingly, we have also netted HBO volumes on the same basis as of October 1, 2003, in the table below.
| • | Average availability and average baseload capacity factor. Availability represents the percent of total hours during the period that our plants were available to run after taking into account the downtime associated with both scheduled and unscheduled outages. The baseload capacity factor is calculated by dividing (a) total MWh generated by our power plants (excluding peakers) by the product of multiplying (b) the weighted average MW in operation during the period by (c) the total hours in the period. The average baseload capacity factor is thus a measure of total actual generation as a percent of total potential generation. If we elect not to generate during periods when electricity pricing is too low

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|  | or gas prices too high to operate profitably, the baseload capacity factor will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements.
| • | Average heat rate for gas-fired fleet of power plants expressed in Btu’s of fuel consumed per kilowatt hour (“KWh”) generated. We calculate the average heat rate for our gas-fired power plants (excluding peakers) by dividing (a) fuel consumed in Btu’s by (b) KWh generated. The resultant heat rate is a measure of fuel efficiency, so the lower the heat rate, the better. We also calculate a “steam-adjusted” heat rate, in which we adjust the fuel consumption in Btu’s down by the equivalent heat content in steam or other thermal energy exported to a third party, such as to steam hosts for our cogeneration facilities. Our goal is to have the lowest average heat rate in the industry.
| • | Average all-in realized electric price expressed in dollars per MWh generated. Our risk management and optimization activities are integral to our power generation business and directly impact our total realized revenues from generation. Accordingly, we calculate the all-in realized electric price per MWh generated by dividing (a) adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues and the spread on sales of purchased electricity for hedging, balancing, and optimization activity, by (b) total generated MWh in the period.
| • | Average cost of natural gas expressed in dollars per millions of Btu’s of fuel consumed. Our risk management and optimization activities related to fuel procurement directly impact our total fuel expense. The fuel costs for our gas-fired power plants are a function of the price we pay for fuel purchased and the results of the fuel hedging, balancing, and optimization activities by CES. Accordingly, we calculate the cost of natural gas per millions of Btu’s of fuel consumed in our power plants by dividing (a) adjusted fuel expense which includes the cost of fuel consumed by our plants (adding back cost of inter-company “equity” gas from Calpine Natural Gas, which is eliminated in consolidation), and the spread on sales of purchased gas for hedging, balancing, and optimization activity by (b) the heat content in millions of Btu’s of the fuel we consumed in our power plants for the period.
| • | Average spark spread expressed in dollars per MWh generated. Our risk management activities focus on managing the spark spread for our portfolio of power plants, the spread between the sales price for electricity generated and the cost of fuel. We calculate the spark spread per MWh generated by subtracting (a) adjusted fuel expense from (b) adjusted E&S revenue and dividing the difference by (c) total generated MWh in the period.
| • | Average plant operating expense per normalized MWh. To assess trends in electric power plant operating expense (“POX”) per MWh, we normalize the results from period to period by assuming a constant 70% total company-wide capacity factor (including both baseload and peaker capacity) in deriving normalized MWh. By normalizing the cost per MWh with a constant capacity factor, we can better analyze trends and the results of our program to realize economies of scale, cost reductions and efficiencies at our electric generating plants. For comparison purposes we also include POX per actual MWh.

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The table below shows the operating performance metrics discussed above.

|  | Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |
|  | (In thousands) |
Operating Performance Metrics; |  |  |  |  |  |  |  |  |  |  |  |
| Total deliveries of power: |  |  |  |  |  |  |  |  |  |  |  |
|  | MWh generated |  |  | 96,489 |  |  |  | 82,423 |  |  |  | 72,767 |
|  | HBO and trading MWh sold |  |  | 51,175 |  |  |  | 77,232 |  |  |  | 75,740 |
|  | MWh delivered |  |  | 147,664 |  |  |  | 159,655 |  |  |  | 148,507 |
| Average availability |  |  | 92.6 | % |  |  | 91.2 | % |  |  | 91.8 | %
| Average baseload capacity factor: |  |  |  |  |  |  |  |  |  |  |  |
|  | Average total MW in operation |  |  | 24,690 |  |  |  | 20,092 |  |  |  | 14,346 |
|  | Less: Average MW of pure peakers |  |  | 2,951 |  |  |  | 2,672 |  |  |  | 1,708 |
|  | Average baseload MW in operation |  |  | 21,739 |  |  |  | 17,420 |  |  |  | 12,638 |
|  | Hours in the period |  |  | 8,784 |  |  |  | 8,760 |  |  |  | 8,760 |
|  | Potential baseload generation (MWh) |  |  | 190,955 |  |  |  | 152,599 |  |  |  | 110,709 |
|  | Actual total generation (MWh) |  |  | 96,489 |  |  |  | 82,423 |  |  |  | 72,767 |
|  | Less: Actual pure peakers’ generation (MWh) |  |  | 1,453 |  |  |  | 1,290 |  |  |  | 979 |
|  | Actual baseload generation (MWh) |  |  | 95,036 |  |  |  | 81,133 |  |  |  | 71,788 |
|  | Average baseload capacity factor |  |  | 49.8 | % |  |  | 53.2 | % |  |  | 64.8 | %
| Average heat rate for gas-fired power plants (excluding peakers) (Btu’s/ KWh): |  |  |  |  |  |  |  |  |  |  |  |
|  | Not steam adjusted |  |  | 8,193 |  |  |  | 8,007 |  |  |  | 7,928 |
|  | Steam adjusted |  |  | 7,120 |  |  |  | 7,253 |  |  |  | 7,239 |
| Average all-in realized electric price: |  |  |  |  |  |  |  |  |  |  |  |
|  | Electricity and steam revenue |  | $ | 5,683,063 |  |  | $ | 4,680,397 |  |  | $ | 3,237,510 |
|  | Spread on sales of purchased power for hedging and optimization |  |  | 164,747 |  |  |  | 24,118 |  |  |  | 527,546 |
|  | Adjusted electricity and steam revenue (in thousands) |  | $ | 5,847,810 |  |  | $ | 4,704,515 |  |  | $ | 3,765,056 |
|  | MWh generated (in thousands) |  |  | 96,489 |  |  |  | 82,423 |  |  |  | 72,767 |
|  | Average all-in realized electric price per MWh |  | $ | 60.61 |  |  | $ | 57.08 |  |  | $ | 51.74 |
| Average cost of natural gas: |  |  |  |  |  |  |  |  |  |  |  |
| Fuel expense (in thousands) |  | $ | 3,731,108 |  |  | $ | 2,665,620 |  |  | $ | 1,792,323 |
|  | Fuel cost elimination |  |  | 208,170 |  |  |  | 284,951 |  |  |  | 141,263 |
|  | Spread on sales of purchased gas for hedging and optimization |  |  | (11,587 | ) |  |  | (41,334 | ) |  |  | (49,401 | )
|  | Adjusted fuel expense |  | $ | 3,927,691 |  |  | $ | 2,909,237 |  |  | $ | 1,884,185 |
|  | Million Btu’s (“MMBtu”) of fuel consumed by generating plants (in thousands) |  |  | 657,762 |  |  |  | 560,508 |  |  |  | 511,354 |
|  | Average cost of natural gas per MMBtu |  | $ | 5.97 |  |  | $ | 5.19 |  |  | $ | 3.68 |
|  | MWh generated (in thousands) |  |  | 96,489 |  |  |  | 82,423 |  |  |  | 72,767 |
|  | Average cost of adjusted fuel expense per MWh |  | $ | 40.71 |  |  | $ | 35.30 |  |  | $ | 25.89 |
| Average spark spread: |  |  |  |  |  |  |  |  |  |  |  |
|  | Adjusted electricity and steam revenue (in thousands) |  | $ | 5,847,810 |  |  | $ | 4,704,515 |  |  | $ | 3,765,056 |
|  | Less: Adjusted fuel expense (in thousands) |  |  | 3,927,691 |  |  |  | 2,909,237 |  |  |  | 1,884,185 |
|  |  | Spark spread (in thousands) |  | $ | 1,920,119 |  |  | $ | 1,795,278 |  |  | $ | 1,880,871 |
|  | MWh generated (in thousands) |  |  | 96,489 |  |  |  | 82,423 |  |  |  | 72,767 |
|  | Average spark spread per MWh |  | $ | 19.90 |  |  | $ | 21.78 |  |  | $ | 25.85 |
|  | Add: Equity gas contribution(1) |  | $ | 129,255 |  |  | $ | 174,922 |  |  | $ | 42,769 |
|  | Spark spread with equity gas benefits (in thousands) |  | $ | 2,049,374 |  |  | $ | 1,970,200 |  |  | $ | 1,923,640 |
|  | Average spark spread with equity gas benefits per MWh |  | $ | 21.24 |  |  | $ | 23.90 |  |  | $ | 26.44 |
| Average plant operating expense (“POX”) per normalized MWh (for comparison purposes we also include POX per actual MWh): |  |  |  |  |  |  |  |  |  |  |  |
|  | Average total consolidated MW in operations |  |  | 24,690 |  |  |  | 20,092 |  |  |  | 14,346 |
|  | Hours per year |  |  | 8,784 |  |  |  | 8,760 |  |  |  | 8,760 |
|  | Total potential MWh |  |  | 216,877 |  |  |  | 176,006 |  |  |  | 125,671 |
|  | Normalized MWh (at 70% capacity factor) |  |  | 151,814 |  |  |  | 123,204 |  |  |  | 87,970 |
|  | Plant operating expense (POX) |  | $ | 795,975 |  |  | $ | 663,045 |  |  | $ | 522,906 |
|  | POX per normalized MWh |  | $ | 5.24 |  |  | $ | 5.38 |  |  | $ | 5.94 |
|  | POX per actual MWh |  | $ | 8.25 |  |  | $ | 8.04 |  |  | $ | 7.19 |

(1) | Equity gas contribution margin from continuing operations:

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|  | Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |
|  | (In thousands) |
Oil and gas sales |  | $ | 63,153 |  |  | $ | 59,156 |  |  | $ | 63,514 |
Add: Fuel cost eliminated in consolidation |  |  | 208,170 |  |  |  | 284,951 |  |  |  | 141,263 |
| Subtotal |  | $ | 271,323 |  |  | $ | 344,107 |  |  | $ | 204,777 |
Less: Oil and gas operating expense |  |  | 56,843 |  |  |  | 75,453 |  |  |  | 69,840 |
Less: Depletion, depreciation and amortization(a) |  |  | 85,225 |  |  |  | 93,732 |  |  |  | 92,168 |
Equity gas contribution margin |  | $ | 129,255 |  |  | $ | 174,922 |  |  | $ | 42,769 |
MWh generated (in thousands) |  |  | 96,489 |  |  |  | 82,423 |  |  |  | 72,767 |
Equity gas contribution margin per MWh |  | $ | 1.34 |  |  | $ | 2.12 |  |  | $ | 0.59 |

(a) | Excludes oil and gas impairment of $202.1 million, $2.9 million and $3.4 million, respectively.

The table below provides additional detail of total mark-to-market activity. For the years ended December 31, 2004, 2003 and 2002, mark-to-market activity, net consisted of (dollars in thousands):

|  | Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |
|  | (In thousands) |
Realized: |  |  |  |  |  |  |  |  |  |  |  |
| Power activity |  |  |  |  |  |  |  |  |  |  |  |
| “Trading Activity” as defined in EITF Issue No. 02-03 |  | $ | 52,390 |  |  | $ | 52,559 |  |  | $ | 12,175 |
|  | Other mark-to-market activity(1) |  |  | (12,158 | ) |  |  | (26,059 | ) |  |  | — |
|  |  | Total realized power activity |  | $ | 40,232 |  |  | $ | 26,500 |  |  | $ | 12,175 |
| Gas activity |  |  |  |  |  |  |  |  |  |  |  |
|  | “Trading Activity” as defined in EITF Issue No. 02-03 |  | $ | 8,025 |  |  | $ | (2,166 | ) |  | $ | 13,915 |
|  | Other mark-to-market activity(1) |  |  | — |  |  |  | — |  |  |  | — |
|  |  | Total realized gas activity |  | $ | 8,025 |  |  | $ | (2,166 | ) |  | $ | 13,915 |
Total realized activity: |  |  |  |  |  |  |  |  |  |  |  |
| “Trading Activity” as defined in EITF Issue No. 02-03 |  | $ | 60,415 |  |  | $ | 50,393 |  |  | $ | 26,090 |
| Other mark-to-market activity(1) |  |  | (12,158 | ) |  |  | (26,059 | ) |  |  | — |
|  |  | Total realized activity |  | $ | 48,257 |  |  | $ | 24,334 |  |  | $ | 26,090 |
Unrealized: |  |  |  |  |  |  |  |  |  |  |  |
| Power activity |  |  |  |  |  |  |  |  |  |  |  |
|  | “Trading Activity” as defined in EITF Issue No. 02-03 |  | $ | (18,075 | ) |  | $ | (55,450 | ) |  | $ | 12,974 |
|  | Ineffectiveness related to cash flow hedges |  |  | 1,814 |  |  |  | (5,001 | ) |  |  | (4,934 | )
|  | Other mark-to-market activity(1) |  |  | (13,591 | ) |  |  | (1,243 | ) |  |  | — |
|  |  | Total unrealized power activity |  | $ | (29,852 | ) |  | $ | (61,694 | ) |  | $ | 8,040 |
| Gas activity |  |  |  |  |  |  |  |  |  |  |  |
|  | “Trading Activity” as defined in EITF Issue No. 02-03 |  | $ | (10,700 | ) |  | $ | 7,768 |  |  | $ | (14,792 | )
|  | Ineffectiveness related to cash flow hedges |  |  | 5,827 |  |  |  | 3,153 |  |  |  | 2,147 |
|  | Other mark-to-market activity(1) |  |  | — |  |  |  | — |  |  |  | — |
|  |  | Total unrealized gas activity |  | $ | (4,873 | ) |  | $ | 10,921 |  |  | $ | (12,645 | )
Total unrealized activity: |  |  |  |  |  |  |  |  |  |  |  |
| “Trading Activity” as defined in EITF Issue No. 02-03 |  | $ | (28,775 | ) |  | $ | (47,682 | ) |  | $ | (1,818 | )
| Ineffectiveness related to cash flow hedges |  |  | 7,641 |  |  |  | (1,848 | ) |  |  | (2,787 | )
| Other mark-to-market activity(1) |  |  | (13,591 | ) |  |  | (1,243 | ) |  |  | — |
|  |  | Total unrealized activity |  | $ | (34,725 | ) |  | $ | (50,773 | ) |  | $ | (4,605 | )

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|  | Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |
|  | (In thousands) |
Total mark-to-market activity: |  |  |  |  |  |  |  |  |  |  |  |
| “Trading Activity” as defined in EITF Issue No. 02-03 |  | $ | 31,640 |  |  | $ | 2,711 |  |  | $ | 24,272 |
| Ineffectiveness related to cash flow hedges |  |  | 7,641 |  |  |  | (1,848 | ) |  |  | (2,787 | )
| Other mark-to-market activity(1) |  |  | (25,749 | ) |  |  | (27,302 | ) |  |  | — |
|  | Total mark-to-market activity |  | $ | 13,532 |  |  | $ | (26,439 | ) |  | $ | 21,485 |

(1) | Activity related to our assets but does not qualify for hedge accounting.

Strategy
For a discussion of our strategy and management’s outlook, see “Item 1 — Business — Strategy.”
Financial Market Risks
As we are primarily focused on generation of electricity using gas-fired turbines, our natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, we enter into derivative commodity instruments as discussed in Item 6. “Business — Marketing, Hedging, Optimization and Trading Activities.”
The change in fair value of outstanding commodity derivative instruments from January 1, 2004, through December 31, 2004, is summarized in the table below (in thousands):

Fair value of contracts outstanding at January 1, 2004 |  | $ | 76,541 |
Cash losses recognized or otherwise settled during the period(1) |  |  | 30,569 |
Non-cash losses recognized or otherwise settled during the period(2) |  |  | (34,394 | )
Changes in fair value attributable to new contracts |  |  | (28,896 | )
Changes in fair value attributable to price movements |  |  | (25,260 | )
| Fair value of contracts outstanding at December 31, 2004(3) |  | $ | 18,560 |
Realized cash flow from fair value hedges(4) |  | $ | 171,096 |

(1) | Recognized (losses) from commodity cash flow hedges of $(89.2) million (represents realized value of cash flow hedge activity of $(70.2) million as disclosed in Note 23 of the Notes to Consolidated Financial Statements, net of non-cash other comprehensive income (“OCI”) items relating to terminated derivatives of $8.1 million and equity method hedges of $10.9 million) and realized gains of $58.6 million on mark-to-market activity, (represents realized value of mark-to-market activity of $48.3 million, as reported in the Consolidated Statements of Operations under mark-to-market activities, net of $(10.3) million of non-cash realized mark-to-market activity).
(2) | This represents the non-cash amortization of deferred items embedded in our derivative assets and liabilities.
(3) | Net commodity derivative assets reported in Note 23 of the Notes to Consolidated Financial Statements.
(4) | Not included as part of the roll-forward of net derivative assets and liabilities because changes in the hedge instrument and hedged item move in equal and offsetting directions to the extent the fair value hedges are perfectly effective.

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The fair value of outstanding derivative commodity instruments at December 31, 2004, based on price source and the period during which the instruments will mature, are summarized in the table below (in thousands):

Fair Value Source |  | 2005 |  |  | 2006-2007 |  |  | 2008-2009 |  |  | After 2009 |  |  | Total |
Prices actively quoted |  | $ | 34,636 |  |  | $ | 57,175 |  |  | $ | — |  |  | $ | — |  |  | $ | 91,811 |
Prices provided by other external sources |  |  | (55,308 | ) |  |  | (18,845 | ) |  |  | 14,678 |  |  |  | (30,666 | ) |  |  | (90,141 | )
Prices based on models and other valuation methods |  |  | — |  |  |  | 7,800 |  |  |  | 9,090 |  |  |  | — |  |  |  | 16,890 |
Total fair value |  | $ | (20,672 | ) |  | $ | 46,130 |  |  | $ | 23,768 |  |  | $ | (30,666 | ) |  | $ | 18,560 |

Our risk managers maintain fair value price information derived from various sources in our risk management systems. The propriety of that information is validated by our Risk Control group. Prices actively quoted include validation with prices sourced from commodities exchanges (e.g., New York Mercantile Exchange). Prices provided by other external sources include quotes from commodity brokers and electronic trading platforms. Prices based on models and other valuation methods are validated using quantitative methods. See “Critical Accounting Policies” for a discussion of valuation estimates used where external prices are unavailable.
The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at December 31, 2004, and the period during which the instruments will mature are summarized in the table below (in thousands):

Credit Quality (Based on Standard & Poor’s Ratings |  |  |  |  |  |  |  |  |  |
as of December 31, 2004) |  | 2005 |  |  | 2006-2007 |  |  | 2008-2009 |  |  | After 2009 |  |  | Total |
Investment grade |  | $ | (30,186 | ) |  | $ | 46,357 |  |  | $ | 23,768 |  |  | $ | (30,666 | ) |  | $ | 9,273 |
Non-investment grade |  |  | 8,676 |  |  |  | 632 |  |  |  | — |  |  |  | — |  |  |  | 9,308 |
No external ratings |  |  | 838 |  |  |  | (859 | ) |  |  | — |  |  |  | — |  |  |  | (21 | )
Total fair value |  | $ | (20,672 | ) |  | $ | 46,130 |  |  | $ | 23,768 |  |  | $ | (30,666 | ) |  | $ | 18,560 |

The fair value of outstanding derivative commodity instruments and the fair value that would be expected after a ten percent adverse price change are shown in the table below (in thousands):

|  |  |  | Fair Value After |
|  |  |  | 10% Adverse |
|  | Fair Value |  |  | Price Change |
At December 31, 2004: |  |  |  |  |  |  |  |
| Electricity |  | $ | (70,457 | ) |  | $ | (227,624 | )
| Natural gas |  |  | 89,017 |  |  |  | 4,505 |
|  | Total |  | $ | 18,560 |  |  | $ | (223,119 | )

Derivative commodity instruments included in the table are those included in Note 23 of the Notes to Consolidated Financial Statements. The fair value of derivative commodity instruments included in the table is based on present value adjusted quoted market prices of comparable contracts. The fair value of electricity derivative commodity instruments after a 10% adverse price change includes the effect of increased power prices versus our derivative forward commitments. Conversely, the fair value of the natural gas derivatives after a 10% adverse price change reflects a general decline in gas prices versus our derivative forward commitments. Derivative commodity instruments offset the price risk exposure of our physical assets. None of the offsetting physical positions are included in the table above.
Price changes were calculated by assuming an across-the-board ten percent adverse price change regardless of term or historical relationship between the contract price of an instrument and the underlying commodity price. In the event of an actual ten percent change in prices, the fair value of our derivative

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portfolio would typically change by more than ten percent for earlier forward months and less than ten percent for later forward months because of the higher volatilities in the near term and the effects of discounting expected future cash flows.
The primary factors affecting the fair value of our derivatives at any point in time are (1) the volume of open derivative positions (MMBtu and MWh), and (2) changing commodity market prices, principally for electricity and natural gas. The total volume of open gas derivative positions increased 185% from December 31, 2003, to December 31, 2004, and the total volume of open power derivative positions increased 147% for the same period. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in OCI, net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of December 31, 2004, a significant component of the balance in accumulated OCI represented the unrealized net loss associated with commodity cash flow hedging transactions. As noted above, there is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and our results during the year ended December 31, 2004, have reflected this. See Notes 21 and 23 of the Notes to Consolidated Financial Statements for additional information on derivative activity.
Interest Rate Swaps — From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations associated with certain of our debt instruments and to adjust the mix between fixed and floating rate debt in our capital structure to desired levels. We do not use interest rate swap agreements for speculative or trading purposes. The following tables summarize the fair market values of our existing interest rate swap agreements as of December 31, 2004 (dollars in thousands):

| Variable to Fixed Swaps

|  |  |  | Weighted Average |  |  | Weighted Average |  |  |
|  | Notional |  |  | Interest Rate |  |  | Interest Rate |  |  | Fair Market |
Maturity Date |  | Principal Amount |  |  | (Pay) |  |  | (Receive) |  |  | Value |
2011 |  | $ | 58,178 |  |  |  | 4.5 | % |  | 3-month US$ | LIBOR |  |  | $ | (1,734 | )
2011 |  |  | 291,897 |  |  |  | 4.5 | % |  | 3-month US$ | LIBOR |  |  |  | (8,753 | )
2011 |  |  | 209,833 |  |  |  | 4.4 | % |  | 3-month US$ | LIBOR |  |  |  | (4,916 | )
2011 |  |  | 41,822 |  |  |  | 4.4 | % |  | 3-month US$ | LIBOR |  |  |  | (980 | )
2011 |  |  | 38,479 |  |  |  | 6.9 | % |  | 3-month US$ | LIBOR |  |  |  | (4,089 | )
2012 |  |  | 105,840 |  |  |  | 6.5 | % |  | 3-month US$ | LIBOR |  |  |  | (11,680 | )
2016 |  |  | 21,120 |  |  |  | 7.3 | % |  | 3-month US$ | LIBOR |  |  |  | (3,654 | )
2016 |  |  | 14,080 |  |  |  | 7.3 | % |  | 3-month US$ | LIBOR |  |  |  | (2,436 | )
2016 |  |  | 42,240 |  |  |  | 7.3 | % |  | 3-month US$ | LIBOR |  |  |  | (7,308 | )
2016 |  |  | 28,160 |  |  |  | 7.3 | % |  | 3-month US$ | LIBOR |  |  |  | (4,872 | )
2016 |  |  | 35,200 |  |  |  | 7.3 | % |  | 3-month US$ | LIBOR |  |  |  | (6,092 | )
| Total |  | $ | 886,849 |  |  |  | 7.3 | % |  |  |  |  |  | $ | (56,514 | )

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| Fixed to Variable Swaps

|  |  |  | Weighted Average |  |  | Weighted Average |  |  |
|  | Notional |  |  | Interest Rate |  |  | Interest Rate |  |  | Fair Market |
Maturity Date |  | Principal Amount |  |  | (Pay) |  |  | (Receive) |  |  | Value |
2011 |  | $ | 100,000 |  |  | 6-month US$ | LIBOR |  |  |  | 8.5 | % |  | $ | (5,406 | )
2011 |  |  | 100,000 |  |  | 6-month US$ | LIBOR |  |  |  | 8.5 | % |  |  | (3,699 | )
2011 |  |  | 200,000 |  |  | 6-month US$ | LIBOR |  |  |  | 8.5 | % |  |  | (7,740 | )
2011 |  |  | 100,000 |  |  | 6-month US$ | LIBOR |  |  |  | 8.5 | % |  |  | (6,508 | )
| Total |  | $ | 500,000 |  |  |  |  |  |  |  | 8.5 | % |  | $ | (23,353 | )

The fair value of outstanding interest rate swaps and the fair value that would be expected after a one percent (100 basis points) adverse interest rate change are shown in the table below (in thousands). Given our net variable to fixed portfolio position, a 100 basis point decrease would adversely impact our portfolio as follows:

|  | Fair Value After a 1.0% |
|  | (100 Basis Points) Adverse |
Net Fair Value as of December 31, 2004 |  | Interest Rate Change |
$(79,867) |  | $ | (97,567 | )

Currency Exposure — We own subsidiary entities in several countries. These entities generally have functional currencies other than the U.S. dollar. In most cases, the functional currency is consistent with the local currency of the host country where the particular entity is located. In certain cases, we and our foreign subsidiary entities hold monetary assets and/or liabilities that are not denominated in the functional currencies referred to above. In such instances, we apply the provisions of SFAS No. 52, “Foreign Currency Translation,” (“SFAS No. 52”) to account for the monthly re-measurement gains and losses of these assets and liabilities into the functional currencies for each entity. In some cases we can reduce our potential exposures to net income by designating liabilities denominated in non-functional currencies as hedges of our net investment in a foreign subsidiary or by entering into derivative instruments and designating them in hedging relationships against a foreign exchange exposure. Based on our unhedged exposures at December 31, 2004, the impact to our pre-tax earnings that would be expected after a 10% adverse change in exchange rates is shown in the table below (in thousands):

|  | Impact to Pre-Tax Net Income |
|  | After 10% Adverse Exchange |
Currency Exposure |  | Rate Change |
GBP-Euro |  | $ | (15,982 | )
GBP-$US |  |  | (10,781 | )
$Cdn-$US |  |  | (72,294 | )
Other |  |  | (2,241 | )

Significant changes in exchange rates will also impact our Cumulative Translation Adjustment (“CTA”) balance when translating the financial statements of our foreign operations from their respective functional currencies into our reporting currency, the U.S. dollar. An example of the impact that significant exchange rate movements can have on our Balance Sheet position occurred in 2004. During 2004 our CTA increased by approximately $62 million primarily due to a strengthening of the Canadian dollar and GBP against the U.S. dollar by approximately 7% each.

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Foreign Currency Transaction Gain (Loss)

| Year Ended December 31, 2004, Compared to Year Ended December 31, 2003:

The major components of our foreign currency transaction losses from continuing operations of $25.1 million and $33.3 million, respectively, in 2004 and 2003, respectively, are as follows (amounts in millions):

|  | 2004 |  |  | 2003 |
Gain (Loss) from $Cdn-$US fluctuations: |  | $ | (42.8 | ) |  | $ | (22.6 | )
Gain (Loss) from GBP-Euro fluctuations: |  |  | 0.8 |  |  |  | (12.2 | )
Gain (Loss) from GBP-$US fluctuations: |  |  | 16.7 |  |  |  | — |
Gain (Loss) from other currency fluctuations: |  |  | 0.2 |  |  |  | 1.5 |

The $Cdn-$US loss for 2004 was driven by two primary factors. First, as a result of the sale of our Canadian gas assets, we recognized remeasurement losses due to the fact that the sales proceeds were converted into U.S. dollars through a series of forward foreign exchange contracts but during September, October and November, a portion of these converted proceeds were retained by the $Cdn-denominated entity that sold the assets. During these months, the Canadian dollar strengthened considerably against the U.S. dollar, creating large remeasurement losses which did not cease until the balance of the proceeds were distributed back to the U.S. parent company. Second, also in conjunction with the sale of our Canadian gas assets, we recognized remeasurement losses during the third and fourth quarter of 2004 when the Canadian dollar strengthened after the sale and subsequent repatriation of the proceeds to the U.S. parent company. The sale and repatriation of funds substantially reduced the degree to which we could designate our $Cdn-denominated liabilities as hedges against our investment in Canadian dollar denominated subsidiaries, triggering significant remeasurement losses as the Canadian dollar strengthened against the U.S. dollar. This loss was partially offset by remeasurement gains recognized on the translation of the interest receivable associated with our large intercompany loan that has been deemed a permanent investment.
The $Cdn-$US loss for 2003 was driven primarily by a significant strengthening of the Canadian dollar against the U.S. dollar during the first six months of 2003, at a time when the majority of our $Cdn-$US payable exposures were not designated as hedges of the net investment in our Canadian operations. The majority of these payable exposures were created by transactions that occurred during the fourth quarter of 2002 and the first quarter of 2003. The losses on these loans were partially offset by remeasurement gains recognized on the translation of the interest receivable associated with our large intercompany loan that has been deemed a permanent investment.
During 2004, the Euro weakened slightly against the GBP, triggering re-measurement gains associated with our Euro-denominated 83/8% Senior Notes Due 2008.
During 2003, the Euro strengthened considerably against the GBP, triggering re-measurement losses associated with these Senior Notes.
The GBP-$US gain for 2004 relates to re-measurement gains associated with our US$360 million Two-Year Redeemable Preferred Shares issued by our indirect, wholly owned subsidiary, Calpine (Jersey) Limited. The offering closed on October 26, 2004 and the remeasurement gains recognized were driven by a significant strengthening of the GBP against the U.S. dollar during November and December. There is no comparable amount for 2003 as no such exposure existed prior to the closing of this offering.

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| Year Ended December 31, 2003, Compared to Year Ended December 31, 2002:

The major components of our foreign currency transaction losses of $33.3 million and $1.0 million, respectively, in 2003 and 2002, respectively, are as follows (amounts in millions):

|  | 2003 |  |  | 2002 |
Gain (Loss) from $Cdn-$US fluctuations: |  | $ | (22.6 | ) |  | $ | (1.3 | )
Gain (Loss) from GBP-Euro fluctuations: |  |  | (12.2 | ) |  |  | 0.3 |
Gain (Loss) from other currency fluctuations: |  |  | 1.5 |  |  |  | — |

The $Cdn-$US loss for 2003 was driven primarily by a significant strengthening of the Canadian dollar against the U.S. dollar during the first six months of 2003, at a time when the majority of our $Cdn-$US payable exposures were not designated as hedges of the net investment in our Canadian operations. The majority of these payable exposures were created by transactions that occurred during the fourth quarter of 2002 and the first quarter of 2003. The losses on these loans were partially offset by remeasurement gains recognized on the translation of the interest receivable associated with our large intercompany loan that has been deemed a permanent investment.
The $Cdn-$US loss for 2002 was significantly smaller than the loss incurred during 2003, primarily due to a very limited number of $Cdn-$US payable exposures during the majority of the year. Prior to the fourth quarter of 2002, we had very few $Cdn-$US transactions subject to re-measurement gains and losses under the guidance of SFAS No. 52 and as a result of this low transaction volume, our foreign currency transaction activity was minimal. Additionally, the $Cdn-$US exchange rate was fairly static during the balance of 2002; the Canadian dollar strengthened very slightly against the U.S. dollar. The low volume of transactions combined with very mild exchange rate volatility resulted in a small financial impact to our Consolidated Statement of Operations.
During 2003, the Euro strengthened considerably against the GBP, triggering re-measurement losses associated with our Euro-denominated 83/8% Senior Notes Due 2008.
During 2002, the Euro likewise strengthened considerably against the GBP; however, we effectively mitigated our exposure to the majority of this exchange rate volatility through a Euro-GBP cross currency swap that was designated as an effective cash flow hedge against the anticipated Euro-denominated future cash flows of these Senior Notes in accordance with SFAS No. 133, as amended. The currency swap was entered into during 2001 in conjunction with the initial offering of these Senior Notes and was in place for the full balance of 2002. The swap was subsequently terminated in February, 2003.
Debt Financing — Because of the significant capital requirements within our industry, debt financing is often needed to fund our growth. Certain debt instruments may affect us adversely because of changes in market conditions. We have used two primary forms of debt which are subject to market risk: (1) Variable rate construction/project financing and (2) Other variable-rate instruments. Significant LIBOR increases could have a negative impact on our future interest expense. Our variable-rate construction/project financing is primarily through the CalGen floating rate notes, institutional term loans and revolving credit facility. New borrowings under our $200 million CalGen revolving credit agreement are used exclusively to fund the construction costs of CalGen power plants (of which only the Pastoria Energy Center was still in active construction at December 31, 2004). Other variable-rate instruments consist primarily of our revolving credit and term loan facilities, which are used for general corporate purposes. Both our variable-rate construction/project financing and other variable-rate instruments are indexed to base rates, generally LIBOR, as shown below.

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The following table summarizes our variable-rate debt, by repayment year, exposed to interest rate risk as of December 31, 2004. All outstanding balances and fair market values are shown net of applicable premium or discount, if any (dollars in thousands):

|  | 2005 |  |  | 2006 |  |  | 2007 |  |  | 2008 |
3-month US $LIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| MEP Pleasant Hill Term Loan, Tranche A |  | $ | 6,700 |  |  | $ | 7,482 |  |  | $ | 8,132 |  |  | $ | 9,271 |
| Saltend preferred interest |  |  | — |  |  |  | 360,000 |  |  |  | — |  |  |  | — |
|  |  | Total of 3-month US $LIBOR rate debt |  |  | 6,700 |  |  |  | 367,482 |  |  |  | 8,132 |  |  |  | 9,271 |
1-month EURLIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Thomassen revolving line of credit |  |  | 3,332 |  |  |  | — |  |  |  | — |  |  |  | — |
|  |  | Total of 1-month EURLIBOR rate debt |  |  | 3,332 |  |  |  | — |  |  |  | — |  |  |  | — |
1-month US $LIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| First Priority Secured Floating Rate Notes Due 2009 (CalGen) |  |  | — |  |  |  | — |  |  |  | 1,175 |  |  |  | 2,350 |
|  |  | Total of 1-month US $LIBOR rate debt |  |  | — |  |  |  | — |  |  |  | 1,175 |  |  |  | 2,350 |
6-month US $LIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Third Priority Secured Floating Rate Notes Due 2011 (CalGen) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  |  | Total of 6-month US $LIBOR rate debt |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
5-month US $LIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Riverside Energy Center project financing |  |  | 3,685 |  |  |  | 3,685 |  |  |  | 3,685 |  |  |  | 3,685 |
| Rocky Mountain Energy Center project financing |  |  | 2,642 |  |  |  | 2,649 |  |  |  | 2,649 |  |  |  | 2,649 |
|  |  | Total of 6-month US $LIBOR rate debt |  |  | 6,327 |  |  |  | 6,334 |  |  |  | 6,334 |  |  |  | 6,334 |
(1)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| First Priority Secured Institutional Term Loan Due 2009 (CCFC I) |  |  | 3,208 |  |  |  | 3,208 |  |  |  | 3,208 |  |  |  | 3,208 |
| Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  |  | Total of variable rate debt as defined at(1) below |  |  | 3,208 |  |  |  | 3,208 |  |  |  | 3,208 |  |  |  | 3,208 |
(2)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Second Priority Senior Secured Term Loan B Notes Due 2007 |  |  | 7,500 |  |  |  | 7,500 |  |  |  | 725,625 |  |  |  | — |
|  |  | Total of variable rate debt as defined at(2) below |  |  | 7,500 |  |  |  | 7,500 |  |  |  | 725,625 |  |  |  | — |
(3)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Second Priority Senior Secured Floating Due 2007 |  |  | 5,000 |  |  |  | 5,000 |  |  |  | 483,750 |  |  |  | — |
| Blue Spruce Energy Center project financing |  |  | 1,875 |  |  |  | 3,750 |  |  |  | 3,750 |  |  |  | 3,750 |
|  |  | Total of variable rate debt as defined at(3) below |  |  | 6,875 |  |  |  | 8,750 |  |  |  | 487,500 |  |  |  | 3,750 |
(5)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | First Priority Secured Term Loans Due 2009 (CalGen) |  |  | — |  |  |  | — |  |  |  | 3,000 |  |  |  | 6,000 |
|  | Second Priority Secured Floating Rate Notes Due 2010 (CalGen) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3,200 |
|  | Second Priority Secured Term Loans Due 2010 (CalGen) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 500 |
|  |  |  | Total of variable rate debt as defined at(5) below |  |  | — |  |  |  | — |  |  |  | 3,000 |  |  |  | 9,700 |
(6)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Island Cogen |  |  | 9,954 |  |  |  | — |  |  |  | — |  |  |  | — |
|  |  | Total of variable rate debt as defined at(6) below |  |  | 9,954 |  |  |  | — |  |  |  | — |  |  |  | — |
(6)(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Contra Costa |  |  | 168 |  |  |  | 175 |  |  |  | 182 |  |  |  | 190 |
|  |  | Total of variable rate debt as defined at(6) below |  |  | 168 |  |  |  | 175 |  |  |  | 182 |  |  |  | 190 |
|  |  |  | Grand total variable-rate debt instruments |  | $ | 44,064 |  |  | $ | 393,449 |  |  | $ | 1,235,156 |  |  | $ | 34,803 |

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|  |  |  |  |  | Fair Value |
|  |  |  |  |  | December 31, |
|  | 2009 |  |  | Thereafter |  |  | 2004(7) |
3-month US $LIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |
| MEP Pleasant Hill Term Loan, Tranche A |  | $ | 9,433 |  |  | $ | 85,802 |  |  | $ | 126,820 |
| Saltend preferred interest |  |  | — |  |  |  | — |  |  |  | 360,000 |
|  | Total of 3-month US $LIBOR rate debt |  |  | 9,433 |  |  |  | 85,802 |  |  |  | 486,820 |
1-month EURLIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |
Thomassen revolving line of credit |  |  | — |  |  |  | — |  |  |  | 3,332 |
|  | Total of 1-month EURLIBOR rate debt |  |  | — |  |  |  | — |  |  |  | 3,332 |
1-month US $LIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |
First Priority Secured Floating Rate Notes Due 2009 (CalGen) |  |  | 231,475 |  |  |  | — |  |  |  | 235,000 |
|  | Total of 1-month US $LIBOR rate debt |  |  | 231,475 |  |  |  | — |  |  |  | 235,000 |
6-month US $LIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |
Third Priority Secured Floating Rate Notes Due 2011 (CalGen) |  |  | — |  |  |  | 680,000 |  |  |  | 680,000 |
|  | Total of 6-month US $LIBOR rate debt |  |  | — |  |  |  | 680,000 |  |  |  | 680,000 |
5-month US $LIBOR weighted average interest rate basis(4) |  |  |  |  |  |  |  |  |  |  |  |
Riverside Energy Center project financing |  |  | 3,685 |  |  |  | 350,075 |  |  |  | 368,500 |
| Rocky Mountain Energy Center project financing |  |  | 2,649 |  |  |  | 251,662 |  |  |  | 264,900 |
|  | Total of 6-month US $LIBOR rate debt |  |  | 6,334 |  |  |  | 601,737 |  |  |  | 633,400 |
(1)(4) |  |  |  |  |  |  |  |  |  |  |  |
| First Priority Secured Institutional Term Loan Due 2009 (CCFC I) |  |  | 365,350 |  |  |  | — |  |  |  | 378,182 |
| Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I) |  |  | — |  |  |  | 408,568 |  |  |  | 408,568 |
|  | Total of variable rate debt as defined at(1) below |  |  | 365,350 |  |  |  | 408,568 |  |  |  | 786,750 |
(2)(4) |  |  |  |  |  |  |  |  |  |  |  |
| Second Priority Senior Secured Term Loan B Notes Due 2007 |  |  | — |  |  |  | — |  |  |  | 677,672 |
|  | Total of variable rate debt as defined at(2) below |  |  | — |  |  |  | — |  |  |  | 677,672 |
(3)(4) |  |  |  |  |  |  |  |  |  |  |  |
| Second Priority Senior Secured Floating Due 2007 |  |  | — |  |  |  | — |  |  |  | 449,313 |
| Blue Spruce Energy Center project financing |  |  | 3,750 |  |  |  | 81,397 |  |  |  | 98,272 |
|  | Total of variable rate debt as defined at(3) below |  |  | 3,750 |  |  |  | 81,397 |  |  |  | 547,585 |
(5)(4) |  |  |  |  |  |  |  |  |  |  |  |
| First Priority Secured Term Loans Due 2009 (CalGen) |  |  | 591,000 |  |  |  | — |  |  |  | 600,000 |
| Second Priority Secured Floating Rate Notes Due 2010 (CalGen) |  |  | 6,400 |  |  |  | 622,039 |  |  |  | 631,639 |
| Second Priority Secured Term Loans Due 2010 (CalGen) |  |  | 1,000 |  |  |  | 97,194 |  |  |  | 98,694 |
|  |  | Total of variable rate debt as defined at(5) below |  |  | 598,400 |  |  |  | 719,233 |  |  |  | 1,330,333 |
(6)(4) |  |  |  |  |  |  |  |  |  |  |  |
Island Cogen |  |  | — |  |  |  | — |  |  |  | 9,954 |
|  | Total of variable rate debt as defined at(6) below |  |  | — |  |  |  | — |  |  |  | 9,954 |
(6)(4) |  |  |  |  |  |  |  |  |  |  |  |
Contra Costa |  |  | 197 |  |  |  | 1,364 |  |  |  | 2,276 |
|  | Total of variable rate debt as defined at(6) below |  |  | 197 |  |  |  | 1,364 |  |  |  | 2,276 |
|  |  | Grand total variable-rate debt instruments |  | $ | 1,214,939 |  |  | $ | 2,578,101 |  |  | $ | 5,393,122 |

(1) | British Bankers Association LIBOR Rate for deposit in US dollars for a period of six months.
(2) | U.S. prime rate in combination with the Federal Funds Effective Rate.
(3) | British Bankers Association LIBOR Rate for deposit in US dollars for a period of three months.
(4) | Actual interest rates include a spread over the basis amount.

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(5) | Choice of 1-month US $LIBOR, 2-month US $LIBOR, 3-month US $LIBOR, 6-month US $LIBOR, 12-month US $LIBOR or a base rate.
(6) | Bankers Acceptance Rate.
(7) | Fair value equals carrying value, with the exception of the Second-Priority Senior Secured Term B Loans Due 2007 and Second-Priority Senior Secured Floating Rate Notes Due 2007 which are shown at quoted trading values as of December 31, 2004.

Construction/ Project Financing Facilities — See Note 16 of the Notes to Consolidated Financial Statements for information on our construction/project financing.
Application of Critical Accounting Policies
Our financial statements reflect the selection and application of accounting policies which require management to make significant estimates and judgments. See Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies.” We believe that the following reflect the more critical accounting policies that currently affect our financial condition and results of operations.

| Fair Value of Energy Marketing and Risk Management Contracts and Derivatives

Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us. As a result, we are required to rely on internally developed price estimates when external quotes are unavailable. We derive our future price estimates, during periods, where external price quotes are unavailable, based on extrapolation of prices from prior periods where external price quotes are available. We perform this extrapolation using liquid and observable market prices and extending those prices to an internally generated long-term price forecast based on a generalized equilibrium model.

| Credit Reserves

In estimating the fair value of our derivatives, we must take into account the credit risk that our counterparties will not have the financial wherewithal to honor their contract commitments.
In establishing credit risk reserves we take into account historical default rate data published by the rating agencies based on the credit rating of each counterparty where we have realization exposure, as well as other published data and information.

| Liquidity Reserves

We value our forward positions at the mid-market price, or the price in the middle of the bid-ask spread. This creates a risk that the value reported by us as the fair value of our derivative positions will not represent the realizable value or probable loss exposure of our derivative positions if we are unable to liquidate those positions at the mid-market price. Adjusting for this liquidity risk states our derivative assets and liabilities at their most probable value. We use a two-step quantitative and qualitative analysis to determine our liquidity reserve.
In the first step we quantitatively derive an initial liquidity reserve assessment applying the following assumptions in calculating the initial liquidity reserve assessment: (1) where we have the capability to cover physical positions with our own assets, we assume no liquidity reserve is necessary because we will not have to cross the bid-ask spread in covering the position; (2) we record no reserve against our hedge positions because a high likelihood exists that we will hold our hedge positions to maturity or cover them with our own assets; and (3) where reserves are necessary, we base the reserves on the spreads observed using broker quotes as a starting point.
Using these assumptions, we calculate the net notional volume exposure at each location by commodity and multiply the result by one half of the bid-ask spread.

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The second step involves a qualitative analysis where the initial assessment may be adjusted for qualitative factors such as liquidity spreads observed through recent trading activity, strategies for liquidating open positions, and imprecision in or unavailability of broker quotes due to market illiquidity. Using this quantitative and qualitative information, we estimate the amount of probable liquidity risk exposure to us and we record this estimate as a liquidity reserve.

| Accounting for Commodity Contracts

Commodity contracts are evaluated to determine whether the contract is (1) accounted for as a lease (2) accounted for as a derivative (3) or accounted for as an executory contract and additionally whether the financial statement presentation is gross or net.
Accounting for Leases — We account for commodity contracts as leases per SFAS No. 13 , “Accounting for Leases,” (“SFAS No. 13”) and EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” (“EITF Issue No. 01-08”). EITF Issue No. 01-08 clarifies the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. Prior to adopting EITF Issue No. 01-08, we had accounted for certain contractual arrangements as leases under existing industry practices, and the adoption of EITF Issue No. 01-08 did not materially change our accounting for leases. Per SFAS No. 13, operating leases with minimum lease rentals which vary over time must be levelized over the term of the contract. We levelize these contracts on a straight-line basis. See Note 25 for additional information on our operating leases. For income statement presentation purposes, income from arrangements accounted for as leases is classified within electricity and steam revenue in our consolidated statements of operations.
Accounting for Derivatives — On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133 — an Amendment of FASB Statement No. 133,” SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an Amendment of FASB Statement No. 133,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” We currently hold six classes of derivative instruments that are impacted by the new pronouncement — foreign currency swaps, interest rate swaps, forward interest rate agreements, commodity financial instruments, commodity contracts, and physical options.
Consistent with the requirements of SFAS No. 133, we evaluate all of our contracts to determine whether or not they qualify as derivatives under the accounting pronouncements. For a given contract, there are typically three steps we use to determine its proper accounting treatment. First, based on the terms and conditions of the contract, as well as the applicable guidelines established by SFAS No. 133, we identify the contract as being either a derivative or non-derivative contract. Second, if the contract is not a derivative, we account for it as an executory contract. Alternatively, if the contract does qualify as a derivative under the guidance of SFAS No. 133, we evaluate whether or not it qualifies for the “normal” purchases and sales exception (as described below). If the contract qualifies for the exception, we may elect to apply the normal exception and account for as an executory contract. Finally, if the contract is a derivative, we apply the accounting treatment required by SFAS No. 133, which is outlined below in further detail.

| Normal Purchases and Sales

When we elect normal purchases and sales treatment, as defined by paragraph 10b. of SFAS No. 133 and amended by SFAS No. 138 and SFAS No. 149, the normal contracts are exempt from SFAS No. 133 accounting treatment. As a result, these contracts are not required to be recorded on the balance sheet at their fair values and any fluctuations in these values are not required to be reported within earnings. Probability of

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physical delivery from our generation plants, in the case of electricity sales, and to our generation plants, in the case of natural gas contracts, is required over the life of the contract within reasonable tolerances.
Two of our contracts that had been accounted for as normal contracts were subject to the special transition adjustment for their estimated future economic benefits upon adoption of DIG Issue No. C20, and we amortize the corresponding asset recorded upon adoption of DIG Issue No. C20 through a charge to earnings. Accordingly on October 1, 2003, the date we adopted DIG Issue No. C20, we recorded other current assets and other assets of approximately $33.5 million and $259.9 million, respectively, and a cumulative effect of a change in accounting principle of approximately $181.9 million, net of $111.5 million of tax. For periods subsequent to October 1, 2003, we again account for these two contracts as normal purchases and sales under the provisions of DIG Issue No. C20.

| Fair Value Hedges

As further defined in SFAS No. 133, fair value hedge transactions hedge the exposure to changes in the fair value of either all or a specific portion of a recognized asset or liability or of an unrecognized firm commitment. The accounting treatment for fair value hedges requires reporting both the changes in fair values of a hedged item (the underlying risk) and the hedging instrument (the derivative designated to offset the underlying risk) on both the balance sheet and the income statement. On that basis, when a firm commitment is associated with a hedge instrument that attains 100% effectiveness (under the effectiveness criteria outlined in SFAS No. 133), there is no net earnings impact because the earnings caused by the changes in fair value of the hedged item will move in an equal, but opposite, amount as the earnings caused by the changes in fair value of the hedging instrument. In other words, the earnings volatility caused by the underlying risk factor will be neutralized because of the hedge. For example, if we want to manage the price-induced fair value risk (i.e. the risk that market electric rates will rise, making a fixed price contract less valuable) associated with all or a portion of a fixed price power sale that has been identified as a “normal” transaction (as described above), we might create a fair value hedge by purchasing fixed price power. From that date and time forward until delivery, the change in fair value of the hedged item and hedge instrument will be reported in earnings with asset/liability offsets on the balance sheet. If there is 100% effectiveness, there is no net earnings impact. If there is less than 100% effectiveness, the fair value change of the hedged item (the underlying risk) and the hedging instrument (the derivative) will likely be different and the “ineffectiveness” will result in a net earnings impact.

| Cash Flow Hedges

As further defined in SFAS No. 133, cash flow hedge transactions hedge the exposure to variability in expected future cash flows (i.e., in our case, the price variability of forecasted purchases of gas and sales of power, as well as interest rate and foreign exchange rate exposure). In the case of cash flow hedges, the hedged item (the underlying risk) is generally unrecognized (i.e., not recorded on the balance sheet prior to delivery), and any changes in this fair value, therefore, will not be recorded within earnings. Conceptually, if a cash flow hedge is effective, this means that a variable, such as movement in power prices, has been effectively fixed, so that any fluctuations will have no net result on either cash flows or earnings. Therefore, if the changes in fair value of the hedged item are not recorded in earnings, then the changes in fair value of the hedging instrument (the derivative) must also be excluded from the income statement, or else a one-sided net impact on earnings will be reported, despite the fact that the establishment of the effective hedge results in no net economic impact. To prevent such a scenario from occurring, SFAS No. 133 requires that the fair value of a derivative instrument designated as a cash flow hedge be recorded as an asset or liability on the balance sheet, but with the offset reported as part of other comprehensive income, to the extent that the hedge is effective. Similar to fair value hedges, any ineffectiveness portion will be reflected in earnings.

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| Undesignated Derivatives

The fair values and changes in fair values of undesignated derivatives are recorded in earnings, with the corresponding offsets recorded as derivative assets or liabilities on the balance sheet. We have the following types of undesignated transactions:

| • | transactions executed at a location where we do not have an associated natural long (generation capacity) or short (fuel consumption requirements) position of sufficient quantity for the entire term of the transaction (e.g., power sales where we do not own generating assets or intend to acquire transmission rights for delivery from other assets for any portion of the contract term), and
| • | transactions executed with the intent to profit from short-term price movements, and
| • | discontinuance (de-designation) of hedge treatment prospectively consistent with paragraphs 25 and 32 of SFAS No. 133. In circumstances where we believe the hedge relationship is no longer necessary, we will remove the hedge designation and close out the hedge positions by entering into an equal and offsetting derivative position. Prospectively, the two derivative positions should generally have no net earnings impact because the changes in their fair values are offsetting.
| • | any other transactions that do not qualify for hedge accounting

Our Mark-to-Market Activity includes realized settlements of and unrealized mark-to-market gains and losses on both power and gas derivative instruments not designated as cash flow hedges, including those held for trading purposes. Our gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses. We present trading activity net in accordance with EITF Issue No. 02-03.
Accounting for Executory Contracts — Where commodity contracts do not qualify as leases or derivatives, the contracts are classified as executory contracts. These contracts apply traditional accrual accounting treatment unless the revenue must be levelized per EITF Issue No. 91-06, “Revenue Recognition of Long Term Power Sales Contracts.” We currently account for one commodity contract under EITF 91-06 which is levelized over the term of the agreement.
Accounting for Financial Statement Presentation — Where our derivative instruments are subject to a netting agreement and the criteria of FIN 39 “Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10 and SFAS No. 105)” are met, we present the derivative assets and liabilities on a net basis in our balance sheet. We chose this method of presentation because it is consistent with the way related mark-to-market gains and losses on derivatives are recorded in Consolidated Statements of Operations and within Other Comprehensive Income.
We account for certain of our power sales and purchases on a net basis under EITF Issue No. 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS 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 on a prospective basis on October 1, 2003. Transactions with either of the following characteristics are presented net in our Consolidated Condensed Financial Statements: (1) transactions executed in a back-to-back buy and sale pair, primarily because of market protocols; and (2) physical power purchase and sale transactions where our power schedulers net the physical flow of the power purchase against the physical flow of the power sale (or “book out” the physical power flows) as a matter of scheduling convenience to eliminate the need for actual power delivery. These book out transactions may occur with the same counterparty or between different counterparties where we have equal but offsetting physical purchase and delivery commitments.

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| Accounting for Long-Lived Assets

| Plant Useful Lives

Property, plant and equipment is stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. Depreciation is recorded utilizing the straight line method over the estimated original composite useful life, generally 35 years for baseload power plants and 40 years for peaking facilities, exclusive of the estimated salvage value, typically 10%.

| Impairment of Long-Lived Assets, Including Intangibles

We evaluate long-lived assets, such as property, plant and equipment, equity method investments, patents, and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Discussion of the impairment of oil and gas assets is covered under “Oil and Gas Property Valuations” below. Factors which could trigger an impairment include determination that a suspended project is not completed, significant underperformance relative to historical or projected future operating results, significant changes in the manner of our use of the acquired assets or the strategy for our overall business and significant negative industry or economic trends. Certain of our generating assets are located in regions with depressed demand and market spark spreads. Our forecasts assume that spark spreads will increase in future years in these regions as the supply and demand relationships improve.
The determination of whether an impairment of a power plant has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. The significant assumptions that we use in our undiscounted future cash flow estimates include the probability of completion of assets in development or construction the future supply and demand relationships for electricity and natural gas, and the expected pricing for those commodities and the resultant spark spreads in the various regions where we generate. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the fair value of the assets and recording a loss if the fair value was less than the book value. For equity method investments and assets identified as held for sale, the book value is compared to the estimated fair value to determine if an impairment loss is required. For equity method investments, we would record a loss when the decline in value is other than temporary.
Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors of our businesses. Our review of factors present and the resulting appropriate carrying value of our intangibles, and other long-lived assets are subject to judgments and estimates that management is required to make. Future events could cause us to conclude that impairment indicators exist and that our intangibles, and other long-lived assets might be impaired.

| Turbine Impairment Charges

A significant portion of our overall cost of constructing a power plant is the cost of the gas turbine-generators, steam turbine-generators and related equipment (collectively the “turbines”). The turbines are ordered primarily from three large manufacturers under long-term, build to order contracts. Payments are generally made over a two to four year period for each turbine. The turbine prepayments are included as a component of construction-in-progress if the turbines are assigned to specific projects probable of being built, and interest is capitalized on such costs. Turbines assigned to specific projects are not evaluated for impairment separately from the project as a whole. Prepayments for turbines that are not assigned to specific projects that are probable of being built are carried in other assets, and interest is not capitalized on such costs. Additionally, our commitments relating to future turbine payments are discussed in Note 25 of the Notes to Consolidated Financial Statements.
To the extent that there are more turbines on order than are allocated to specific construction projects, we determine the probability that new projects will be initiated to utilize the turbines or that the turbines will be resold to third parties. The completion of in progress projects and the initiation of new projects are dependent on our overall liquidity and the availability of funds for capital expenditures.

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In assessing the impairment of turbines, we must determine both the realizability of the progress payments to date that have been capitalized, as well as the probability that at future decision dates, we will cancel the turbines and apply the prepayments to the cancellation charge, or will proceed and pay the remaining progress payments in accordance with the original payment schedule.
We apply SFAS No. 5, “Accounting for Contingencies” to evaluate potential future cancellation obligations. We apply SFAS No. 144 to evaluate turbine progress payments made to date for, and the carrying value of, delivered turbines not assigned to projects. At the reporting date, if we believe that it is probable that we will elect the cancellation provisions on future decision dates, then the expected future termination payment is also expensed.

| Oil and Gas Property Valuations

Successful Efforts Method of Accounting. We follow the successful efforts method of accounting for oil and natural gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated, or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful.
The successful efforts method of accounting relies on management’s judgment in the designation of wells as either exploratory or developmental, which determines the proper accounting treatment of costs incurred. During 2004 we drilled 75 (net 39.3) development wells and 24 (net 14.5) exploratory wells, of which 71 (net 35.8) development and 21 (net 13.0) exploration were successful. Our operational results may be significantly impacted if we decide to drill in a new exploratory area, which will result in increased seismic costs and potentially increased dry hole costs if the wells are determined to be not successful.
Successful Efforts Method of Accounting v. Full Cost Method of Accounting. Under the successful efforts method, unsuccessful exploration well cost, geological and geophysical costs, delay rentals, and general and administrative expenses directly allocable to acquisition, exploration, and development activities are charged to exploration expense as incurred; whereas, under the full cost method these costs are capitalized and amortized over the life of the reserves.
A significant sale (usually multiple fields) would have to occur before a gain or loss would be recognized under the full cost method. However, under the successful efforts method, when only an entire cost center (generally a field) is sold, a gain or loss is recognized.
For impairment evaluation purposes, successful efforts requires that individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows, which is generally on a field-by-field basis. Under full cost impairment review, all properties in the depreciation, depletion and amortization pools based on geography are assessed against a ceiling based on discounted cash flows, with certain adjustments.
Though successful efforts and full cost methods are both acceptable under GAAP, successful efforts is used by most major companies due to such method being more reflective of current operating results due to the expensing of certain exploration activities.
Oil and Gas Reserves. The process of estimating quantities of proved developed and proved undeveloped crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. Estimates of economically recoverable oil and gas reserves and future net cash flows depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of governmental regulations, operating and workover costs, severance taxes and development costs, all of which may vary considerably from actual results. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such properties.

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We based our estimates of proved developed and proved undeveloped reserves as of December 31, 2004, 2003 and 2002, on estimates made by Netherland, Sewell & Associates, Inc. for reserves in the United States, and by Gilbert Laustsen Jung Associates Ltd. for 2003 and 2002 reserves in Canada, both independent petroleum engineering firms.
Impairment of Oil and Gas Properties. We review our oil and gas properties periodically (at least annually) to determine if impairment of such properties is necessary. Property impairments may occur if a field discovers lower than anticipated reserves, reservoirs produce below original estimates or if commodity prices fall below a level that significantly affects anticipated future cash flows on the property. Proved oil and gas property values are reviewed when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value based on proved reserves and other market factors. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the current period. During the year ended December 31, 2004, we recorded $202.1 million in impairment charges related to reduced proved reserve projections based on the year end independent engineers report. These impairments are discussed further in Note 4 of the Notes to Consolidated Financial Statements.

| Capitalized Interest

We capitalize interest using two methods: (1) capitalized interest on funds borrowed for specific construction projects and (2) capitalized interest on general corporate funds. For capitalization of interest on specific funds, we capitalize the interest cost incurred related to debt entered into for specific projects under construction or in the advanced stage of development. The methodology for capitalizing interest on general funds, consistent with paragraphs 13 and 14 of SFAS No. 34, “Capitalization of Interest Cost,” begins with a determination of the borrowings applicable to our qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off other debt. We use our best judgment in determining which borrowings represent the cost of financing the acquisition of the assets. The primary debt instruments included in the rate calculation of interest incurred on general corporate funds have been our Senior Notes, our term loan facilities and our secured working capital revolving credit facility with adjustments made as debt is retired or new debt is issued. The interest rate is derived by dividing the total interest cost by the average borrowings. This weighted average interest rate is applied to our average qualifying assets in excess of specific debt on which interest is capitalized. To qualify for interest capitalization, we must continue to make significant progress on the construction of the assets. See Note 4 of the Notes to Consolidated Financial Statements for additional information about the capitalization of interest expense.

| Accounting for Income and Other Taxes

To arrive at our worldwide income tax provision and other tax balances, significant judgment is required. In the ordinary course of a global business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Some of these uncertainties arise as a consequence of the treatment of capital assets, financing transactions, multistate taxation of operations and segregation of foreign and domestic income and expense to avoid double taxation. Although we believe that our estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our historical tax provisions and accruals. Such differences could have a material impact on our income tax provision, other tax accounts and net income in the period in which such determination is made.
We record a valuation allowance to reduce our deferred tax assets to the amount of future tax benefit that is more likely than not to be realized. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance, there is no assurance that the valuation allowance would not need to be increased to cover additional deferred tax assets that may not be realizable. Any increase in the valuation allowance could have a material adverse impact on our income tax provision and net income in the period in which such determination is made.

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We provide for United States income taxes on the earnings of foreign subsidiaries unless they are considered permanently invested outside the United States. At December 31, 2004, we had no cumulative undistributed earnings of foreign subsidiaries.
Our effective income tax rates for continuing operations were (38.6)%, 9.0% and 28.8% in fiscal 2004, 2003 and 2002, respectively. The effective tax rate in all periods is the result of profits Calpine Corporation and its subsidiaries earned in various tax jurisdictions, both foreign and domestic, that apply a broad range of income tax rates. The provision for income taxes differs from the tax computed at the federal statutory income tax rate due primarily to state taxes, tax credits, other permanent differences and earnings considered as permanently reinvested in foreign operations and the effect of the treatment by foreign jurisdictions of cross border financings. Future effective tax rates could be adversely affected if earnings are lower than anticipated in countries where we have lower statutory rates, if unfavorable changes in tax laws and regulations occur, or if we experience future adverse determinations by taxing authorities after any related litigation. Our foreign taxes at rates other than statutory include the benefit of cross border financings as well as withholding taxes and foreign valuation allowance.
Under SFAS No. 109, “Accounting for Income Taxes,” deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities, and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. SFAS No. 109 provides for the recognition of deferred tax assets if realization of such assets is more likely than not. Based on the weight of available evidence, we have provided a valuation allowance against certain deferred tax assets. The valuation allowance was based on the historical earnings patterns within individual tax jurisdictions that make it uncertain that we will have sufficient income in the appropriate jurisdictions to realize the full value of the assets. We will continue to evaluate the realizability of the deferred tax assets on a quarterly basis.
At December 31, 2004, we had credit carryforwards of $50.4 million. These credits relate to Energy Credits, Research and Development Credits, Alternative Minimum Tax Credits and other miscellaneous state credits. The net operating loss carryforward consists of federal and state carryforwards of approximately $2.3 billion which expire between 2017 and 2019. The federal and state net operating loss carryforwards available are subject to limitations on their annual usage. We also have loss carryforwards in certain foreign subsidiaries, resulting in tax benefits of approximately $152 million, the majority of which expire by 2008. We provided a valuation allowance on certain state and foreign tax jurisdiction deferred tax assets to reduce the gross amount of these assets to the extent necessary to result in an amount that is more likely than not of being realized. Realization of the deferred tax assets and net operating loss carryforwards is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

| Variable Interest Entities and Primary Beneficiary

In determining whether an entity is a variable interest entity (“VIE”) and whether or not we are the Primary Beneficiary, we use significant judgment regarding the adequacy of an entity’s equity relative to maximum expected losses, amounts and timing of estimated cash flows, discount rates and the probability of achieving a specific expected future cash flow outcome for various cash flow scenarios. Due to the long-term nature of our investment in a VIE and its underlying assets, our estimates of the probability-weighted future expected cash flow outcomes are complex and subjective, and are based, in part, on our assessment of future commodity prices based on long-term supply and demand forecasts for electricity and natural gas, operational performance of the underlying assets, legal and regulatory factors affecting our industry, long-term interest rates and our current credit profile and cost of capital. As a result of applying the complex guidance outlined in FIN 46-R, we may be required to consolidate assets we do not legally own and liabilities that we are not legally obligated to satisfy. Also, future changes in a VIE’s legal or capital structure may cause us to reassess whether or not we are the Primary Beneficiary and may result in our consolidation or deconsolidation of that entity.

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We adopted FIN 46-R for our equity method joint ventures and operating lease arrangements containing fixed price purchase options, our wholly owned subsidiaries that are subject to long-term power purchase agreements and tolling arrangements and our wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests as of March 31, 2004, and for our investments in SPEs as of December 31, 2003.

| Joint Venture Investments and Operating Leases with Fixed Price Options

On application of FIN 46-R, we evaluated our investments in joint venture investments and operating lease arrangements containing fixed price purchase options and concluded that, in some instances, these entities were VIEs. However, in these instances, we were not the Primary Beneficiary, as we would not absorb a majority of these entities’ expected variability. An enterprise that holds a significant variable interest in a VIE is required to make certain disclosures regarding the nature and timing of its involvement with the VIE and the nature, purpose, size and activities of the VIE. The fixed price purchase options under our operating lease arrangements were not considered significant variable interests. However, the joint ventures in which we invested, and which did not qualify for the definition of a business scope exception outlined in paragraph 4(h) of FIN 46-R, were considered significant variable interests and the required disclosures have been made in Note 7 of the Notes to Consolidated Financial Statements for these joint venture investments.

| Significant Long-Term Power Sales and Tolling Agreements

An analysis was performed for our wholly owned subsidiaries with significant long-term power sales or tolling agreements. Certain of our 100% owned subsidiaries were deemed to be VIEs by virtue of the power sales and tolling agreements which meet the definition of a variable interest under FIN 46-R. However, in all cases, we absorbed a majority of the entity’s variability and continue to consolidate our wholly owned subsidiaries. As part of our quantitative assessment, a fair value methodology was used to determine whether we or the power purchaser absorbed the majority of the subsidiary’s variability. As part of our analysis, we qualitatively determined that power sales or tolling agreements with a term for less than one-third of the facility’s remaining useful life or for less than 50% of the entity’s capacity would not cause the power purchaser to be the Primary Beneficiary, due to the length of the economic life of the underlying assets. Also, power sales and tolling agreements meeting the definition of a lease under EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” were not considered variable interests, since lease payments create rather than absorb variability, and therefore, do not meet the definition of a variable interest.

| Preferred Interests issued from Wholly-Owned Subsidiaries

A similar analysis was performed for our wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests. These entities were determined to be VIEs in which we absorb the majority of the variability, primarily due to the debt characteristics of the preferred interest, which are classified as debt in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” in our Consolidated Condensed Balance Sheets. As a result, we continue to consolidate these wholly owned subsidiaries.

| Investments in Special Purpose Entities

Significant judgment was required in making an assessment of whether or not a VIE was an SPE for purposes of adopting and applying FIN 46, as originally issued at December 31, 2003. Since the current accounting literature does not provide a definition of an SPE, our assessment was primarily based on the degree to which the VIE aligned with the definition of a business outlined in FIN 46-R. Entities that meet the definition of a business outlined in FIN 46-R and that satisfy other formation and involvement criteria are not subject to the FIN 46-R consolidation guidelines. The definitional characteristics of a business include having: inputs such as long-lived assets; the ability to obtain access to necessary materials and employees; processes such as strategic management, operations and resource management; and the ability to obtain access to the customers that purchase the outputs of the entity. Based on this assessment, we determined that six VIE

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investments were in SPEs requiring further evaluation and were subject to the application of FIN 46, as originally issued, as of October 1, 2003: CNEM, PCF, PCF III and the Trusts.
On May 15, 2003, our wholly owned subsidiary, CNEM, completed the $82.8 million monetization of an existing power sales agreement with BPA. CNEM borrowed $82.8 million secured by the spread between the BPA contract and certain fixed power purchase contracts. CNEM was established as a bankruptcy-remote entity and the $82.8 million loan is recourse only to CNEM’s assets and is not guaranteed by us. CNEM was determined to be a VIE in which we were the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into our accounts as of June 30, 2003.
On June 13, 2003, PCF, a wholly-owned stand-alone subsidiary of CES, completed the offering of the PCF Notes, totaling $802.2 million. To facilitate the transaction, we formed PCF as a wholly owned, bankruptcy remote entity with assets and liabilities consisting of certain transferred power purchase and sales contracts, which serve as collateral for the PCF Notes. The PCF Notes are non-recourse to our other consolidated subsidiaries. PCF was originally determined to be a VIE in which we were the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into our accounts as of June 30, 2003.
As a result of the debt reserve monetization consummated on June 2, 2004, we were required to evaluate our new investment in PCF III and to reevaluate our investment in PCF under FIN 46-R (effective March 31, 2004). We determined that the entities were VIEs but we were not the Primary Beneficiary and, therefore, were required to deconsolidate the entities as of June 30, 2004.
Upon the application of FIN 46, as originally issued at December 31, 2003, for our investments in SPEs, we determined that our equity investment in the Trusts was not considered at-risk as defined in FIN 46 and that we did not have a significant variable interest in the Trusts. Consequently, we deconsolidated the Trusts as of December 31, 2003.
We created CNEM, PCF, PCF III and the Trusts to facilitate capital transactions. However, in cases such as these where we have a continuing involvement with the assets held by the deconsolidated SPE, we account for the capital transaction with the SPE as a financing rather than a sale under EITF Issue No. 88-18, “Sales of Future Revenue” (“EITF Issue No. 88-18”) or Statement of Financial Accounting Standard No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities — a Replacement of FASB Statement No. 125” (“SFAS No. 140”), as appropriate. When EITF Issue No. 88-18 and SFAS No. 140 require us to account for a transaction as a financing, derecognition of the assets underlying the financing is prohibited, and the proceeds received from the transaction must be recorded as debt. Accordingly, in situations where we account for transactions as financings under EITF Issue No. 88-18 or SFAS No. 140, we continue to recognize the assets and the debt of the deconsolidated SPE on our balance sheet. See Note 2 of the Notes to Consolidated Financial Statements for a summary on how we account for our SPEs when we have continuing involvement under EITF Issue No. 88-18 or SFAS No. 140.

| Stock Based Compensation

Prior to 2003, we accounted for qualified stock compensation under APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Under APB 25, we were required to recognize stock compensation as expense only to the extent that there is a difference in value between the market price of the stock being offered to employees and the price those employees must pay to acquire the stock. The expense measurement methodology provided by APB 25 is commonly referred to as the “intrinsic value based method.” To date, our stock compensation program has been based primarily on stock options whose exercise prices are equal to the market price of Calpine stock on the date of the stock option grant; consequently, under APB 25 we had historically incurred minimal stock compensation expense. On January 1, 2003, we prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”) as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (“SFAS No. 148”). SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for companies that voluntarily change their accounting for stock-based compensation from the less preferred

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intrinsic value based method to the more preferred fair value based method. Prior to its amendment, SFAS No. 123 required that companies enacting a voluntary change in accounting principle from the intrinsic value methodology provided by APB 25 could only do so on a prospective basis; no adoption or transition provisions were established to allow for a restatement of prior period financial statements. SFAS No. 148 provides two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We elected to adopt the provisions of SFAS No. 123 on a prospective basis; consequently, we are required to provide a pro-forma disclosure of net income and earnings per share as if SFAS No. 123 accounting had been applied to all prior periods presented within our financial statements. In December 2004 the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) (“SFAS No. 123-R”), Share Based Payments. This Statement revises SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB 25, Accounting for Stock Issued to Employees, and its related implementation guidance. This statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions), which must be recognized over the period during which an employee is required to provide service in exchange for the award — the requisite service period (usually the vesting period). Adoption of SFAS No. 123-R is not expected to materially impact our operating results, cash flows or financial position, due to the aforementioned discussion surrounding our prior adoption of SFAS No. 123 as amended by SFAS No. 148.
Under SFAS No. 123, the fair value of a stock option or its equivalent is estimated on the date of grant by using an option-pricing model, such as the Black-Scholes model or a binomial model. The option-pricing model selected should take into account, as of the stock option’s grant date, the exercise price and expected life of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock, and the risk-free interest rate for the expected term of the stock option.
The fair value calculated by this model is then recognized as compensation expense over the period in which the related employee services are rendered. Unless specifically defined within the provisions of the stock option granted, the service period is presumed to begin on the grant date and end when the stock option is fully vested. Depending on the vesting structure of the stock option and other variables that are built into the option-pricing model, the fair value of the stock option is recognized over the service period using either a straight-line method (the single option approach) or a more conservative, accelerated method (the multiple option approach). For consistency, we have chosen the multiple option approach, which we have used historically for pro-forma disclosure purposes. The multiple option approach views one four-year option grant as four separate sub-grants, each representing 25% of the total number of stock options granted. The first sub-grant vests over one year, the second sub-grant vests over two years, the third sub-grant vests over three years, and the fourth sub-grant vests over four years. Under this scenario, over 50% of the total fair value of the stock option grant is recognized during the first year of the vesting period, and nearly 80% of the total fair value of the stock option grant is recognized by the end of the second year of the vesting period. By contrast, if we were to apply the single option approach, only 25% and 50% of the total fair value of the stock option grant would be recognized as compensation expense by the end of the first and second years of the vesting period, respectively.
We have selected the Black-Scholes model, primarily because it has been the most commonly recognized options-pricing model among U.S.-based corporations. Nonetheless, we believe this model tends to overstate the true fair value of our employee stock options in that our options cannot be freely traded, have vesting requirements, and are subject to blackout periods during which, even if vested, they cannot be traded. We will monitor valuation trends and techniques as more companies adopt SFAS No. 123-R and as additional guidance is provided by FASB and the SEC and review our choices as appropriate in the future. The key assumption in our Black-Scholes model is the expected life of the stock option, because it is this figure that drives our expected volatility calculation, as well as our risk-free interest rate. The expected life of the option relies on two factors — the option’s vesting period and the expected term that an employee holds the option once it has vested. There is no single method described by SFAS No. 123 for predicting future events such as

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how long an employee holds on to an option or what the expected volatility of a company’s stock price will be; the facts and circumstances are unique to different companies and depend on factors such as historical employee stock option exercise patterns, significant changes in the market place that could create a material impact on a company’s stock price in the future, and changes in a company’s stock-based compensation structure.
We base our expected option terms on historical employee exercise patterns. We have segregated our employees into four different categories based on the fact that different groups of employees within our company have exhibited different stock exercise patterns in the past, usually based on employee rank and income levels. Therefore, we have concluded that we will perform separate Black-Scholes calculations for four employee groups — executive officers, senior vice presidents, vice presidents, and all other employees.
We compute our expected stock price volatility based on our stock’s historical movements. For each employee group, we measure the volatility of our stock over a period that equals the expected term of the option. In the case of our executive officers, this means we measure our stock price volatility dating back to our public inception in 1996, because these employees are expected to hold their options for over 7 years after the options have fully vested. In the case of other employees, volatility is only measured dating back 4 years. In the short run, this causes other employees to generate a higher volatility figure than the other company employee groups because our stock price has fluctuated significantly in the past four years. As of December 31, 2004, the volatility for our employee groups ranged from 69%-98%.
See Note 21 of the Notes to Consolidated Financial Statements for additional information related to the January 1, 2003, adoption of SFAS Nos. 123 and 148 and the pro-forma impact that they would have had on our net income for the years ended December 31, 2004, 2003 and 2002.
Initial Adoption of New Accounting Standards in 2004
See “Application of Critical Accounting Policies” above for our adoption of FIN 46-R relating to variable interest entities and primary beneficiary.
EITF Issue No. 04-08 — On September 30, 2004, the EITF reached a final consensus on EITF Issue No. 04-08: “The Effect of Contingently Convertible Debt on Diluted Earnings per Share” (“EITF Issue No. 04-08”). The guidance in EITF Issue No. 04-08 is effective for periods ending after December 15, 2004, and must be applied by retroactively restating previously reported earnings per share results. The consensus requires companies that have issued contingently convertible instruments with a market price trigger to include the effects of the conversion in diluted earnings per share (if dilutive), regardless of whether the price trigger had been met. Prior to this consensus, contingently convertible instruments were not included in diluted earnings per share if the price trigger had not been met. Typically, the affected instruments are convertible into common stock of the issuer after the issuer’s common stock price has exceeded a predetermined threshold for a specified time period. Calpine’s $634 million of 2023 Convertible Senior Notes and $736 million aggregate principal amount at maturity of 2014 Convertible Notes outstanding at December 31, 2004, are affected by the new guidance. Depending on the closing price of the Company’s common stock at the end of each reporting period, the conversion provisions in these Contingent Convertible Notes may significantly impact the reported diluted earnings per share amounts in future periods.

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For the twelve months ended December 31, 2004, approximately 8.6 million weighted common shares potentially issuable under the Company’s outstanding 2014 Convertible Notes were excluded from the diluted earnings per share calculations as the inclusion of such shares would have been antidilutive because of the Company’s net loss. The 2023 Convertible Senior Notes would not have impacted the diluted EPS calculation for any reporting period since issuance in November 2003, because the Company’s closing stock price at each period end was below the conversion price.
Summary of Dilution Potential of Our Contingent Convertible Notes: 2023 Convertible Senior Notes and 2014 Convertible Notes — The table below assumes normal conversion for the 2014 Convertible Notes and the 2023 Convertible Senior Notes in which the principal amount is paid in cash, and the excess up to the conversion value is paid in shares of Calpine common stock. The table shows only the potential impact of our two contingent convertible notes issuances and does not include the potential dilutive effect of HIGH TIDES III, the remaining 2006 Convertible Senior Notes or employee stock options. Additionally, we are still assessing the potential impact of the SFAS No. 128-R exposure draft on our convertible issues. See Note 2 of the Notes to Consolidated Condensed Financial Statements for more information.

|  | 2014 |  |  | 2023 |
|  | Convertible |  |  | Convertible |
|  | Notes |  |  | Senior Notes |
Size of issuance |  | $ | 736,000,000 |  |  | $ | 633,775,000 |
Conversion price per share |  | $ | 3.85 |  |  | $ | 6.50 |
Conversion rate |  |  | 259.7403 |  |  |  | 153.8462 |
Trigger price (20% over conversion price) |  | $ | 4.62 |  |  | $ | 7.80 |

| Additional Shares

|  | 2014 |  |  | 2023 |  |  |  |  |  |  |
|  | Convertible |  |  | Convertible |  |  | Share |  |  |  |  | Dilution in |
Future Calpine Common Stock Price |  | Notes* |  |  | Senior Notes |  |  | Subtotal |  |  | Share Increase |  |  | EPS |
$5.00 |  |  | 43,968,831 |  |  |  | 0 |  |  |  | 43,968,831 |  |  |  | 9.8 | % |  |  | 8.9 | %
$7.50 |  |  | 93,035,498 |  |  |  | 13,000,542 |  |  |  | 106,036,040 |  |  |  | 23.7 | % |  |  | 19.2 | %
$10.00 |  |  | 117,568,831 |  |  |  | 34,126,375 |  |  |  | 151,695,207 |  |  |  | 33.9 | % |  |  | 25.3 | %
$20.00 |  |  | 154,368,831 |  |  |  | 65,815,125 |  |  |  | 220,183,957 |  |  |  | 49.2 | % |  |  | 33.0 | %
$40.00 |  |  | 172,768,831 |  |  |  | 81,659,500 |  |  |  | 254,428,332 |  |  |  | 56.9 | % |  |  | 36.2 | %
$100.00 |  |  | 183,808,831 |  |  |  | 91,166,125 |  |  |  | 274,974,957 |  |  |  | 61.4 | % |  |  | 38.1 | %
Basic earnings per share base at December 31, 2004 |  |  | 447,509,231 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

* | In the case of the 2014 Convertible Notes, since the conversion value is set for any given common stock price, more shares would be issued when the accreted value is less than $1,000 than in the table above since the accreted value (initially $839 per bond) is paid in cash, and the balance of the conversion value is paid in shares. The incremental shares assuming conversion when the accreted value is only $839 per bond are shown in the table below:

|  | Incremental |
Future Calpine Common Stock Price |  | Shares |
$5.00 |  |  | 23,699,200 |
$7.50 |  |  | 15,799,467 |
$10.00 |  |  | 11,849,600 |
$20.00 |  |  | 5,924,800 |
$40.00 |  |  | 2,962,400 |
$100.00 |  |  | 1,184,960 |

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Item 7A. | Quantitative and Qualitative Disclosures About Market Risk

The information required hereunder is set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Market Risks.”

Item 8. | Financial Statements and Supplementary Data

The information required hereunder is set forth under “Reports of Independent Registered Public Accounting Firms,” “Consolidated Balance Sheets,” “Consolidated Statements of Operations,” “Consolidated Statements of Stockholders’ Equity,” “Consolidated Statements of Cash Flows,” and “Notes to Consolidated Financial Statements” included in the Consolidated Financial Statements that are a part of this report. Other financial information and schedules are included in the Consolidated Financial Statements that are a part of this report.

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

None.

Item 9A. | Controls and Procedures

Disclosure Controls and Procedures
Calpine Corporation (the “Company”) maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s Securities Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure.
As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s Disclosure Committee and management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures were not effective, because of the material weakness discussed below. In light of this material weakness, the Company performed additional analysis and post-closing procedures to ensure its consolidated financial statements are prepared in accordance with generally accepted accounting principles (“GAAP”). Accordingly, management believes that the financial statements included in this report fairly present in all material respects the Company’s financial condition, results of operations and cash flows for the periods presented.
Management’s Report on Internal Control over Financial Reporting
The management of Calpine Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. In making its assessment of internal control over financial reporting, management used the criteria described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. As of December 31, 2004, the Company did not maintain effective controls over the accounting for income taxes and the determination of current income taxes payable, deferred income tax

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assets and liabilities and the related income tax provision (benefit) for continuing and discontinued operations. Specifically, the Company did not have effective controls in place to (i) identify and evaluate in a timely manner the tax implications of the repatriation of funds from Canada (ii) appropriately determine the allocation of the tax provision between continuing and discontinued operations (iii) ensure there was adequate communication from the tax department to the accounting departments relating to the preparation of the tax provision (iv) ensure all elements of the income tax provision were mathematically correct and (v) ensure the rationale for certain tax positions was adequately documented. This control deficiency resulted in the restatement of the Company’s consolidated financial statements for the three and nine months ended September 30, 2004, as well as income tax related audit adjustments to the fourth quarter 2004 consolidated financial statements. Additionally, this control deficiency could result in a misstatement of current income taxes payable, deferred income tax assets and liabilities and the related income tax provision (benefit) for continuing and discontinued operations that would result in a material misstatement to annual or interim financial statements that would not be prevented or detected. Accordingly, management determined that this control deficiency constitutes a material weakness. Because of this material weakness, we have concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2004, based on criteria in Internal Control — Integrated Framework.
Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Remediation of Material Weakness
As discussed in Management’s Report on Internal Control over Financial Reporting, as of December 31, 2004, there was a material weakness in the Company’s internal control over financial reporting.
Prior to the fourth quarter of 2004, we identified certain deficiencies in our tax accounting processes, procedures and controls. Although we had processes and systems in place relating to the preparation and review of the interim and annual income tax provisions, we subsequently determined that these controls were not adequate.
In 2005, the Company is taking the following steps to improve its internal controls relating to the preparation and review of interim and annual income tax provisions, including the accounting for current income taxes payable, deferred income tax assets and liabilities and the related income tax provision:

| • | Complete the implementation of the CorpTax computer application to automate more of the tax analysis and provision processes and improve clarity of supporting documentation and reports;
| • | Will add resources in the tax and accounting departments as well as additional tax accounting training for key personnel and will continue to monitor staffing levels in the future; and
| • | Engage third party tax experts to review the details of the income tax calculations.

The Company believes it is taking steps necessary to remediate this material weakness and will continue to monitor the effectiveness of these procedures and will continue to make any changes that management deems appropriate.
Changes in Internal Control Over Financial Reporting
Calpine continuously seeks to improve the efficiency and effectiveness of our internal controls. This results in refinements to processes throughout the Company. However, there was no change in our internal control over financial reporting that occurred during the last fiscal quarter of 2004 that has materially affected, or is reasonably likely to materially affect, Calpine’s internal control over financial reporting.

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Item 9B. | Other Information

Consulting Agreement with George J. Stathakis
Effective January 1, 2005, we entered into a consulting agreement with George J. Stathakis, a member of our Board of Directors, pursuant to which Mr. Stathakis will provide advice and guidance on various management issues to our President and members of the President’s senior staff. The consulting agreement is filed as Exhibit 10.3.6.1 to this Report.
The term of the consulting agreement is one year (until December 31, 2005) and may be extended upon the mutual agreement of the parties. We or Mr. Stathakis may terminate the consulting agreement at any time by giving thirty days’ written notice to the other.
Mr. Stathakis will receive a monthly retainer fee of $5,000. Mr. Stathakis was also granted an option to purchase 10,000 shares of common stock pursuant to the Discretionary Option Grant Program of our 1996 Stock Incentive Plan, as amended. The exercise price of the option is $3.80 per share (representing the closing price of Calpine common stock on January 3, 2005). The option has a ten-year term and will vest in twelve monthly installments.
Management Incentive Plan
On December 14, 2004, the Executive Committee of the Board of Directors of Calpine Corporation approved corporate and executive corporate performance goals under its Management Incentive Plan (“MIP”) for the year ending December 31, 2005. The MIP provides employees a cash bonus based on the achievement of annual corporate goals and objectives and individual performance. The purpose of the MIP is to assist us in attracting and retaining desired talent, building team effort, recognizing achievement of predetermined business objectives, and providing increased performance motivation. Calpine North American employees, other than the operations and maintenance hourly employees, are eligible to participate in the MIP in 2005.
Among the goals adopted under the MIP were numerous financial goals relating to liquidity, operating and other expense reduction and earnings. Non-financial goals relating to safety and workforce diversity, among other areas, were adopted. In 2006, the Compensation Committee of our Board of Directors will evaluate our progress in achieving the adopted goals, both financial and other, in determining the level of funding for bonuses under the MIP. The MIP is filed as Exhibit 10.3.13 to this Report.
PART III

Item 10. | Directors and Executive Officers of the Registrant

Incorporated by reference to Proxy Statement relating to the 2005 Annual Meeting of Stockholders to be filed.

Item 11. | Executive Compensation

Incorporated by reference to Proxy Statement relating to the 2005 Annual Meeting of Stockholders to be filed.

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

Incorporated by reference to Proxy Statement relating to the 2005 Annual Meeting of Stockholders to be filed.

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Equity Compensation Plan Information
The following table provides certain information, as of December 31, 2004, concerning certain compensation plans under which our equity securities are authorized for issuance.

|  |  |  |  |  | Number of Securities |
|  |  |  |  |  | Remaining Available |
|  |  |  |  |  | for Future Issuance |
|  | Number of Securities |  |  |  |  | Under Equity |
|  | to be Issued Upon |  |  | Weighted Average |  |  | Compensation Plans |
|  | Exercise of |  |  | Exercise Price of |  |  | (Excluding |
|  | Outstanding Options, |  |  | Outstanding Options, |  |  | Securities Reflected |
Plan Category |  | Warrants, and Rights |  |  | Warrants and Rights |  |  | in Column(a)) |
Equity compensation plans approved by security holders |  |  |  |  |  |  |  |  |  |  |  |
| Calpine Corporation 1992 Stock Incentive Plan(1) |  |  | 1,752,590 |  |  | $ | 1.070 |  |  |  | — |
| Encal Energy Ltd. Stock Option Plan(2) |  |  | 87,274 |  |  | $ | 35.692 |  |  |  | — |
| Calpine Corporation 1996 Stock Incentive Plan |  |  | 32,937,993 |  |  | $ | 8.734 |  |  |  | 22,205,905 |
| Calpine Corporation 2000 Employee Stock Purchase Plan |  |  | — |  |  | $ | — |  |  |  | 15,859,702 |
| Equity compensation plans not approved by security holders |  |  | — |  |  |  | — |  |  |  | — |
|  | Total |  |  | 34,777,857 |  |  | $ | 8.42 |  |  |  | 38,065,607 |

(1) | The Calpine Corporation 1992 Stock Incentive Plan was approved in 1992 by the Company’s sole security holder at the time, Electrowatt Ltd.
(2) | In connection with the merger with Encal Energy Ltd., which closed in 2001, we assumed the Encal Energy Fifth Amended and Restated Stock Option Plan. 87,274 shares of our common stock are subject to issuance upon exercise of options granted pursuant to this plan at a weighted average exercise price of $35.692. Other than the shares reserved for future issuance upon the exercise of these options, there are no securities available for future issuance under this Plan.

Item 13. | Certain Relationships and Related Transactions

Incorporated by reference to Proxy Statement relating to the 2005 Annual Meeting of Stockholders to be filed.

Item 14. | Principal Accounting Fees and Services

Incorporated by reference to Proxy Statement relating to the 2005 Annual Meeting of Stockholders to be filed.
PART IV

Item 15. | Exhibits, Financial Statement Schedules

(a)-1. Financial Statements and Other Information
The following items appear in Appendix F of this report:

| Reports of Independent Registered Public Accounting Firms
| Consolidated Balance Sheets December 31, 2004 and 2003
| Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003, and 2002

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| Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003, and 2002
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002
| Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003, and 2002
| Supplemental Oil and Gas Disclosures

(a)-2. Financial Statement Schedules
Schedule II — Valuation and Qualifying Accounts
(b) Exhibits
The following exhibits are filed herewith unless otherwise indicated:

Exhibit |  |
Number |  | Description
| 2 | .1 |  | Purchase and Sale Agreement, dated July 1, 2004, among Calpine Corporation (the “Company”), Calpine Natural Gas L.P. and Pogo Producing Company.(a)
| 2 | .2 |  | Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Natural Gas L.P. and Bill Barrett Corporation.(a)
| 2 | .3 |  | Asset and Trust Unit Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Canada Natural Gas Partnership, Calpine Energy Holdings Limited, PrimeWest Gas Corp. and PrimeWest Energy Trust.(a)
| 3 | .1 |  | Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004.(b)
| 3 | .2 |  | Amended and Restated By-laws of the Company.(c)
| 4 | .1.1 |  | Indenture dated as of May 16, 1996, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(d)
| 4 | .1.2 |  | First Supplemental Indenture dated as of August 1, 2000, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(e)
| 4 | .1.3 |  | Second Supplemental Indenture dated as of April 26, 2004, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(f)
| 4 | .2.1 |  | Indenture dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(g)
| 4 | .2.2 |  | Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(h)
| 4 | .2.3 |  | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e)
| 4 | .2.4 |  | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f)
| 4 | .3.1 |  | Indenture dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(i)
| 4 | .3.2 |  | Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(i)
| 4 | .3.3 |  | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e)
| 4 | .3.4 |  | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f)
| 4 | .4.1 |  | Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(j)

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Exhibit |  |  |
Number |  |  | Description
| 4 | .4.2 |  | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e)
| 4 | .4.3 |  | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f)
| 4 | .5.1 |  | Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(j)
| 4 | .5.2 |  | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e)
| 4 | .5.3 |  | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f)
| 4 | .6.1 |  | Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(k)
| 4 | .6.2 |  | First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(e)
| 4 | .6.3 |  | Second Supplemental Indenture dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee.(l)
| 4 | .7.1 |  | Amended and Restated Indenture dated as of October 16, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee.(m)
| 4 | .7.2 |  | Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(n)
| 4 | .7.3 |  | First Amendment, dated as of October 16, 2001, to Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(m)
| 4 | .8.1 |  | Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(m)
| 4 | .8.2 |  | First Supplemental Indenture, dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(m)
| 4 | .8.3 |  | Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(m)
| 4 | .8.4 |  | First Amendment, dated as of October 18, 2001, to Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(m)
| 4 | .9 |  | Indenture, dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(o)
| 4 | .10 |  | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o)
| 4 | .11 |  | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o)
| 4 | .12 |  | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o)
| 4 | .13.1 |  | Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee, including form of Notes.(p)
| 4 | .13.2 |  | Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(p)
| 4 | .13.3 |  | Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q)

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Exhibit |  |  |
Number |  |  | Description
| 4 | .13.4 |  | Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q)
| 4 | .14 |  | Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy Center, as Guarantors, and Wilmington Trust Company, as Trustee and Collateral Agent, including form of Notes.(p)
| 4 | .15 |  | Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(q)
| 4 | .16.1 |  | Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(q)
| 4 | .16.2 |  | Registration Rights Agreement, dated as of November 14, 2003, between the Company and Deutsche Bank Securities, Inc., as Representative of the Initial Purchasers.(q)
| 4 | .17.1 |  | First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q)
| 4 | .17.2 |  | Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q)
| 4 | .17.3 |  | Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q)
| 4 | .18 |  | Indenture, dated as of June 2, 2004, between Power Contract Financing III, LLC and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(b)
| 4 | .19 |  | Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r)
| 4 | .20.1 |  | Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(s)
| 4 | .20.2 |  | Amendment No. 1 to Rights Agreement, dated as of September 28, 2004, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(l)
| 4 | .20.3 |  | Amendment No. 2 to Rights Agreement, dated as of March 18, 2005, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(bb)
| 4 | .21 |  | Memorandum and Articles of Association of Calpine (Jersey) Limited.(t)
| 4 | .22 |  | Memorandum and Articles of Association of Calpine European Funding (Jersey) Limited.(t)
| 4 | .23 |  | High Tides III
| 4 | .23.1 |  | Amended and Restated Certificate of Trust of Calpine Capital Trust III, a Delaware statutory trust, filed July 19, 2000.(u)
| 4 | .23.2 |  | Declaration of Trust of Calpine Capital Trust III dated June 28, 2000, among the Company, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee and the Administrative Trustees named therein.(u)
| 4 | .23.3 |  | Amendment No. 1 to the Declaration of Trust of Calpine Capital Trust III dated July 19, 2000, among the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein.(u)
| 4 | .23.4 |  | Indenture dated as of August 9, 2000, between the Company and Wilmington Trust Company, as Trustee.(u)
| 4 | .23.5 |  | Remarketing Agreement dated as of August 9, 2000, among the Company, Calpine Capital Trust III, Wilmington Trust Company, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(u)
| 4 | .23.6 |  | Registration Rights Agreement dated as August 9, 2000, between the Company, Calpine Capital Trust III, Credit Suisse First Boston Corporation, ING Barings LLC and CIBC World Markets Corp.(u)

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Exhibit |  |  |
Number |  |  | Description
| 4 | .23.7 |  | Amended and Restated Declaration of Trust of Calpine Capital Trust III dated as of August 9, 2000, the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein, including the form of Preferred Security and form of Common Security.(u)
| 4 | .23.8 |  | Preferred Securities Guarantee Agreement dated as of August 9, 2000, between the Company, as Guarantor, and Wilmington Trust Company, as Guarantee Trustee.(u)
| 4 | .24 |  | Pass Through Certificates (Tiverton and Rumford)
| 4 | .24.1 |  | Pass Through Trust Agreement dated as of December 19, 2000, among Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of Certificate.(e)
| 4 | .24.2 |  | Participation Agreement dated as of December 19, 2000, among the Company, Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership, PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee.(e)
| 4 | .24.3 |  | Appendix A — Definitions and Rules of Interpretation.(e)
| 4 | .24.4 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of December 19, 2000, between PMCC Calpine New England Investment LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, including the forms of Lessor Notes.(e)
| 4 | .24.5 |  | Calpine Guaranty and Payment Agreement (Tiverton) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(e)
| 4 | .24.6 |  | Calpine Guaranty and Payment Agreement (Rumford) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(e)
| 4 | .25 |  | Pass Through Certificates (South Point, Broad River and RockGen)
| 4 | .25.1 |  | Pass Through Trust Agreement A dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 8.400% Pass Through Certificate, Series A.(c)
| 4 | .25.2 |  | Pass Through Trust Agreement B dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 9.825% Pass Through Certificate, Series B.(c)
| 4 | .25.3 |  | Participation Agreement (SP-1) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.4 |  | Participation Agreement (SP-2) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)

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Exhibit |  |  |
Number |  |  | Description
| 4 | .25.5 |  | Participation Agreement (SP-3) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.6 |  | Participation Agreement (SP-4) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.7 |  | Participation Agreement (BR-1) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.8 |  | Participation Agreement (BR-2) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.9 |  | Participation Agreement (BR-3) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.10 |  | Participation Agreement (BR-4) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.11 |  | Participation Agreement (RG-1) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.12 |  | Participation Agreement (RG-2) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)

117

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .25.13 |  | Participation Agreement (RG-3) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.14 |  | Participation Agreement (RG-4) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.15 |  | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c)
| 4 | .25.16 |  | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c)
| 4 | .25.17 |  | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c)
| 4 | .25.18 |  | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c)
| 4 | .25.19 |  | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c)
| 4 | .25.20 |  | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c)
| 4 | .25.21 |  | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c)
| 4 | .25.22 |  | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c)
| 4 | .25.23 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c)
| 4 | .25.24 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c)

118

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .25.25 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c)
| 4 | .25.26 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c)
| 4 | .25.27 |  | Calpine Guaranty and Payment Agreement (South Point SP-1) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.28 |  | Calpine Guaranty and Payment Agreement (South Point SP-2) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.29 |  | Calpine Guaranty and Payment Agreement (South Point SP-3) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.30 |  | Calpine Guaranty and Payment Agreement (South Point SP-4) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.31 |  | Calpine Guaranty and Payment Agreement (Broad River BR-1) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.32 |  | Calpine Guaranty and Payment Agreement (Broad River BR-2) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.33 |  | Calpine Guaranty and Payment Agreement (Broad River BR-3) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.34 |  | Calpine Guaranty and Payment Agreement (Broad River BR-4) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.35 |  | Calpine Guaranty and Payment Agreement (RockGen RG-1) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.36 |  | Calpine Guaranty and Payment Agreement (RockGen RG-2) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.37 |  | Calpine Guaranty and Payment Agreement (RockGen RG-3) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)

119

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .25.38 |  | Calpine Guaranty and Payment Agreement (RockGen RG-4) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 10 | .1 |  | Financing and Term Loan Agreements
| 10 | .1.1 |  | Share Lending Agreement, dated as of September 28, 2004, among the Company, as Lender, Deutsche Bank AG London, as Borrower, through Deutsche Bank Securities Inc., as agent for the Borrower, and Deutsche Bank Securities Inc., in its capacity as Collateral Agent and Securities Intermediary.(l)
| 10 | .1.2 |  | Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(q)
| 10 | .1.3.1 |  | Letter of Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent.(o)
| 10 | .1.3.2 |  | Amendment to Letter of Credit Agreement, dated as of September 30, 2004, between the Company and The Bank of Nova Scotia, as Administrative Agent.(v)
| 10 | .1.4 |  | Letter of Credit Agreement, dated as of September 30, 2004, between the Company and Bayerische Landesbank, acting through its Cayman Islands Branch, as the Issuer.(v)
| 10 | .1.5 |  | Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents.(o)
| 10 | .1.6.1 |  | Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(p)
| 10 | .1.6.2 |  | Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(p)
| 10 | .1.6.3 |  | Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q)
| 10 | .1.6.4 |  | Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q)
| 10 | .1.7 |  | Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(q)
| 10 | .1.8 |  | Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(q)

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Exhibit |  |  |
Number |  |  | Description
| 10 | .1.9 |  | Credit Agreement, dated as of June 24, 2004, among Riverside Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(*)
| 10 | .1.10 |  | Credit Agreement, dated as of June 24, 2004, among Rocky Mountain Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(*)
| 10 | .1.11 |  | Credit Agreement, dated as of February 25, 2005, among Calpine Steamboat Holdings, LLC, the Lenders named therein, Calyon New York Branch, as a Lead Arranger, Underwriter, Co-Book Runner, Administrative Agent, Collateral Agent and LC Issuer, CoBank, ACB, as a Lead Arranger, Underwriter, Co-Syndication Agent and Co-Book Runner, HSH Nordbank AG, as a Lead Arranger, Underwriter and Co-documentation Agent, UFJ Bank Limited, as a Lead Arranger, Underwriter and Co-Documentation Agent, and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as a Lead Arranger, Underwriter and Co-Syndication Agent.(*)
| 10 | .2 |  | Security Agreements
| 10 | .2.1 |  | Guarantee and Collateral Agreement, dated as of July 16, 2003, made by the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.2 |  | First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.3 |  | First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.4.1 |  | Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.4.2 |  | Amendment No. 1 to the Second Amendment Pledge Agreement (Stock Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(q)
| 10 | .2.5.1 |  | Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.5.2 |  | Amendment No. 1 to the Second Amendment Pledge Agreement (Membership Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(q)
| 10 | .2.6 |  | First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.7.1 |  | Collateral Trust Agreement, dated as of July 16, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.7.2 |  | First Amendment to the Collateral Trust Agreement, dated as of November 18, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(q)
| 10 | .2.8 |  | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee.(o)

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Exhibit |  |  |
Number |  |  | Description
| 10 | .2.9 |  | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.10 |  | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.11 |  | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.12 |  | Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.13 |  | Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.14 |  | Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.15 |  | Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.16 |  | Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from the Company to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.17 |  | Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.18 |  | Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.19 |  | Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.20 |  | Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.21 |  | Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.22 |  | Designated Asset Sale Proceeds Account Control Agreement, dated as of July 16, 2003, among the Company, Union Bank of California, N.A., and The Bank of New York, as Collateral Agent.(q)
| 10 | .3 |  | Management Contracts or Compensatory Plans or Arrangements.
| 10 | .3.1.1 |  | Employment Agreement, dated as of January 1, 2005, between the Company and Mr. Peter Cartwright.(w)(x)
| 10 | .3.1.2 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Peter Cartwright.(y)(x)
| 10 | .3.2 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Ms. Ann B. Curtis.(c)(x)
| 10 | .3.3 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Ron A. Walter.(c)(x)

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Exhibit |  |  |
Number |  |  | Description
| 10 | .3.4 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Robert D. Kelly.(c)(x)
| 10 | .3.5 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Thomas R. Mason.(c)(x)
| 10 | .3.6.1 |  | Consulting Contract, dated as of January 1, 2005, between the Company and Mr. George J. Stathakis.(*)(x)
| 10 | .3.6.2 |  | Consulting Contract, dated as of January 1, 2004, between the Company and Mr. George J. Stathakis.(q)(x)
| 10 | .3.7 |  | Form of Indemnification Agreement for directors and officers.(z)(x)
| 10 | .3.8 |  | Form of Indemnification Agreement for directors and officers.(c)(x)
| 10 | .3.9 |  | Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(q)(x)
| 10 | .3.10 |  | Base Salary, Bonus, Stock Option Grant and Restricted Stock Summary Sheet.(w)(x)
| 10 | .3.11 |  | Form of Stock Option Agreement.(w)(x)
| 10 | .3.12 |  | Form of Restricted Stock Agreement.(w)(x)
| 10 | .3.13 |  | Calpine Corporation 2003 Management Incentive Plan.(*)(x)
| 10 | .3.14 |  | 2000 Employee Stock Purchase Plan.(aa)(x)
| 12 | .1 |  | Statement on Computation of Ratio of Earnings to Fixed Charges.(*)
| 21 | .1 |  | Subsidiaries of the Company.(*)
| 23 | .1 |  | Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm.(*)
| 23 | .2 |  | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.(*)
| 23 | .3 |  | Consent of Netherland, Sewell & Associates, Inc., independent engineer.(*)
| 23 | .4 |  | Consent of Gilbert Laustsen Jung Associates Ltd., independent engineer.(*)
| 24 | .1 |  | Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this report).(*)
| 31 | .1 |  | Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
| 31 | .2 |  | Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
| 32 | .1 |  | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*)
| 99 | .1 |  | Acadia Power Partners, LLC and Subsidiary, Consolidated Financial Statements, December 31, 2003, 2002 and 2001.(*)
| 99 | .2 |  | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.(*)

(*) |  | Filed herewith.
(a) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K/ A filed with the SEC on September 14, 2004.
(b) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004.
(c) |  | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2001, filed with the SEC on March 29, 2002.
(d) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-06259) filed with the SEC on June 19, 1996.
(e) |  | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.

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(f) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2004, filed with the SEC on May 10, 2004.
(g) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.
(h) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-41261) filed with the SEC on November 28, 1997.
(i) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-61047) filed with the SEC on August 10, 1998.
(j) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-72583) filed with the SEC on March 8, 1999.
(k) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17, 2002.
(l) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 30, 2004.
(m) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001.
(n) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-57338) filed with the SEC on April 19, 2001.
(o) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
(p) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003.
(q) |  | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004.
(r) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on October 6, 2004.
(s) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form 8-A/ A (Registration No. 001-12079) filed with the SEC on September 28, 2001.
(t) |  | This document has been omitted in reliance on Item 601(b)(4)(iii) of Regulation S-K. Calpine Corporation agrees to furnish a copy of such document to the SEC upon request.
(u) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration Statement No. 333-47068) filed with the SEC on September 29, 2000.
(v) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2004, filed with the SEC on November 9, 2004.
(w) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 17, 2005.
(x) |  | Management contract or compensatory plan or arrangement.
(y) |  | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, filed with the SEC on February 29, 2000.
(z) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-1/ A (Registration Statement No. 333-07497) filed with the SEC on August 22, 1996.
(aa) |  | Incorporated by reference to Calpine Corporation’s Definitive Proxy Statement on Schedule 14A dated April 13, 2000, filed with the SEC on April 13, 2000.
(bb) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 23, 2005.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

| CALPINE CORPORATION

| By: | /s/ ROBERT D. KELLY

| Robert D. Kelly
| Executive Vice President and
| Chief Financial Officer

Date: March 31, 2005
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENT: That the undersigned officers and directors of Calpine Corporation do hereby constitute and appoint Peter Cartwright and Ann B. Curtis, and each of them, the lawful attorney and agent or attorneys and agents with power and authority to do any and all acts and things and to execute any and all instruments which said attorneys and agents, or either of them, determine may be necessary or advisable or required to enable Calpine Corporation to comply with the Securities and Exchange Act of 1934, as amended, and any rules or regulations or requirements of the Securities and Exchange Commission in connection with this Form 10-K Annual Report. Without limiting the generality of the foregoing power and authority, the powers granted include the power and authority to sign the names of the undersigned officers and directors in the capacities indicated below to this Form 10-K Annual Report or amendments or supplements thereto, and each of the undersigned hereby ratifies and confirms all that said attorneys and agents, or either of them, shall do or cause to be done by virtue hereof. This Power of Attorney may be signed in several counterparts.
IN WITNESS WHEREOF, each of the undersigned has executed this Power of Attorney as of the date indicated opposite the name.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature |  | Title |  | Date
/s/ PETER CARTWRIGHT Peter Cartwright |  | Chairman, President, Chief Executive and Director (Principal Executive Officer) |  | March 31, 2005
/s/ ANN B. CURTIS Ann B. Curtis |  | Executive Vice President, Vice Chairman and Director |  | March 31, 2005
/s/ ROBERT D. KELLY Robert D. Kelly |  | Executive Vice President and Chief Financial Officer (Principal Financial Officer) |  | March 31, 2005
/s/ CHARLES B. CLARK, JR. Charles B. Clark, Jr. |  | Senior Vice President and Corporate Controller (Principal Accounting Officer) |  | March 31, 2005

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Signature |  | Title |  | Date
Kenneth T. Derr |  | Director |  |
Jeffrey E. Garten |  | Director |  |
/s/ GERALD GREENWALD Gerald Greenwald |  | Director |  | March 31, 2005
/s/ SUSAN C. SCHWAB Susan C. Schwab |  | Director |  | March 31, 2005
/s/ GEORGE J. STATHAKIS George J. Stathakis |  | Director |  | March 31, 2005
/s/ SUSAN WANG Susan Wang |  | Director |  | March 31, 2005
/s/ JOHN O. WILSON John O. Wilson |  | Director |  | March 31, 2005

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CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004

|  | Page |
Reports of Independent Registered Public Accounting Firms |  |  | F-2 |
Consolidated Balance Sheets December 31, 2004 and 2003 |  |  | F-5 |
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003, and 2002 |  |  | F-6 |
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003, and 2002 |  |  | F-7 |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002 |  |  | F-8 |
Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003, and 2002 |  |  | F-9 |

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Report of Independent Registered Public Accounting Firm
To the Board of Directors
And Stockholders of Calpine Corporation
We have audited the consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2002 of Calpine Corporation and subsidiaries (the “Company”). Our audit also included the 2002 consolidated financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, based on our audit, such consolidated financial statements present fairly, in all material respects, the consolidated results of operations and of cash flows for the year ended 2002 of Calpine Corporation and subsidiaries, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2002 consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 2 of the Notes to the Consolidated Financial Statements, effective January 1, 2002, the Company adopted a new accounting standard to account for the impairment of long-lived assets and discontinued operations.
As discussed in Note 10 of the Notes to the Consolidated Financial Statements, in June 2003, the Company approved the divestiture of its specialty data center engineering business; in November 2003, the Company completed the divestiture of certain oil and gas assets; in December 2003, the Company committed to the divestiture of its fifty percent ownership interest in a power project; in September 2004, the Company completed the divestiture of certain oil and gas assets.

| /s/ DELOITTE & TOUCHE LLP

San Jose, California
March 10, 2003
(October 21, 2003 as to paragraph two of Note 10,
March 22, 2004 as to paragraphs six and thirteen of Note 10, and
March 31, 2005 as to paragraphs seven and eight of Note 10)

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Report Of Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders of Calpine Corporation:
We have completed an integrated audit of Calpine Corporation’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a) (1) present fairly, in all material respects, the financial position of Calpine Corporation and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 (a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which they calculate diluted earnings per share in 2004, changed the manner in which they account for asset retirement costs and stock based compensation as of January 1, 2003, changed the manner in which they account for certain financial instruments with characteristics of both liabilities and equity effective July 1, 2003, changed the manner in which they report gains and losses on certain derivative instruments not held for trading purposes and account for certain derivative contracts with a price adjustment feature effective October 1, 2003, adopted provisions of Financial Accounting Standards Board Interpretation No. 46-R (“FIN-46R”), “Consolidation of Variable Interest Entities — an interpretation of ARB 51 (revised December 2003),” for Special-Purpose-Entities as of December 31, 2003, and adopted FIN-46R for all non-Special-Purpose-Entities on March 31, 2004.
Internal control over financial reporting
Also, we have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that Calpine Corporation did not maintain effective internal control over financial reporting as of December 31, 2004, because the Company did not maintain effective controls over the accounting for income taxes and the determination of current income taxes payable, deferred income tax assets and liabilities and the related income tax provision (benefit) for continuing and discontinued operations, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial

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reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment. As of December 31, 2004, the Company did not maintain effective controls over the accounting for income taxes and the determination of current income taxes payable, deferred income tax assets and liabilities and the related income tax provision (benefit) for continuing and discontinued operations. Specifically, the Company did not have effective controls in place to (i) identify and evaluate in a timely manner the tax implications of the repatriation of funds from Canada (ii) appropriately determine the allocation of the tax provision between continuing and discontinued operations (iii) ensure there was adequate communication from the tax department to the accounting department relating to the preparation of the tax provision (iv) ensure all elements of the income tax provision were mathematically correct and (v) ensure the rationale for certain tax positions was adequately documented. This control deficiency resulted in the restatement of the Company’s consolidated financial statements for the three and nine months ended September 30, 2004 as well as income tax related audit adjustments to the fourth quarter 2004 consolidated financial statements. Additionally, this control deficiency could result in a misstatement of current income taxes payable, deferred income tax assets and liabilities and the related income tax provision (benefit) for continuing and discontinued operations that would result in a material misstatement to annual or interim financial statements that would not be prevented or detected. Accordingly, management determined that this control deficiency constitutes a material weakness. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2004 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.
In our opinion, management’s assessment that Calpine Corporation did not maintain effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the COSO. Also, in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Calpine Corporation has not maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the COSO.
/s/ PricewaterhouseCoopers LLP
Los Angeles, CA
March 31, 2005

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CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2004 and 2003

|  | 2004 |  |  | 2003 |
|  | (In thousands, except |
|  | share and per |
|  | share amounts) |
ASSETS
Current assets: |  |  |  |  |  |  |  |
| Cash and cash equivalents |  | $ | 783,428 |  |  | $ | 991,806 |
| Accounts receivable, net of allowance of $8,679 and $7,614 |  |  | 1,097,157 |  |  |  | 988,947 |
| Margin deposits and other prepaid expense |  |  | 452,432 |  |  |  | 385,348 |
| Inventories |  |  | 179,395 |  |  |  | 137,740 |
| Restricted cash |  |  | 593,304 |  |  |  | 383,788 |
| Current derivative assets |  |  | 324,206 |  |  |  | 496,967 |
| Current assets held for sale |  |  | — |  |  |  | 2,565 |
| Other current assets |  |  | 133,643 |  |  |  | 89,593 |
|  | Total current assets |  |  | 3,563,565 |  |  |  | 3,476,754 |
Restricted cash, net of current portion |  |  | 157,868 |  |  |  | 575,027 |
Notes receivable, net of current portion |  |  | 203,680 |  |  |  | 213,629 |
Project development costs |  |  | 150,179 |  |  |  | 139,953 |
Investments in power projects and oil and gas properties |  |  | 374,032 |  |  |  | 444,150 |
Deferred financing costs |  |  | 422,606 |  |  |  | 400,732 |
Prepaid lease, net of current portion |  |  | 424,586 |  |  |  | 414,058 |
Property, plant and equipment, net |  |  | 20,636,394 |  |  |  | 19,478,650 |
Goodwill |  |  | 45,160 |  |  |  | 45,160 |
Other intangible assets, net |  |  | 73,190 |  |  |  | 89,924 |
Long-term derivative assets |  |  | 506,050 |  |  |  | 673,979 |
Long-term assets held for sale |  |  | — |  |  |  | 743,149 |
Other assets |  |  | 658,778 |  |  |  | 608,767 |
|  | Total assets |  | $ | 27,216,088 |  |  | $ | 27,303,932 |
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities: |  |  |  |  |  |  |  |
| Accounts payable |  | $ | 1,014,350 |  |  | $ | 938,644 |
| Accrued payroll and related expense |  |  | 88,719 |  |  |  | 96,693 |
| Accrued interest payable |  |  | 385,794 |  |  |  | 321,176 |
| Income taxes payable |  |  | 82,958 |  |  |  | 18,026 |
| Notes payable and borrowings under lines of credit, current portion |  |  | 204,775 |  |  |  | 254,292 |
| Preferred interests, current portion |  |  | 8,641 |  |  |  | 11,220 |
| CCFC I financing, current portion |  |  | 3,208 |  |  |  | 3,208 |
| Capital lease obligation, current portion |  |  | 5,490 |  |  |  | 4,008 |
| Construction/project financing, current portion |  |  | 93,393 |  |  |  | 61,900 |
| Senior notes and term loans, current portion |  |  | 718,449 |  |  |  | 14,500 |
| Current derivative liabilities |  |  | 364,965 |  |  |  | 456,688 |
| Current liabilities held for sale |  |  | — |  |  |  | 221 |
| Other current liabilities |  |  | 314,650 |  |  |  | 334,827 |
|  | Total current liabilities |  |  | 3,285,392 |  |  |  | 2,515,403 |
Notes payable and borrowings under lines of credit, net of current portion |  |  | 769,490 |  |  |  | 873,571 |
Notes payable to Calpine Capital Trusts |  |  | 517,500 |  |  |  | 1,153,500 |
Preferred interests, net of current portion |  |  | 497,896 |  |  |  | 232,412 |
Capital lease obligation, net of current portion |  |  | 283,429 |  |  |  | 193,741 |
CCFC I financing, net of current portion |  |  | 783,542 |  |  |  | 785,781 |
CalGen/ CCFC II financing |  |  | 2,395,332 |  |  |  | 2,200,358 |
Construction/project financing, net of current portion |  |  | 1,905,658 |  |  |  | 1,209,506 |
Convertible Senior Notes Due 2006 |  |  | 1,326 |  |  |  | 660,059 |
Convertible Senior Notes Due 2014 |  |  | 620,197 |  |  |  | — |
Convertible Senior Notes Due 2023 |  |  | 633,775 |  |  |  | 650,000 |
Senior notes, net of current portion |  |  | 8,532,664 |  |  |  | 9,369,253 |
Deferred income taxes, net of current portion |  |  | 1,021,739 |  |  |  | 1,310,335 |
Deferred lease incentive |  |  | — |  |  |  | 50,228 |
Deferred revenue |  |  | 114,202 |  |  |  | 116,001 |
Long-term derivative liabilities |  |  | 526,598 |  |  |  | 692,088 |
Long-term liabilities held for sale |  |  | — |  |  |  | 17,828 |
Other liabilities |  |  | 346,230 |  |  |  | 241,723 |
|  | Total liabilities |  |  | 22,234,970 |  |  |  | 22,271,787 |
Commitments and contingencies (see Note 25) |  |  |  |  |  |  |  |
Minority interests |  |  | 393,445 |  |  |  | 410,892 |
Stockholders’ equity: |  |  |  |  |  |  |  |
| Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2004 and 2003 |  |  | — |  |  |  | — |
| Common stock, $.001 par value per share; authorized 2,000,000,000 shares in 2003; issued and outstanding 536,509,231 shares in 2004 and 415,010,125 shares in 2003 |  |  | 537 |  |  |  | 415 |
| Additional paid-in capital |  |  | 3,151,577 |  |  |  | 2,995,735 |
| Additional paid-in capital, loaned shares |  |  | 258,100 |  |  |  | — |
| Additional paid-in capital, returnable shares |  |  | (258,100 | ) |  |  | — |
| Retained earnings |  |  | 1,326,048 |  |  |  | 1,568,509 |
| Accumulated other comprehensive income |  |  | 109,511 |  |  |  | 56,594 |
|  | Total stockholders’ equity |  |  | 4,587,673 |  |  |  | 4,621,253 |
|  | Total liabilities and stockholders’ equity |  | $ | 27,216,088 |  |  | $ | 27,303,932 |

The accompanying notes are an integral part of these consolidated financial statements.

F-5

##### Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

|  | For the Years Ended |
|  | December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |
|  | (In thousands, except per |
|  | share amounts) |
Revenue: |  |  |  |  |  |  |  |  |  |  |  |
| Electric generation and marketing revenue |  |  |  |  |  |  |  |  |  |  |  |
|  | Electricity and steam revenue |  | $ | 5,683,063 |  |  | $ | 4,680,397 |  |  | $ | 3,237,510 |
|  | Transmission sales revenue |  |  | 20,003 |  |  |  | 15,347 |  |  |  | — |
|  | Sales of purchased power for hedging and optimization |  |  | 1,651,767 |  |  |  | 2,714,187 |  |  |  | 3,145,991 |
|  |  | Total electric generation and marketing revenue |  |  | 7,354,833 |  |  |  | 7,409,931 |  |  |  | 6,383,501 |
| Oil and gas production and marketing revenue |  |  |  |  |  |  |  |  |  |  |  |
|  | Oil and gas sales |  |  | 63,153 |  |  |  | 59,156 |  |  |  | 63,514 |
|  | Sales of purchased gas for hedging and optimization |  |  | 1,728,301 |  |  |  | 1,320,902 |  |  |  | 870,466 |
|  |  | Total oil and gas production and marketing revenue |  |  | 1,791,454 |  |  |  | 1,380,058 |  |  |  | 933,980 |
| Mark-to-market activities, net |  |  | 13,532 |  |  |  | (26,439 | ) |  |  | 21,485 |
| Other revenue |  |  | 70,069 |  |  |  | 107,483 |  |  |  | 10,787 |
|  |  | Total revenue |  |  | 9,229,888 |  |  |  | 8,871,033 |  |  |  | 7,349,753 |
Cost of revenue: |  |  |  |  |  |  |  |  |  |  |  |
| Electric generation and marketing expense |  |  |  |  |  |  |  |  |  |  |  |
|  | Plant operating expense |  |  | 795,975 |  |  |  | 663,045 |  |  |  | 522,906 |
|  | Royalty expense |  |  | 28,673 |  |  |  | 24,932 |  |  |  | 17,615 |
|  | Transmission purchase expense |  |  | 85,514 |  |  |  | 46,455 |  |  |  | 25,486 |
|  | Purchased power expense for hedging and optimization |  |  | 1,487,020 |  |  |  | 2,690,069 |  |  |  | 2,618,445 |
|  |  | Total electric generation and marketing expense |  |  | 2,397,182 |  |  |  | 3,424,501 |  |  |  | 3,184,452 |
| Oil and gas operating and marketing expense |  |  |  |  |  |  |  |  |  |  |  |
|  | Oil and gas operating expense |  |  | 56,843 |  |  |  | 75,453 |  |  |  | 69,840 |
|  |  | Purchased gas expense for hedging and optimization |  |  | 1,716,714 |  |  |  | 1,279,568 |  |  |  | 821,065 |
|  |  | Total oil and gas operating and marketing expense |  |  | 1,773,557 |  |  |  | 1,355,021 |  |  |  | 890,905 |
| Fuel expense |  |  | 3,731,108 |  |  |  | 2,665,620 |  |  |  | 1,792,323 |
| Depreciation, depletion and amortization expense |  |  | 574,200 |  |  |  | 504,383 |  |  |  | 398,889 |
| Oil and gas impairment |  |  | 202,120 |  |  |  | 2,931 |  |  |  | 3,399 |
| Operating lease expense |  |  | 105,886 |  |  |  | 112,070 |  |  |  | 111,022 |
| Other cost of revenue |  |  | 90,742 |  |  |  | 42,270 |  |  |  | 7,279 |
|  |  | Total cost of revenue |  |  | 8,874,795 |  |  |  | 8,106,796 |  |  |  | 6,388,269 |
|  |  |  | Gross profit |  |  | 355,093 |  |  |  | 764,237 |  |  |  | 961,484 |
(Income) loss from unconsolidated investments in power projects and oil and gas properties |  |  | 13,525 |  |  |  | (75,804 | ) |  |  | (16,552 | )
Equipment cancellation and impairment cost |  |  | 42,374 |  |  |  | 64,384 |  |  |  | 404,737 |
Long-term service agreement cancellation charge |  |  | 11,334 |  |  |  | 16,355 |  |  |  | — |
Project development expense |  |  | 24,409 |  |  |  | 21,803 |  |  |  | 66,981 |
Research and development expense |  |  | 18,396 |  |  |  | 10,630 |  |  |  | 9,986 |
Sales, general and administrative expense |  |  | 239,347 |  |  |  | 216,471 |  |  |  | 186,056 |
Income from operations |  |  | 5,708 |  |  |  | 510,398 |  |  |  | 310,276 |
Interest expense |  |  | 1,140,802 |  |  |  | 706,307 |  |  |  | 402,677 |
Distributions on trust preferred securities |  |  | — |  |  |  | 46,610 |  |  |  | 62,632 |
Interest (income) |  |  | (56,412 | ) |  |  | (39,716 | ) |  |  | (43,086 | )
Minority interest expense |  |  | 34,735 |  |  |  | 27,330 |  |  |  | 2,716 |
(Income) from repurchase of various issuances of debt |  |  | (246,949 | ) |  |  | (278,612 | ) |  |  | (118,020 | )
Other (income), net |  |  | (149,093 | ) |  |  | (46,126 | ) |  |  | (34,200 | )
| Income (loss) before provision (benefit) for income taxes |  |  | (717,375 | ) |  |  | 94,605 |  |  |  | 37,557 |
Provision (benefit) for income taxes |  |  | (276,549 | ) |  |  | 8,495 |  |  |  | 10,835 |
| Income (loss) before discontinued operations and cumulative effect of a change in accounting principle |  |  | (440,826 | ) |  |  | 86,110 |  |  |  | 26,722 |
Discontinued operations, net of tax provision (benefit) of $50,095, $(14,416) and $17,104 |  |  | 198,365 |  |  |  | 14,969 |  |  |  | 91,896 |
Cumulative effect of a change in accounting principle, net of tax provision of $ — , $110,913, and $ — |  |  | — |  |  |  | 180,943 |  |  |  | — |
|  |  |  | Net income (loss) |  | $ | (242,461 | ) |  | $ | 282,022 |  |  | $ | 118,618 |
Basic earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |
| Weighted average shares of common stock outstanding |  |  | 430,775 |  |  |  | 390,772 |  |  |  | 354,822 |
| Income (loss) before discontinued operations and cumulative effect of a change in accounting principle |  | $ | (1.02 | ) |  | $ | 0.22 |  |  | $ | 0.07 |
| Discontinued operations, net of tax |  | $ | 0.46 |  |  | $ | 0.04 |  |  | $ | 0.26 |
| Cumulative effect of a change in accounting principle, net of tax |  | $ | — |  |  | $ | 0.46 |  |  | $ | — |
|  |  |  | Net income (loss) |  | $ | (0.56 | ) |  | $ | 0.72 |  |  | $ | 0.33 |
Diluted earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |
| Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities |  |  | 430,775 |  |  |  | 396,219 |  |  |  | 362,533 |
| Income (loss) before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle |  | $ | (1.02 | ) |  | $ | 0.22 |  |  | $ | 0.07 |
| Dilutive effect of certain convertible securities(1) |  | $ | — |  |  | $ | — |  |  | $ | — |
| Income (loss) before discontinued operations and cumulative effect of a change in accounting principle |  | $ | (1.02 | ) |  | $ | 0.22 |  |  | $ | 0.07 |
| Discontinued operations, net of tax |  | $ | 0.46 |  |  | $ | 0.04 |  |  | $ | 0.26 |
| Cumulative effect of a change in accounting principle, net of tax |  | $ | — |  |  | $ | 0.45 |  |  | $ | — |
|  |  |  | Net income(loss) |  | $ | (0.56 | ) |  | $ | 0.71 |  |  | $ | 0.33 |

(1) | See Note 24 of the Notes to Consolidated Financial Statements for further information.

The accompanying notes are an integral part of these consolidated financial statements.

F-6

##### Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2004, 2003, and 2002

|  |  |  |  |  |  |  | Accumulated |  |  |  |  |
|  |  |  |  |  |  |  | Other |  |  |  |  |
|  |  |  | Additional |  |  |  |  | Comprehensive |  |  | Total |  |  | Comprehensive |
|  | Common |  |  | Paid-In |  |  | Retained |  |  | Income |  |  | Stockholders’ |  |  | Income |
|  | Stock |  |  | Capital |  |  | Earnings |  |  | (Loss) |  |  | Equity |  |  | (Loss) |
|  | (In thousands, except share amounts) |
Balance, January 1, 2002 |  | $ | 307 |  |  | $ | 2,040,833 |  |  | $ | 1,167,869 |  |  | $ | (240,880 | ) |  | $ | 2,968,129 |  |  |  |  |
| Issuance of 73,757,381 shares of common stock, net of issuance costs |  |  | 74 |  |  |  | 751,721 |  |  |  |  |  |  |  | — |  |  |  | 751,795 |  |  |  |  |
| Tax benefit from stock options exercised and other |  |  | — |  |  |  | 9,949 |  |  |  |  |  |  |  |  |  |  |  | 9,949 |  |  |  |  |
Comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Net income |  |  | — |  |  |  | — |  |  |  | 118,618 |  |  |  | — |  |  |  | 118,618 |  |  | $ | 118,618 |
| Other comprehensive income |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,423 |  |  |  | 3,423 |  |  |  | 3,423 |
| Total comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  |  |  |  | $ | 122,041 |
Balance, December 31, 2002 |  |  | 381 |  |  |  | 2,802,503 |  |  |  | 1,286,487 |  |  |  | (237,457 | ) |  |  | 3,851,914 |  |  |  |  |
| Issuance of 34,194,063 shares of common stock, net of issuance costs |  |  | 34 |  |  |  | 175,063 |  |  |  | — |  |  |  | — |  |  |  | 175,097 |  |  |  |  |
| Tax benefit from stock options exercised and other |  |  | — |  |  |  | 2,097 |  |  |  | — |  |  |  | — |  |  |  | 2,097 |  |  |  |  |
| Stock compensation expense |  |  | — |  |  |  | 16,072 |  |  |  | — |  |  |  | — |  |  |  | 16,072 |  |  |  |  |
Comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Net income |  |  | — |  |  |  | — |  |  |  | 282,022 |  |  |  | — |  |  |  | 282,022 |  |  | $ | 282,022 |
| Other comprehensive income |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 294,051 |  |  |  | 294,051 |  |  |  | 294,051 |
| Total comprehensive income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 576,073 |
Balance, December 31, 2003 |  | $ | 415 |  |  | $ | 2,995,735 |  |  | $ | 1,568,509 |  |  | $ | 56,594 |  |  | $ | 4,621,253 |  |  |  |  |
| Issuance of 32,499,106 shares of common stock, net of issuance costs |  |  | 33 |  |  |  | 130,141 |  |  |  | — |  |  |  | — |  |  |  | 130,174 |  |  |  |  |
| Issuance of 89,000,000 shares of loaned common stock |  |  | 89 |  |  |  | 258,100 |  |  |  | — |  |  |  | — |  |  |  | 258,189 |  |  |  |  |
| Returnable shares |  |  |  |  |  |  | (258,100 | ) |  |  | — |  |  |  | — |  |  |  | (258,100 | ) |  |  |  |
| Tax benefit from stock options exercised and other |  |  | — |  |  |  | 4,773 |  |  |  | — |  |  |  | — |  |  |  | 4,773 |  |  |  |  |
| Stock compensation expense |  |  |  |  |  |  | 20,928 |  |  |  |  |  |  |  |  |  |  |  | 20,928 |  |  |  |  |
Comprehensive loss: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Net loss |  |  | — |  |  |  | — |  |  |  | (242,461 | ) |  |  |  |  |  |  | (242,461 | ) |  | $ | (242,461 | )
| Other comprehensive income |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 52,917 |  |  |  | 52,917 |  |  |  | 52,917 |
| Total comprehensive loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | (189,544 | )
Balance, December 31, 2004 |  | $ | 537 |  |  | $ | 3,151,577 |  |  | $ | 1,326,048 |  |  | $ | 109,511 |  |  | $ | 4,587,673 |  |  |  |  |

The accompanying notes are an integral part of these consolidated financial statements.

F-7

##### Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002

|  | 2004 |  |  | 2003 |  |  | 2002 |
|  | (In thousands) |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |
| Net income (loss) |  | $ | (242,461 | ) |  | $ | 282,022 |  |  | $ | 118,618 |
|  | Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |
|  | Depreciation, depletion and amortization(1) |  |  | 833,375 |  |  |  | 732,410 |  |  |  | 538,777 |
|  | Oil and gas impairment |  |  | 202,120 |  |  |  | 2,931 |  |  |  | 3,399 |
|  | Equipment cancellation and asset impairment cost |  |  | 42,374 |  |  |  | 53,058 |  |  |  | 404,737 |
|  | Development cost write off |  |  | — |  |  |  | 3,400 |  |  |  | 56,427 |
|  | Deferred income taxes, net |  |  | (226,454 | ) |  |  | 150,323 |  |  |  | 23,206 |
|  | Gain on sale of assets |  |  | (349,611 | ) |  |  | (65,351 | ) |  |  | (97,377 | )
|  | Foreign currency transaction loss (gain) |  |  | 25,122 |  |  |  | 33,346 |  |  |  | (986 | )
|  | Cumulative change in accounting principle |  |  | — |  |  |  | (180,943 | ) |  |  | — |
|  | Income from repurchase of various issuances of debt |  |  | (246,949 | ) |  |  | (278,612 | ) |  |  | (118,020 | )
|  | Minority interests |  |  | 34,735 |  |  |  | 27,330 |  |  |  | 2,716 |
|  | Change in net derivative liability |  |  | 14,743 |  |  |  | 59,490 |  |  |  | (340,851 | )
|  | (Income) loss from unconsolidated investments in power projects and oil and gas properties |  |  | 9,717 |  |  |  | (76,704 | ) |  |  | (16,490 | )
|  | Distributions from unconsolidated investments in power projects and oil and gas properties |  |  | 29,869 |  |  |  | 141,627 |  |  |  | 14,117 |
|  | Stock compensation expense |  |  | 20,929 |  |  |  | 16,072 |  |  |  | — |
|  | Change in operating assets and liabilities, net of effects of acquisitions: |  |  |  |  |  |  |  |  |  |  |  |
|  |  | Accounts receivable |  |  | (99,447 | ) |  |  | (221,243 | ) |  |  | 229,187 |
|  |  | Other current assets |  |  | (118,790 | ) |  |  | (160,672 | ) |  |  | 405,515 |
|  |  | Other assets |  |  | (95,699 | ) |  |  | (143,654 | ) |  |  | (305,908 | )
|  |  | Accounts payable and accrued expense |  |  | 231,827 |  |  |  | (111,901 | ) |  |  | (48,804 | )
|  |  | Other liabilities |  |  | (55,505 | ) |  |  | 27,630 |  |  |  | 200,203 |
|  |  |  | Net cash provided by operating activities |  |  | 9,895 |  |  |  | 290,559 |  |  |  | 1,068,466 |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |
| Purchases of property, plant and equipment |  |  | (1,545,480 | ) |  |  | (1,886,013 | ) |  |  | (4,036,254 | )
| Disposals of property, plant and equipment |  |  | 1,066,481 |  |  |  | 206,804 |  |  |  | 400,349 |
| Disposal of subsidiary |  |  | 85,412 |  |  |  | — |  |  |  | — |
| Acquisitions, net of cash acquired |  |  | (187,786 | ) |  |  | (6,818 | ) |  |  | — |
| Advances to joint ventures |  |  | (8,788 | ) |  |  | (54,024 | ) |  |  | (68,088 | )
| Sale of collateral securities |  |  | 93,963 |  |  |  | — |  |  |  | — |
| Project development costs |  |  | (29,308 | ) |  |  | (35,778 | ) |  |  | (105,182 | )
| Redemption of HIGH TIDES |  |  | (110,592 | ) |  |  | — |  |  |  | — |
| Cash flows from derivatives not designated as hedges |  |  | 16,499 |  |  |  | 42,342 |  |  |  | 26,091 |
| (Increase) decrease in restricted cash |  |  | 210,762 |  |  |  | (766,841 | ) |  |  | (73,848 | )
| (Increase) decrease in notes receivable |  |  | 10,235 |  |  |  | (21,135 | ) |  |  | 8,926 |
| Other |  |  | (2,824 | ) |  |  | 6,098 |  |  |  | 10,179 |
|  |  |  | Net cash used in investing activities |  |  | (401,426 | ) |  |  | (2,515,365 | ) |  |  | (3,837,827 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |
| Repurchase of Zero-Coupon Convertible Debentures Due 2021 |  |  | — |  |  |  | — |  |  |  | (869,736 | )
| Borrowings from notes payable and lines of credit |  |  | 101,781 |  |  |  | 1,672,871 |  |  |  | 1,348,798 |
| Repayments of notes payable and lines of credit |  |  | (353,236 | ) |  |  | (1,769,072 | ) |  |  | (126,404 | )
| Borrowings from project financing |  |  | 3,743,930 |  |  |  | 1,548,601 |  |  |  | 725,111 |
| Repayments of project financing |  |  | (3,006,374 | ) |  |  | (1,638,519 | ) |  |  | (286,293 | )
| Proceeds from issuance of Convertible Senior Notes |  |  | 867,504 |  |  |  | 650,000 |  |  |  | 100,000 |
| Repurchases of Convertible Senior Notes Due 2006 |  |  | (834,765 | ) |  |  | (455,447 | ) |  |  | — |
| Repurchases of senior notes |  |  | (871,309 | ) |  |  | (1,139,812 | ) |  |  | — |
| Proceeds from issuance of senior notes |  |  | 878,814 |  |  |  | 3,892,040 |  |  |  | — |
| Proceeds from preferred interests |  |  | 360,000 |  |  |  | — |  |  |  | — |
| Repayment of HIGH TIDES |  |  | (483,500 | ) |  |  | — |  |  |  | — |
| Proceeds from issuance of common stock |  |  | 98 |  |  |  | 15,951 |  |  |  | 751,795 |
| Proceeds from income trust offerings |  |  | — |  |  |  | 159,727 |  |  |  | 169,677 |
| Financing costs |  |  | (204,139 | ) |  |  | (323,167 | ) |  |  | (42,783 | )
| Other |  |  | (31,752 | ) |  |  | 10,813 |  |  |  | (12,769 | )
|  |  |  | Net cash provided by financing activities |  |  | 167,052 |  |  |  | 2,623,986 |  |  |  | 1,757,396 |
Effect of exchange rate changes on cash and cash equivalents |  |  | 16,101 |  |  |  | 13,140 |  |  |  | (2,693 | )
Net increase (decrease) in cash and cash equivalents |  |  | (208,378 | ) |  |  | 412,320 |  |  |  | (1,014,658 | )
Cash and cash equivalents, beginning of period |  |  | 991,806 |  |  |  | 579,486 |  |  |  | 1,594,144 |
Cash and cash equivalents, end of period |  | $ | 783,428 |  |  | $ | 991,806 |  |  | $ | 579,486 |
Cash paid during the period for: |  |  |  |  |  |  |  |  |  |  |  |
| Interest, net of amounts capitalized |  | $ | 939,243 |  |  | $ | 462,714 |  |  | $ | 325,334 |
| Income taxes |  | $ | 22,877 |  |  | $ | 18,415 |  |  | $ | 15,451 |

(1) | Includes depreciation and amortization that is also recorded in sales, general and administrative expense and interest expense.

Schedule of non cash investing and financing activities:

| • | 2004 issuance of 24.3 million shares of common stock in exchange for $40.0 million par value of HIGH TIDES I and $75.0 million par value of HIGH TIDES II
| • | 2004 capital lease entered into for the King City facility for an initial asset balance of $114.9 million
| • | 2004 issuance of 89 million shares of Calpine common stock pursuant to a Share Lending Agreement. See Note 17 for more information regarding the 89 million shares issued
| • | 2004 acquired the remaining 50% interest in the Aries Power Plant for $3.7 million cash and $220.0 million of assumed liabilities, including debt of $173.2 million
| • | 2003 issuance of 30 million shares of common stock in exchange for $182.5 million of debt, convertible debt and preferred securities
| • | 2002 non-cash consideration of $88.4 million in tendered Company debt received upon the sale of its British Columbia oil and gas properties

The accompanying notes are an integral part of these consolidated financial statements.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2004, 2003, and 2002

1. | Organization and Operations of the Company

Calpine Corporation, a Delaware corporation, and subsidiaries (collectively, “Calpine” or the “Company”) are engaged in the generation of electricity in the United States of America, Canada, and the United Kingdom. The Company is involved in the development, construction, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. The Company has ownership interests in, and operates, gas-fired power generation and cogeneration facilities, gas fields, gathering systems and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States of America. In Canada, the Company has ownership interests in, and operates, gas-fired power generation facilities. In Mexico, Calpine is a joint venture participant in a gas-fired power generation facility under construction. In the United Kingdom, the Company owns and operates a gas-fired power cogeneration facility. The Company markets electricity produced by its generating facilities to utilities and other third party purchasers. Thermal energy produced by the gas-fired power cogeneration facilities is primarily sold to industrial users. Gas produced, and not physically delivered to the Company’s generating plants, is sold to third parties. The Company offers to third parties energy procurement, liquidation and risk management services, combustion turbine component parts and repair and maintenance services world-wide. The Company also provides engineering, procurement, construction management, commissioning and operations and maintenance (“O&M”) services.

2. | Summary of Significant Accounting Policies

Principles of Consolidation — The accompanying consolidated financial statements include accounts of the Company and its wholly owned and majority-owned subsidiaries. The Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. (“FIN”) 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (“FIN 46”) for its investments in special purpose entities as of December 31, 2003. These consolidated financial statements as of December 31, 2004 and 2003, and for the twelve months ended December 31, 2004, also include the accounts of those special purpose Variable Interest Entities (“VIE”) for which the Company is the Primary Beneficiary. The Company adopted FIN 46, as revised (“FIN 46-R”) for its investments in non-special purpose VIEs on March 31, 2004. These consolidated financial statements as of December 31, 2004 and for the nine months ended December 31, 2004 include the accounts of non-special purpose VIEs for which the Company is the Primary Beneficiary. Certain less-than-majority-owned subsidiaries are accounted for using the equity method or cost method. For equity method investments, the Company’s share of income is calculated according to the Company’s equity ownership or according to the terms of the appropriate partnership agreement (see Note 7). For cost method investments, income is recognized when equity distributions are received. All intercompany accounts and transactions are eliminated in consolidation.
Unrestricted Subsidiaries — The information in this paragraph is required to be provided under the terms of the indentures and credit agreement governing the various tranches of the Company’s second-priority secured indebtedness (collectively, the “Second Priority Secured Debt Instruments”). The Company has designated certain of its subsidiaries as “unrestricted subsidiaries” under the Second Priority Secured Debt Instruments. A subsidiary with “unrestricted” status thereunder generally is not required to comply with the covenants contained therein that are applicable to “restricted subsidiaries.” The Company has designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as “unrestricted subsidiaries” for purposes of the Second Priority Secured Debt Instruments.
Reclassifications — Certain prior years’ amounts in the consolidated financial statements have been reclassified to conform to the 2004 presentation. These include a reclassification between sales, general and administrative expense (“SG&A”) and plant operating expense for information technology and stock compensation costs and reclassifications to begin separately disclosing: (1) research and development expense

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(formerly in SG&A), (2) transmission sales revenue (formerly in electricity and steam revenue), (3) oil and gas impairment (formerly in depreciation, depletion and amortization expense) and (4) transmission purchase expense (formerly in plant operating expense).
As a result of current year dispositions, certain prior year amounts have been reclassified to conform with discontinued operations presentation. See Note 10.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to useful lives and carrying values of assets (including the carrying value of projects in development, construction, and operation), provision for income taxes, fair value calculations of derivative instruments and associated reserves, capitalization of interest, primary beneficiary determination for the Company’s investments in VIEs, the outcome of pending litigation and estimates of oil and gas reserve quantities used to calculate depletion, depreciation and impairment of oil and gas property and equipment.
Foreign Currency Translation — Through its international operations, the Company owns subsidiary entities in several countries. These entities generally have functional currencies other than the U.S. dollar; in most cases, the functional currency is consistent with the local currency of the host country where the particular entity is located. In accordance with FASB Statement of Financial Accounting Standards (“SFAS”) No. 52, “Foreign Currency Translation,” (“SFAS No. 52”) the Company translates the financial statements of its foreign subsidiaries from their respective functional currencies into the U.S. dollar, which represents the Company’s reporting currency.
Assets and liabilities held by the foreign subsidiaries are translated into U.S. dollars using exchange rates in effect at the balance sheet date. Certain long-term assets (such as the investment in a subsidiary company) as well as equity accounts are translated into U.S. dollars using historical exchange rates at the date the specific transaction occurred which created the asset or equity balance (such as the date of the initial investment in the subsidiary). Income and expense accounts are translated into U.S. dollars using average exchange rates during the reporting period. All translation gains and losses that result from translating the financial statements of the Company’s foreign subsidiaries from their respective functional currencies into the U.S. dollar reporting currency are recognized within the Cumulative Translation Adjustment (“CTA”) account, which is a component of Other Comprehensive Income (“OCI”) within Stockholders’ Equity.
In certain cases, the Company and its foreign subsidiary entities hold monetary assets and/or liabilities that are not denominated in the functional currencies referred to above. In such instances, the Company applies the provisions of SFAS No. 52 to account for the monthly re-measurement gains and losses of these assets and liabilities into the functional currencies for each entity.
For foreign currency transactions designated as economic hedges of a net investment in a foreign entity and for intercompany foreign currency transactions which are of a long-term investment nature, the Company records the re-measurement gains and losses through the CTA account, in accordance with Paragraph 20 of SFAS No. 52.
All other foreign currency transactions that do not qualify for the Paragraph 20 exclusion are re-measured at the end of each month into the proper functional currency, and the gains and losses resulting from such re-measurement are recorded within net income, in accordance with Paragraph 15 of SFAS No. 52.
For the years ended December 31, 2004, 2003 and 2002, the Company recognized foreign currency transaction losses from continuing operations of $25.1 million, $33.3 million and $1.0 million, respectively,

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
which were recorded within Other Income on the Company’s Consolidated Statements of Operations. Additionally, the Company settled a series of forward foreign exchange contracts associated with the sale of its Canadian oil and gas assets in 2004. See Note 10 for further discussion or the settlement of these contracts within discontinued operations. Subsequent to December 31, 2004, the Company was exposed to significant exchange rate movements between the Canadian dollar and the U.S. dollar due to several large intercompany transactions between Calpine’s U.S. and Canadian subsidiaries. Subsequent to December 31, 2004, the U.S. dollar strengthened considerably against the Canadian dollar and the Company recognized re-measurement gains on these transactions of approximately $24.0 million; however, these gains could reverse based on future exchange rate movements.
Fair Value of Financial Instruments — The carrying value of accounts receivable, marketable securities, accounts payable and other payables approximate their respective fair values due to their short maturities. See Note 18 for disclosures regarding the fair value of the senior notes.
Cash and Cash Equivalents — The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The carrying amount of these instruments approximates fair value because of their short maturity.
The Company has certain project debt and lease agreements that establish working capital accounts which limit the use of certain cash balances to the operations of the respective plants. At December 31, 2004 and 2003, $284.4 million and $392.3 million, respectively, of the cash and cash equivalents balance was subject to such project debt and lease agreements.
Accounts Receivable and Accounts Payable — Accounts receivable and payable represent amounts due from customers and owed to vendors. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances and do not bear interest. Reserve and allowance accounts represent the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company reviews the financial condition of customers prior to granting credit. The Company determines the allowance based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting its customer base, significant one-time events and historical write off experience. Also, specific provisions are recorded for individual receivables when the Company becomes aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. The Company reviews the adequacy of its reserves and allowances quarterly. Generally, past due balances over 90 days and over a specified amount are individually reviewed for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.
The accounts receivable and payable balances also include settled but unpaid amounts relating to hedging, balancing, optimization and trading activities of Calpine Energy Services, L.P. (“CES”). Some of these receivables and payables with individual counterparties are subject to master netting agreements whereby the Company legally has a right of offset and the Company settles the balances net. However, for balance sheet presentation purposes and to be consistent with the way the Company presents the majority of amounts related to hedging, balancing and optimization activities in its consolidated statements of operations under Staff Accounting Bulletin (“SAB”) No. 101 “Revenue Recognition in Financial Statements,” as amended by SAB No. 104 “Revenue Recognition” (collectively “SAB No. 101”), and Emerging Issues Task Force (“EITF”) Issue No. 99-19 “Reporting Revenue Gross as a Principal Versus Net as an Agent,” (“EITF Issue No. 99-19”) the Company presents its receivables and payables on a gross basis. CES receivable balances (which comprise the majority of the accounts receivable balance at December 31, 2004) greater than 30 days past due are individually reviewed for collectibility, and if deemed uncollectible, are charged off against the allowance accounts or reversed out of revenue after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance-sheet credit exposure related to its customers.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Inventories — The Company’s inventories primarily include spare parts, stored gas and oil as well as work-in-process. Inventories are valued at the lower of cost or market. The cost for spare parts as well as stored gas and oil is generally determined using the weighted average cost method. Work-in-process is generally determined using the specific identification method and represents the value of manufactured goods during the manufacturing process. The inventory balance at December 31, 2004, was $179.4 million. This balance is comprised of $117.1 million of spare parts, $53.2 million of stored gas and oil as well as $9.1 million of work-in-process. The inventory balance at December 31, 2003, was $137.7 million. This balance is comprised of $88.3 million of spare parts, $43.5 million of stored gas and oil as well as $5.9 million of work-in-process.
Margin Deposits — As of December 31, 2004 and 2003, as credit support for the gas and power procurement and risk management activities conducted on the Company’s behalf, CES had deposited net amounts of $248.9 million and $188.0 million, respectively, in cash as margin deposits.
Available-for-Sale Debt Securities — See Note 3 for a discussion of the Company’s accounting policy for its available-for-sale debt securities.
Property, Plant and Equipment, Net — See Note 4 for a discussion of the Company’s accounting policies for its property, plant and equipment.
Project Development Costs — The Company capitalizes project development costs once it is determined that it is highly probable that such costs will be realized through the ultimate construction of a power plant. These costs include professional services, salaries, permits, capitalized interest, and other costs directly related to the development of a new project. Upon commencement of construction, these costs are transferred to construction in progress (“CIP”), a component of property, plant and equipment. Upon the start-up of plant operations, these construction costs are reclassified as buildings, machinery and equipment, also a component of property, plant and equipment, and are depreciated as a component of the total cost of the plant over its estimated useful life. Capitalized project costs are charged to expense if the Company determines that the project is no longer probable or to the extent it is impaired. Outside services and other third party costs are capitalized for acquisition projects.
Investments in Power Projects and Oil and Gas Properties — See Note 7 for a discussion of the Company’s accounting policies for its investments in power projects and oil and gas properties. In November 2004 one of the Company’s equity method investees filed for protection under Chapter 11 of the U.S. Bankruptcy code. As a result of this legal proceeding, the Company has lost significant influence and control of the project. Consequently, as of December 31, 2004, the Company no longer accounts for this investment using the equity method but instead uses the cost method. See Note 7 for a discussion of this event.
Restricted Cash — The Company is required to maintain cash balances that are restricted by provisions of its debt agreements, lease agreements and regulatory agencies. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent service, major maintenance and debt repurchases. Funds that can be used to satisfy obligations due during the next twelve months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents in the consolidated statements of cash flows.
As part of a prior business acquisition which included certain facilities subject to a pre-existing operating lease, the Company acquired certain restricted cash balances comprised of a portfolio of debt securities. This portfolio is classified as held-to-maturity because the Company has the intent and ability to hold the securities to maturity. The securities are held in escrow accounts to support operating activities of the leased facilities and consist of a $17.0 million debt security maturing in 2015 and a $7.4 million debt security maturing in

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2023. This portfolio is stated at amortized cost, adjusted for amortization of premiums and accretion discounts to maturity.
Of the Company’s restricted cash at December 31, 2004, $276.0 million relates to the assets of the following entities, each an entity with its existence separate from the Company and other subsidiaries of the Company.

Bankruptcy-Remote Subsidiary |  | 2004 |
Power Contracting Finance, LLC |  | $ | 175.6 |
Gilroy Energy Center, LLC |  |  | 53.5 |
Rocky Mountain Energy Center, LLC |  |  | 18.1 |
Riverside Energy Center, LLC |  |  | 7.1 |
Calpine Energy Management, L.P. |  |  | 6.9 |
Calpine King City Cogen, LLC |  |  | 6.7 |
Calpine Northbrook Energy Marketing, LLC |  |  | 6.0 |
Power Contracting Finance III, LLC |  |  | 1.5 |
Creed Energy Center, LLC |  |  | 0.3 |
Goose Haven Energy Center, LLC |  |  | 0.3 |

Notes Receivable — See Note 8 for a discussion of the Company’s accounting policies for its notes receivable.
Preferred Interests — As outlined in SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” (“SFAS No. 150”) the Company classifies preferred interests that embody obligations to transfer cash to the preferred interest holder, in short-term and long-term debt. These instruments require the Company to make priority distributions of available cash, as defined in each preferred interest agreement, representing a return of the preferred interest holder’s investment over a fixed period of time and at a specified rate of return in priority to certain other distributions to equity holders. The return on investment is recorded as interest expense under the interest method over the term of the priority period. See Note 12 for a further discussion of the Company’s accounting policies for its preferred interests.
Deferred Financing Costs — See Note 11 for a discussion of the Company’s accounting policies for deferred financing costs.
Goodwill and Other Intangible Assets — See Note 5 for a discussion of the Company’s accounting for goodwill and other intangible assets.
Long-Lived Assets — In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (“SFAS No. 144”) the Company evaluates the impairment of long-lived assets, including construction and development projects, based on the projection of undiscounted pre-interest expense and pre-tax expense cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. The significant assumptions that the Company uses in its undiscounted future cash flow estimates include the future supply and demand relationships for electricity and natural gas, the expected pricing for those commodities and the resultant spark spreads in the various regions where the Company generates, and external oil and gas year-end reserve reports prepared by licensed independent petroleum engineering firms. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values. See Note 4 for more information on the impairment charges recorded for oil and gas properties. Certain of the Company’s generating assets are located in regions with depressed demands and market spark spreads. The Company’s forecasts assume that spark spreads will increase in future years in these regions as the supply and demand relationships improve.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Concentrations of Credit Risk — Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of cash, accounts receivable, notes receivable, and commodity contracts. The Company’s cash accounts are generally held in FDIC insured banks. The Company’s accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the United States (see Notes 8 and 22). The Company generally does not require collateral for accounts receivable from end-user customers, but evaluates the net accounts receivable, accounts payable, and fair value of commodity contracts with trading companies and may require security deposits or letters of credit to be posted if exposure reaches a certain level.
Deferred Revenue — The Company’s deferred revenue consists primarily of deferred gains related to certain sale/leaseback transactions as well as deferred revenue for long-term power supply contracts including contracts accounted for as operating leases.
Trust Preferred Securities — Prior to the adoption of FIN 46, as originally issued, for special purpose VIEs on October 1, 2003, the Company’s trust preferred securities were accounted for as a minority interest in the balance sheet and reflected as “Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts.” The distributions were reflected in the Consolidated Statements of Operations as “distributions on trust preferred securities” through September 30, 2003. Financing costs related to these issuances are netted with the principal amounts and were accreted as minority interest expense over the securities’ 30-year maturity using the straight-line method which approximated the effective interest rate method. Upon the adoption of FIN 46, the Company deconsolidated the Calpine Capital Trusts. Consequently, the Trust Preferred Securities are no longer on the Company’s Consolidated Balance Sheet and were replaced with the debentures issued by the Company to the Calpine Capital Trusts. Due to the relationship with the Calpine Capital Trusts, the Company considers Calpine Capital Trust (“Trust I”), Calpine Capital Trust II (“Trust II”) and Calpine Capital Trust III (“Trust III”) to be related parties. The interest payments on the debentures are now reflected in the Consolidated Statements of Operations as “interest expense.” See Note 12 for further information.
Revenue Recognition — The Company is primarily an electric generation company with consolidated revenues being earned from operating a portfolio of mostly wholly owned plants. Equity investment income is also earned from plants in which our ownership interest is 50% or less or the Company is not the Primary Beneficiary under FIN 46-R, and which are accounted for under the equity method. In conjunction with its electric generation business, the Company also produces, as a by-product, thermal energy for sale to customers, principally steam hosts at the Company’s cogeneration sites. In addition, the Company acquires and produces natural gas for its own consumption and sells the balance and oil produced to third parties. Where applicable, revenues are recognized under EITF Issue No. 91-06, “Revenue Recognition of Long Term Power Sales Contracts,” (“EITF Issue No. 91-06”) ratably over the terms of the related contracts. To protect and enhance the profit potential of its electric generation plants, the Company, through its subsidiary, CES, enters into electric and gas hedging, balancing, and optimization transactions, subject to market conditions, and CES has also, from time to time, entered into contracts considered energy trading contracts under EITF Issue No. 02-03, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management” (“EITF Issue No. 02-03”). CES executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, CES generally acts as a principal, takes title to the commodities, and assumes the risks and rewards of ownership. Therefore, when CES does not hold these contracts for trading purposes and, in accordance with SAB No. 101, and EITF Issue No. 99-19, the Company records settlement of the majority of its non-trading physical forward contracts on a gross basis.
The Company, through its wholly owned subsidiary, Power Systems MFG., LLC (“PSM”), designs and manufactures certain spare parts for gas turbines. The Company in the past has also generated revenue by occasionally loaning funds to power projects, and currently provides O&M services to third parties and to

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
certain unconsolidated power projects. The Company also sells engineering and construction services to third parties for power projects. Further details of the Company’s revenue recognition policy for each type of revenue transaction are provided below:

| Accounting for Commodity Contracts

Commodity contracts are evaluated to determine whether the contract is (1) accounted for as a lease (2) accounted for as a derivative (3) or accounted for as an executory contract and additionally whether the financial statement presentation is gross or net.
Leases — Commodity contracts are evaluated for lease accounting in accordance with SFAS No. 13, “Accounting for Leases,” (“SFAS No. 13”) and EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” (EITF Issue No. 01-08). EITF Issue No. 01-08 clarifies the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements (“PPA”), accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. Prior to adopting EITF Issue No. 01-08, the Company had accounted for certain contractual arrangements as leases under existing industry practices, and the adoption of EITF Issue No. 01-08 did not materially change the Company’s accounting for leases. Under the guidance of SFAS No. 13, operating leases with minimum lease rentals which vary over time must be levelized over the term of the contract. The Company currently levelizes these contracts on a straight-line basis. See Note 22 for additional information on our operating leases. For income statement presentation purposes, income from PPAs accounted for as leases is classified within electricity and steam revenue in the Company’s consolidated statements of operations.
Derivative Instruments — SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.
Accounting for derivatives at fair value requires the Company to make estimates about future prices during periods for which price quotes are not available from sources external to the Company. As a result, the Company is required to rely on internally developed price estimates when external price quotes are unavailable. The Company derives its future price estimates, during periods where external price quotes are unavailable, based on an extrapolation of prices from periods where external price quotes are available. The Company performs this extrapolation using liquid and observable market prices and extending those prices to an internally generated long-term price forecast based on a generalized equilibrium model.
SFAS No. 133 sets forth the accounting requirements for cash flow and fair value hedges. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of OCI and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS No. 133 provides that the changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment be recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
With respect to cash flow hedges, if the forecasted transaction is no longer probable of occurring, the associated gain or loss recorded in OCI is recognized currently. In the case of fair value hedges, if the underlying asset, liability or firm commitment being hedged is disposed of or otherwise terminated, the gain or loss associated with the underlying hedged item is recognized currently. If the hedging instrument is terminated prior to the occurrence of the hedged forecasted transaction for cash flow hedges, or prior to the settlement of the hedged asset, liability or firm commitment for fair value hedges, the gain or loss associated with the hedge instrument remains deferred.
Where the Company’s derivative instruments are subject to the special transition adjustment for the estimated future economic benefits of these contracts upon 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”) the Company will amortize the corresponding asset recorded upon adoption of DIG Issue No. C20 through a charge to earnings in future periods. Accordingly on October 1, 2003, the date the Company adopted DIG Issue No. C20, the Company recorded other current assets and other assets of approximately $33.5 million and $259.9 million, respectively, and a cumulative effect of a change in accounting principle of approximately $181.9 million, net of $111.5 million of tax. For all periods subsequent to October 1, 2003, the Company will account for the contracts as normal purchases and sales under the provisions of DIG Issue No. C20.
Mark-to-Market, net activity includes realized settlements of and unrealized mark-to-market gains and losses on both power and gas derivative instruments not designated as cash flow hedges, including those held for trading purposes. Gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses. Trading activity is presented net in accordance with EITF Issue No. 02-03.
Executory Contracts — Where commodity contracts do not qualify as leases or derivatives, the contracts are classified as executory contracts. These contracts apply traditional accrual accounting unless the revenue must be levelized per EITF Issue No. 91-06. The Company currently accounts for one commodity contract under EITF Issue No. 91-06 which is levelized over the term of the agreement.
Financial Statement Presentation — Where the Company’s derivative instruments are subject to a netting agreement and the criteria of FIN 39 “Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10 and SFAS No. 105)” (“FIN 39”) are met, the Company presents its derivative assets and liabilities on a net basis in its balance sheet. The Company has chosen this method of presentation because it is consistent with the way related mark-to-market gains and losses on derivatives are recorded in its Consolidated Statements of Operations and within OCI.
Presentation of revenue under EITF Issue No. 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS 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”) — The Company accounts for certain of its power sales and purchases on a net basis under EITF Issue No. 03-11, which the Company adopted on a prospective basis on October 1, 2003. Transactions with either of the following characteristics are presented net in the Company’s Consolidated Financial Statements: (1) transactions executed in a back-to-back buy and sale pair, primarily because of market protocols; and (2) physical power purchase and sale transactions where the Company’s power schedulers net the physical flow of the power purchase against the physical flow of the power sale (or “book out” the physical power flows) as a matter of scheduling convenience to eliminate the need to schedule actual power delivery. These book out transactions may occur with the same counterparty or between different counterparties where the

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Company has equal but offsetting physical purchase and delivery commitments. In accordance with EITF Issue No. 03-11, the Company netted the following amounts (in thousands):

|  | Year Ended December 31, |
|  | 2004 |  |  | 2003 |
Sales of purchased power for hedging and optimization |  | $ | 1,676,003 |  |  | $ | 256,573 |
Purchased power expense for hedging and optimization |  | $ | 1,676,003 |  |  | $ | 265,573 |

Electric Generation and Marketing Revenue — This includes electricity and steam sales, transmission sales revenue and sales of purchased power for hedging, balancing and optimization. Subject to market and other conditions, the Company manages the revenue stream for its portfolio of electric generating facilities. The Company markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties, through hedging, balancing and optimization transactions. The Company also, from time-to-time, sells excess transmission capacity. CES performs a market-based allocation of electric generation and marketing revenue to electricity and steam sales (based on electricity delivered by the Company’s electric generating facilities) and to sales of purchased power.
Oil and Gas Production and Marketing Revenue — This includes sales to third parties of oil, gas and related products that are produced by the Company’s Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and, subject to market and other conditions, sales of purchased gas arising from hedging, balancing and optimization transactions. Oil and gas sales for produced products are recognized pursuant to the sales method, net of royalties. If the Company has recorded gas sales on a particular well or field in excess of its share of remaining estimated reserves, then the excessive gas sale imbalance is recognized as a liability. If the Company is under-produced on a particular well or field, and it is determined that an over-produced partner’s share of remaining reserves is insufficient to settle the gas imbalance, the Company will recognize a receivable, to the extent collectible, from the over-produced partner.
Other Revenue — This includes O&M contract revenue, PSM and Thomassen Turbine Systems B.V. (“TTS”) revenue from sales to third parties, engineering and construction revenue and miscellaneous revenue.
Plant Operating Expense — This primarily includes employee expenses, repairs and maintenance, insurance, and property taxes.
Purchased Power and Purchased Gas Expense — The cost of power purchased from third parties for hedging, balancing and optimization activities is recorded as purchased power expense, a component of electric generation and marketing expense. The Company records the cost of gas purchased from third parties for the purposes of consumption in its power plants as fuel expense, while gas purchased from third parties for hedging, balancing, and optimization activities is recorded as purchased gas expense for hedging and optimization, a component of oil and gas production and marketing expense. Certain hedging, balancing and optimization activity is presented net in accordance with EITF Issue No. 03-11. See discussion above.
Research and Development Expense — The Company engages in research and development (“R&D”) activities through PSM. R&D activities related to the design and manufacturing of high performance combustion system and turbine blade parts are accounted for in accordance with SFAS No. 2, “Accounting for Research and Development Costs.” The Company’s R&D expense includes costs incurred for conceptual formulation and design of new vanes, blades, combustors and other replacement parts for the industrial gas turbine industry.
Provision (Benefit) for Income Taxes — Deferred income taxes are based on the differences between the financial reporting and tax bases of assets and liabilities. The deferred income tax provision represents the

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
changes during the reporting period in the deferred tax assets and deferred tax liabilities, net of the effect of acquisitions and dispositions. Deferred tax assets include tax losses and tax credit carryforwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Additionally, with respect to income taxes, the Company assumes the deductibility of certain costs in its income tax filings and estimates the future recovery of deferred tax assets. For the twelve months ended December 31, 2004, 2003 and 2002, the Company’s effective tax (benefit) rate from continuing operations was 39%, 9% and 29%, respectively. Also, see Note 19 concerning the impact of tax legislation passed October 22, 2004.
Insurance Program — CPN Insurance Corporation, a wholly owned captive insurance subsidiary, charges the Company premium rates to insure casualty lines (worker’s compensation, automobile liability, and general liability) as well as all risk property insurance including business interruption. Accruals for casualty claims under the captive insurance program are recorded on a monthly basis, and are based upon the estimate of the total cost of the claims incurred during the policy period. Accruals for claims under the captive insurance program pertaining to property, including business interruption claims, are recorded on a claims-incurred basis. In consolidation, claims are accrued on a gross basis before deductibles. The captive provides insurance coverage with limits up to $25 million per occurrence for property claims, including business interruption, and up to $500,000 per occurrence for casualty claims. Intercompany transactions between the captive insurance program and Calpine affiliates are eliminated in consolidation.
Stock-Based Compensation — See Note 21 for a discussion of the Company’s accounting policies for stock-based compensation.
Operational Data — Operational data (including, but not limited to, megawatts (“MW”), megawatt hours (“MWh”), billions cubic feet equivalent (“Bcfe”) and thousand barrels (“MBbl”)), throughout this Form 10-K is unaudited.

| New Accounting Pronouncements

| SFAS No. 144

Effective January 1, 2002, the Company adopted SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”), which changed the criteria for determining when the disposal or sale of certain assets meets the definition of “discontinued operations.” Some of the Company’s asset sales in 2002, 2003 and 2004 met the requirements of the new definition and accordingly, the Company made reclassifications to current and prior period financial statements to reflect the sale or designation as “held for sale” of certain oil and gas and power plant assets and liabilities and to separately classify the operating results of the assets sold and gain on sale of those assets from the operating results of continuing operations. See Note 10 for further information.

| FIN 46 and FIN 46-R

In January 2003, FASB issued FIN 46. FIN 46, as originally issued, was effective immediately for VIEs created or acquired after January 31, 2003. FIN 46 requires the consolidation of an entity by an enterprise that absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interest in the entity. Historically, entities have generally been consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The objectives of FIN 46 are to provide guidance on the identification of VIEs for which control is achieved through means other than ownership of a majority of the voting interest of the entity, and how to determine which business enterprise (if any), as the Primary Beneficiary, should consolidate the VIE. This model for consolidation applies to an entity in which either (1) the at-risk equity is insufficient to absorb expected losses without additional subordinated financial support or (2) its at-risk equity

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
holders as a group are not able to make decisions that have a significant impact on the success or failure of the entity’s ongoing activities. A variable interest in a VIE, by definition, is an asset, liability, equity, contractual arrangement or other economic interest that absorbs the entity’s variability.
In December 2003, FASB modified FIN 46 with FIN 46-R to make certain technical corrections and to address certain implementation issues. FIN 46-R delayed the effective date of the interpretation to March 31, 2004, (for calendar-year enterprises), for all non-Special Purpose Entity (“SPE”) VIEs. FIN 46, as originally issued was effective as of December 31, 2003, for all investments in SPEs. The Company has adopted FIN 46-R for its equity method joint ventures and operating lease arrangements containing fixed price purchase options, its wholly owned subsidiaries that are subject to long-term PPAs and tolling arrangements and its wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests as of March 31, 2004, and for its investments in SPEs as of December 31, 2003.

| Joint Venture Investments and Operating Leases with Fixed Price Options

On application of FIN 46-R, the Company evaluated its economic interests in joint venture investments and operating lease arrangements containing fixed price purchase options and concluded that, in some instances, these entities were VIEs. However, in these instances, the Company was not the Primary Beneficiary, as the Company would not absorb a majority of these entities’ expected variability. An enterprise that holds a significant variable interest in a VIE is required to make certain disclosures regarding the nature and timing of its involvement with the VIE and the nature, purpose, size and activities of the VIE. The fixed price purchase options under the Company’s operating lease arrangements were not considered significant variable interests. However, the joint ventures in which the Company has invested, and which did not qualify for the definition of a business scope exception outlined in paragraph 4(h) of FIN 46-R, were considered significant variable interests and the required disclosures have been made in Note 7 for these joint venture investments.

| Significant Long-Term Power Sales and Tolling Agreements

An analysis was performed for the Company’s wholly owned subsidiaries with significant long-term power sales or tolling agreements. Certain of these 100% Company-owned subsidiaries were deemed to be VIEs by virtue of the power sales and tolling agreements which met the definition of a variable interest under FIN 46-R. However, in all cases, the Company absorbed a majority of the entity’s variability and continues to consolidate these wholly owned subsidiaries. As part of the Company’s quantitative assessment, a fair value methodology was used to determine whether the Company or the power purchaser absorbed the majority of the subsidiary’s variability. As part of the analysis, the Company qualitatively determined that power sales or tolling agreements with a term for less than one-third of the facility’s remaining useful life or for less than 50% of the entity’s capacity would not cause the power purchaser to be the Primary Beneficiary, due to the length of the economic life of the underlying assets. Also, power sales and tolling agreements meeting the definition of a lease under EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” were not considered variable interests, since lease payments create rather than absorb variability, and therefore, do not meet the definition of a variable interest.

| Preferred Interests issued from Wholly-Owned Subsidiaries

A similar analysis was performed for the Company’s wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests. These entities were determined to be VIEs in which the Company absorbs the majority of the variability, primarily due to the debt characteristics of the preferred interest, which are classified as debt in accordance with SFAS No. 150, in the Company’s Consolidated Balance Sheets. As a result, the Company continues to consolidate these wholly owned subsidiaries.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| Investments in Special Purpose Entities

Significant judgment was required in making an assessment of whether or not a VIE was an SPE for purposes of adopting and applying FIN 46, as originally issued at December 31, 2003. Since the current accounting literature does not provide a definition of an SPE, the Company’s assessment was primarily based on the degree to which the VIE aligned with the definition of a business outlined in FIN 46-R. Entities that meet the definition of a business outlined in FIN 46-R and that satisfy other formation and involvement criteria are not subject to the FIN 46-R consolidation guidelines. The definitional characteristics of a business include having: inputs such as long-lived assets; the ability to obtain access to necessary materials and employees; processes such as strategic management, operations and resource management; and the ability to obtain access to the customers that purchase the outputs of the entity. Based on this assessment, the Company determined that six VIE investments were in SPEs requiring further evaluation and were subject to the application of FIN 46, as originally issued, as of December 31, 2003: Calpine Northbrook Energy Marketing, LLC (“CNEM”), Power Contract Financing, L.L.C. (“PCF”), Power Contract Financing III, LLC (“PCF III”) and Trust I, Trust II and Trust III (collectively, the “Trusts”).
On May 15, 2003, the Company’s wholly owned subsidiary, CNEM, completed the $82.8 million monetization of an existing power sales agreement with the Bonneville Power Administration (“BPA”). CNEM borrowed $82.8 million secured by the spread between the BPA contract and certain fixed power purchase contracts. CNEM was established as a bankruptcy-remote entity and the $82.8 million loan is recourse only to CNEM’s assets and is not guaranteed by the Company. CNEM was determined to be a VIE in which the Company was the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into the Company’s accounts as of June 30, 2003.
On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of CES, completed an offering of two tranches of Senior Secured Notes Due 2006 and 2010 (collectively called the “PCF Notes”), totaling $802.2 million. To facilitate the transaction, the Company formed PCF as a wholly owned, bankruptcy remote entity with assets and liabilities consisting of certain transferred power purchase and sales contracts, which serve as collateral for the PCF Notes. The PCF Notes are non-recourse to the Company’s other consolidated subsidiaries. PCF was determined to be a VIE in which the Company was the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into the Company’s accounts as of June 30, 2003.
Upon the application of FIN 46, as originally issued at December 31, 2003, for the Company’s investments in SPEs, the Company determined that its equity investment in the Trusts was not considered at-risk as defined in FIN 46 and that the Company did not have a significant variable interest in the Trusts. Consequently, the Company deconsolidated the Trusts as of December 31, 2003.
In addition, as a result of the debt reserve monetization consummated on June 2, 2004, the Company was required to evaluate its new investments in the PCF and PCF III entities under FIN 46-R (effective March 31, 2004). The Company determined that the entities were VIEs but the Company was not the Primary Beneficiary and was, therefore, required to deconsolidate the entities as of June 30, 2004.
The Company created CNEM, PCF, PCF III and the Trusts to facilitate capital transactions. However, in cases such as this where the Company has continuing involvement with the assets held by the deconsolidated SPE, the Company accounts for the capital transaction with the SPE as a financing rather than a sale under EITF Issue No. 88-18, “Sales of Future Revenue” (“EITF Issue No. 88-18”) or SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities — a Replacement of FASB Statement No. 125” (“SFAS No. 140”), as appropriate. When EITF Issue No. 88-18 and SFAS No. 140 require the Company to account for a transaction as a financing, derecognition of the assets underlying the financing is prohibited, and the proceeds received from the transaction must be recorded as debt. Accordingly, in situations where the Company accounts for transactions as financings under EITF

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Issue No. 88-18 or SFAS No. 140, the Company continues to recognize the assets and the debt of the deconsolidated SPE on its balance sheet. The table below summarizes how the Company has accounted for its SPEs when it has continuing involvement under EITF Issue No. 88-18 or SFAS No. 140:

|  | FIN 46-R |  |  | Sale or |
|  | Treatment |  |  | Financing |
CNEM |  |  | Consolidate |  |  |  | N/A |
PCF |  |  | Deconsolidate |  |  |  | Financing |
PCF III |  |  | Deconsolidate |  |  |  | Financing |
Trust I, Trust II and Trust III |  |  | Deconsolidate |  |  |  | Financing |

| EITF Issue No. 04-07

An integral part of applying FIN 46-R is determining which economic interests are variable interests. In order for an economic interest to be considered a variable interest, it must “absorb variability” of changes in the fair value of the VIE’s underlying net assets. Questions have arisen regarding (a) how to determine whether an interest absorbs variability, and (b) whether the nature of how a long position is created, either synthetically through derivative transactions or through cash transactions, should affect the assessment of whether an interest is a variable interest. EITF Issue No. 04-07, “Determining Whether an Interest Is a Variable Interest in a Potential Variable Interest Entity” (“EITF Issue No. 04-07”) is still in the discussion phase, but will eventually provide a model to assist in determining whether an economic interest in a VIE is a variable interest. The Task Force’s discussions on this Issue have centered on if the variability should be based on whether (a) the interest absorbs fair value variability, (b) the interest absorbs cash flow variability, or (c) the interest absorbs both fair value and cash flow variability. While a consensus has not been reached, a majority of the Task Force members generally support an approach that would determine predominant variability based on the nature of the operations of the VIE. Under this view, for financial VIEs a presumption would exist that only interests that absorb fair value variability would be considered variable interests. Conversely, for non-financial (or operating) VIEs, a presumption would exist that only interests that absorb cash flow variability would be considered variable interests. The final conclusions reached on this issue may impact the Company’s methodology used in making quantitative and/or qualitative assessments of the variability absorbed by the different economic interests holders in the VIE’s in which the Company holds a variable interest. However, until the EITF reaches a final consensus, the effects of this issue on the Company’s financial statements is indeterminable.

| EITF Issue No. 04-08

On September 30, 2004, the EITF reached a final consensus on EITF Issue No. 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share” (“EITF Issue No. 04-08”). The guidance in EITF Issue No. 04-08 is effective for periods ending after December 15, 2004, and must be applied by retroactively restating previously reported earnings per share (“EPS”) results. The consensus requires companies that have issued contingently convertible instruments with a market price trigger to include the effects of the conversion in diluted EPS (if dilutive), regardless of whether the price trigger had been met. Prior to this consensus, contingently convertible instruments were not included in diluted EPS if the price trigger had not been met. Typically, the affected instruments are convertible into common stock of the issuer after the issuer’s common stock price has exceeded a predetermined threshold for a specified time period. Calpine’s $634 million of 4.75% Contingent Convertible Senior Notes Due 2023 (“2023 Convertible Senior Notes”) and $736 million aggregate principal amount at maturity of Contingent Convertible Notes Due 2014 (“2014 Convertible Notes”) outstanding at December 31, 2004, are affected by the new guidance. Depending on the closing price of the Company’s common stock at the end of each reporting period, the conversion provisions in these Contingent Convertible Notes may significantly impact the reported diluted EPS amounts

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
in future periods.
For the twelve months ended December 31, 2004, approximately 8.6 million weighted common shares potentially issuable under the Company’s outstanding 2014 Contingent Convertible Notes were excluded from the diluted earnings per share calculations as the inclusion of such shares would have been antidilutive because of the Company’s net loss. The 2023 Convertible Senior Notes would not have impacted the diluted EPS calculation for any reporting period since issuance in November 2003, because the Company’s closing stock price at each period end was below the conversion price.

| SFAS No. 128-R

FASB is expected to revise SFAS No. 128, “Earnings Per Share” (“SFAS No. 128”) to make it consistent with International Accounting Standard No. 33, “Earnings Per Share,” so that EPS computations will be comparable on a global basis. This new guidance is expected to be issued by the end of 2005 and will require restatement of prior periods diluted EPS data. The proposed changes will affect the application of the treasury stock method and contingently issuable (based on conditions other than market price) share guidance for computing year-to-date diluted EPS. In addition to modifying the year-to-date calculation mechanics, the proposed revision to SFAS No. 128 would eliminate a company’s ability to overcome the presumption of share settlement for those instruments or contracts that can be settled, at the issuer or holder’s option, in cash or shares. Under the revised guidance, FASB has indicated that any possibility of share settlement other than in an event of bankruptcy will require a presumption of share settlement when calculating diluted EPS. The Company’s 2023 Convertible Senior Notes and 2014 Convertible Notes contain provisions that would require share settlement in the event of conversion under certain limited events of default, including bankruptcy. Additionally, the 2023 Convertible Senior Notes include a provision allowing the Company to meet a put with either cash or shares of stock. The revised guidance, if not amended before final issuance, would increase the potential dilution to the Company’s EPS, particularly when the price of the Company’s common stock is low, since the more dilutive of calculations would be used considering both:

| (i) normal conversion assuming a combination of cash and a variable number of shares; and
| (ii) conversion during certain limited events of default assuming 100% shares at the fixed conversion rate, or, in the case of the 2023 Convertible Senior Notes, meeting a put entirely with shares of stock.

| EITF Issue No. 03-13

At the November 2004 EITF meeting, the final consensus was reached on EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations” (“EITF Issue No. 03-13”). This Issue is effective prospectively for disposal transactions entered into after January 1, 2005, and provides a model to assist in evaluating (a) which cash flows should be considered in the determination of whether cash flows of the disposal component have been or will be eliminated from the ongoing operations of the entity and (b) the types of continuing involvement that constitute significant continuing involvement in the operations of the disposal component. The Company considered the model outlined in EITF Issue No. 03-13 in its evaluation of the September 2004 sale of the Canadian and Rockies oil and gas reserves (see Note 10 for more information). The final consensus did not change the Company’s original conclusions reached under the existing discontinued operations guidance in SFAS No. 144.

| EITF Issue No. 03-06

In March 2004, the EITF reached a final consensus on EITF Issue No. 03-06, “Participating Securities and the Two — Class Method under FASB Statement No. 128, Earnings per Share,” (“EITF Issue No. 03-06”) effective for reporting period beginning after March 31, 2004. EITF Issue No. 03-06 clarifies the

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
definition of a participating security under SFAS No. 128 and how to apply the two-class method of computing EPS once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. Prior to the issuance of EITF Issue No. 03-06, the Company had issued certain convertible debt instruments with features that may have been considered participating under SFAS No. 128. However, under the clarifying guidance of EITF Issue No. 03-06, none of these features created a “participating security.” Adoption of this pronouncement did not impact the Company’s current or historical reported EPS amounts.

| EITF Issue No. 04-10

In October 2004, FASB ratified EITF Issue No. 04-10, “Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds” (“EITF Issue No. 04-10”). This issue addresses how an entity should evaluate the aggregation criteria in paragraph 17 of SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information” (“SFAS No. 131”) when determining whether operating segments that do not meet the quantitative thresholds may be aggregated in accordance with paragraph 19 of SFAS No. 131. The Task Force reached a consensus that operating segments must always have similar economic characteristics and meet a majority of the remaining five aggregation criteria, items (a)-(e), listed in paragraph 17, in order to be aggregated under paragraph 19. The consensus was originally effective for reporting periods ending December 31, 2004, with the corresponding information for earlier periods, including interim periods, restated unless it is impractical to do so. At the November 2004 EITF meeting, the Task Force delayed the effective date of this Issue to coincide with the effective date of the anticipated FASB Staff Position on the meaning of “similar economic characteristics.” EITF Issue No. 04-10 is not expected to impact the Company’s current approach to segment reporting or its historically reported segment results.

| SFAS No. 123-R

In December 2004, FASB issued SFAS No. 123 (revised 2004) (“SFAS No. 123-R”), “Share Based Payments.” This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”) and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB Opinion No. 25”), and its related implementation guidance. This statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions), which must be recognized over the period during which an employee is required to provide service in exchange for the award — the requisite service period (usually the vesting period). The statement applies to all share-based payment transactions in which an entity acquires goods or services by issuing (or offering to issue) its shares, share options, or other equity instruments or by incurring liabilities to an employee or other supplier (a) in amounts based, at least in part, on the price of the entity’s shares or other equity instruments or (b) that require or may require settlement by issuing the entity’s equity shares or other equity instruments.
The statement requires the accounting for any excess tax benefits to be consistent with the existing guidance under SFAS No. 123, which provides a two-transaction model summarized as follows:

| • | If settlement of an award creates a tax deduction that exceeds compensation cost, the additional tax benefit would be recorded as a contribution to paid-in-capital.
| • | If the compensation cost exceeds the actual tax deduction, the write-off of the unrealized excess tax benefits would first reduce any available paid-in capital arising from prior excess tax benefits, and any remaining amount would be charged against the tax provision in the income statement.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company is still evaluating the impact of adopting and subsequently accounting for excess tax benefits under the two-transaction model described in SFAS No. 123, but does not expect its consolidated net income or financial position to be materially affected upon adoption of SFAS No. 123-R.
The statement also amends SFAS No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash inflow rather than as an operating cash inflow. However, the statement does not change the accounting guidance for share-based payment transactions with parties other than employees provided in SFAS No. 123 as originally issued and EITF Issue No. 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.” Further, this statement does not address the accounting for employee share ownership plans, which are subject to AICPA Statement of Position 93-6, “Employers’ Accounting for Employee Stock Ownership Plans.”
The statement applies to all awards granted, modified, repurchased, or cancelled after July 1, 2005, and to the unvested portion of all awards granted prior to that date. Public entities that used the fair-value-based method for either recognition or disclosure under SFAS No. 123 may adopt this Statement using a modified version of prospective application (modified prospective application). Under modified prospective application, compensation cost for the portion of awards for which the employee’s requisite service has not been rendered that are outstanding as of July 1, 2005 must be recognized as the requisite service is rendered on or after that date. The compensation cost for that portion of awards shall be based on the original grant-date fair value of those awards as calculated for recognition under SFAS No. 123. The compensation cost for those earlier awards shall be attributed to periods beginning on or after July 1, 2005 using the attribution method that was used under SFAS No. 123. Furthermore, the method of recognizing forfeitures must now be based on an estimated forfeiture rate and can no longer be based on forfeitures as they occur.
Adoption of SFAS No. 123-R is not expected to materially impact the Company’s consolidated results of operations, cash flows or financial position, due to the Company’s prior adoption of SFAS No. 123 as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” (“SFAS No. 148”) on January 1, 2003. SFAS No. 148 allowed companies to adopt the fair-value-based method for recognition of compensation expense under SFAS No. 123 using prospective application. Under that transition method, compensation expense was recognized in the Company’s Consolidated Statement of Operations only for stock-based compensation granted after the adoption date of January 1, 2003. Furthermore, as we have chosen the multiple option approach in recognizing compensation expense associated with the fair value of each option granted, nearly 80% of the total fair value of the stock option is recognized by the end of the second year of the vesting period, and therefore remaining compensation expense associated with options granted before January 1, 2003, is expected to be immaterial.

| SFAS No. 151

In November 2004, FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4” (“SFAS No. 151”). This Statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). Paragraph 5 of ARB 43, Chapter 4, previously stated that “. . . under some circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current period charges. . . .” This Statement requires those items to be recognized as a current-period charge regardless of whether they meet the criterion of “so abnormal.” In addition, this Statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The provisions of SFAS No. 151 are applicable to inventory costs incurred during fiscal years beginning after June 15, 2005. Adoption of this statement is not expected to materially impact the Company’s consolidated results of operations, cash flows or financial position.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| SFAS No. 153

In December 2004, FASB issued SFAS No. 153 (“SFAS No. 153”), “Exchanges of Nonmonetary Assets.” This standard eliminates the exception in APB Opinion No. 29, “Accounting for Nonmonetary Transactions” (“APB Opinion No. 29”) for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. It requires exchanges of productive assets to be accounted for at fair value, rather than at carryover basis, unless (1) neither the asset received nor the asset surrendered has a fair value that is determinable within reasonable limits or (2) the transaction lacks commercial substance (as defined). A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange.
The new standard will not apply to the transfers of interests in assets in exchange for an interest in a joint venture and amends SFAS No. 66, “Accounting for Sales of Real Estate” (“SFAS No. 66”), to clarify that exchanges of real estate for real estate should be accounted for under APB Opinion No. 29. It also amends SFAS No. 140, to remove the existing scope exception relating to exchanges of equity method investments for similar productive assets to clarify that such exchanges are within the scope of SFAS No. 140 and not APB Opinion No. 29. SFAS No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Adoption of this statement is not expected to materially impact the Company’s consolidated results of operations, cash flows or financial position.

3. | Available-for-Sale Debt Securities

| Collateral Debt Securities

At December 31, 2003, the Company owned held-to-maturity debt securities that were pledged as collateral to support the King City operating lease and that matured serially in amounts equal to a portion of the semi-annual lease payments. At December 31, 2003, the amortized cost of these securities was $82.6 million, which represented the book value of the instruments when the Company accounted for the securities as held-to-maturity. In the first quarter of 2004, the Company reclassified the securities that served as collateral under the original lease from held-to-maturity to available-for-sale in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (“SFAS No. 115”). As a result of the reclassification from held-to-maturity to available-for-sale, the Company accounted for these securities at fair value for the duration of 2004 until the instruments were liquidated. On May 19, 2004, the Company restructured the King City operating lease. See Note 13 for more information regarding the King City restructuring. At the close of the restructuring transaction, the Company sold the securities for total proceeds of $95.4 million and recorded a pre-tax gain of $12.3 million in the Other Income. Also, in contemplation of the sale, the Company entered into an interest rate swap with a financial institution with the intent to hedge against a decline in value of the collateral debt securities. The swap did not meet the required criteria for hedge effectiveness under SFAS No. 133 and, as a result, the Company recorded all changes in the swap’s fair value between the dates of inception and settlement in the Other Income. Upon settlement of the swap, the Company had recognized a cumulative gain of $5.2 million, which was also recorded in the Other Income.

| HIGH TIDES Securities Held

Between September 2003 and July 2004, the Company exchanged approximately 15.0 million shares of Calpine common stock in privately negotiated transactions for approximately $77.5 million par value of HIGH TIDES I and 15.8 million shares of Calpine common stock in privately negotiated transactions for approximately $75.0 million par value of HIGH TIDES II. On October 20, 2004, the Company repaid the convertible subordinate debentures held by Trust I and Trust II, which used those proceeds to redeem the outstanding 53/4% convertible preferred securities (“HIGH TIDES I”) issued by Trust I, and 51/2% convertible

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
preferred securities (“HIGH TIDES II”) issued by Trust II. The redemption price paid per each $50 principal amount of such convertible preferred securities was $50 plus accrued and unpaid distributions to the redemption date in the amount of $0.6309 per unit with respect to the convertible preferred securities issued by Trust I and $0.6035 per unit with respect to the convertible preferred securities issued by Trust II. See Note 12 for further information on the convertible subordinate debentures. The redemption of the HIGH TIDES I and HIGH TIDES II available-for-sale securities previously purchased and held by the Company resulted in a realized gain of approximately $6.1 million. Calpine intends to cause both Trusts, which are related parties, to be terminated.
On September 30, 2004, the Company repurchased par value of $115.0 million HIGH TIDES III for cash of $111.6 million. Due to the deconsolidation of the Trusts upon the adoption of FIN 46 as of December 31, 2003, and the terms of the underlying debentures, the repurchased HIGH TIDES III preferred securities could not be offset against the convertible subordinated debentures and are accounted for as available for sale securities and recorded in Other Assets at fair market value at December 31, 2004, with the difference from their repurchase price recorded in OCI (in thousands):

|  | December 31, 2004 |
|  |  |  | Gross Unrealized |  |  |
|  |  |  | Gains in Other |  |  | Realized |  |  |
|  | Repurchase |  |  | Comprehensive |  |  | Gains on |  |  |
|  | Price(1) |  |  | Income/ (Loss) |  |  | Redemption |  |  | Redemptions |  |  | Fair Value |
HIGH TIDES I |  | $ | 75,020 |  |  | $ | — |  |  | $ | 2,480 |  |  | $ | (77,500 | ) |  | $ | — |
HIGH TIDES II |  |  | 71,341 |  |  |  | — |  |  |  | 3,659 |  |  |  | (75,000 | ) |  |  | — |
HIGH TIDES III |  |  | 110,592 |  |  |  | 958 |  |  |  | — |  |  |  | — |  |  | $ | 111,550 |
|  |  |  |  |  | $ | 958 |  |  | $ | 6,139 |  |  | $ | (152,500 | ) |  | $ | 111,550 |

(1) | The repurchase price is shown net of accrued interest. The repurchased amount for HIGH TIDES I was $75.4 million less $0.4 million of accrued interest. The repurchased amount for HIGH TIDES II was $72.0 million less $0.7 million of accrued interest. The repurchased amount for HIGH TIDES III was $111.6 million less $1 million of accrued interest.

4. Property, Plant and Equipment, Net, and Capitalized Interest
As of December 31, 2004 and 2003, the components of property, plant and equipment, are stated at cost less accumulated depreciation and depletion as follows (in thousands):

|  | 2004 |  |  | 2003 |
Buildings, machinery, and equipment |  | $ | 16,449,029 |  |  | $ | 13,137,550 |
Oil and gas properties, including pipelines |  |  | 1,189,626 |  |  |  | 1,176,796 |
Geothermal properties |  |  | 474,869 |  |  |  | 460,602 |
Other |  |  | 218,177 |  |  |  | 234,758 |
|  |  | 18,331,701 |  |  |  | 15,009,706 |
Less: Accumulated depreciation and depletion |  |  | (2,122,371 | ) |  |  | (1,388,225 | )
|  |  | 16,209,330 |  |  |  | 13,621,481 |
Land |  |  | 105,087 |  |  |  | 95,037 |
Construction in progress |  |  | 4,321,977 |  |  |  | 5,762,132 |
Property, plant and equipment, net |  | $ | 20,636,394 |  |  | $ | 19,478,650 |

Total depreciation and depletion expense for the years ended December 31, 2004, 2003 and 2002 was $593.1 million, $522.8 million and $402.4 million, respectively.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company has various debt instruments that are secured by certain of its property, plant and equipment. See Notes 11-18 for a detailed discussion of such instruments.

| Buildings, Machinery, and Equipment

This component primarily includes electric power plants and related equipment. Depreciation is recorded utilizing the straight-line method over the estimated original composite useful life, generally 35 years for baseload power plants, exclusive of the estimated salvage value, typically 10%. Peaking facilities are generally depreciated over 40 years, less the estimated salvage value of 10%. The Company capitalizes costs for major turbine generator refurbishments for the “hot gas path section” and compressor components, which include such significant items as combustor parts (e.g. fuel nozzles, transition pieces, and “baskets”) compressor blades, vanes and diaphragms. These refurbishments are done either under long term service agreements by the original equipment manufacturer or by Calpine’s Turbine Maintenance Group. The capitalized costs are depreciated over their estimated useful lives ranging from 2 to 14 years. At December 31, 2004, the weighted average life was approximately 6 years. The Company expenses annual planned maintenance. Included in buildings, machinery and equipment are assets under capital leases. See Note 13 for more information regarding these assets under capital leases. Certain capital improvements associated with leased facilities may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement.

| Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and natural gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful. The provision for depreciation, depletion, and amortization is based on the capitalized costs as determined above, plus future abandonment costs net of salvage value, using the units of production method with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.
The Company assesses the impairment for oil and gas properties periodically (at least annually) to determine if impairment of such properties is necessary. Management utilizes its year-end reserve report prepared by a licensed independent petroleum engineering firm and related market factors to estimate the future cash flows for all proved developed (producing and non-producing) and proved undeveloped reserves. Property impairments may occur if a field discovers lower than anticipated reserves, reservoirs produce below original estimates or if commodity prices fall below a level that significantly affects anticipated future cash flows on the property. Proved oil and gas property values are reviewed when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value based on proved reserves and other market factors. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charges to expense in the current period. As a result of decreases in proved undeveloped reserves located in South Texas and proved developed non-producing reserves in Offshore Gulf of Mexico, a non-cash impairment charge of approximately $202.1 was recorded for the year ended December 31, 2004, to the “Oil and gas impairment” line of the Consolidated Statement of Operations. For the years ended December 31, 2003 and 2002, the impairment charge recorded to the same line item was $2.9 million and $3.4 million, respectively. These charges related exclusively to the Oil and Gas Production and Marketing segment.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| Geothermal Properties

The Company capitalizes costs incurred in connection with the development of geothermal properties, including costs of drilling wells and overhead directly related to development activities as well as costs of production equipment, the related facilities and the operating power plants. Proceeds from the sale of geothermal properties are applied against capitalized costs, with no gain or loss recognized.
Geothermal costs, including an estimate of future costs to be incurred, costs to optimize the productivity of the assets, and the estimated costs to dismantle, are amortized by the units of production method based on the estimated total productive output over the estimated useful lives of the related steam fields. Depreciation of the buildings and roads is computed using the straight-line method over their estimated useful lives. It is reasonably possible that the estimate of useful lives, total unit-of-production or total capital costs to be amortized using the units-of-production method could differ materially in the near term from the amounts assumed in arriving at current depreciation expense. These estimates are affected by such factors as the ability of the Company to continue selling electricity to customers at estimated prices, changes in prices of alternative sources of energy such as hydro-generation and gas, and changes in the regulatory environment. Geothermal steam turbine generator refurbishments are expensed as incurred.

| Other

This component primarily includes software and emission reduction credits (“ERCs”). Software is amortized over its estimated useful life, generally 3 to 5 years. The Company holds ERCs that must generally be acquired during the permitting process for power plants in construction. ERCs are related to reductions in environmental emissions that result from some action like increasing energy efficiency, and are measured and registered in a way so that they can be bought, sold, and traded. The lives of the ERCs are usually consistent with the life of the related plant. The gross ERC balance recorded in property, plant and equipment and included in “Other” above was $103.6 million and $104.8 million as of December 31, 2004 and 2003, respectively. Of this balance $21.3 million and $21.3 million related to plants in operation as of December 31, 2004 and 2003, respectively. The depreciation expense recorded in 2004, 2003 and 2002, related to ERCs was $0.5 million, $0.5 million and $0.4 million, respectively.

| Construction in Progress

CIP is primarily attributable to gas-fired power projects under construction including prepayments on gas and steam turbine generators and other long lead-time items of equipment for certain development projects not yet in construction. Upon commencement of plant operation, these costs are transferred to the applicable property category, generally buildings, machinery and equipment.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| Capital Spending — Development and Construction

Construction and development costs in process consisted of the following at December 31, 2004 (in thousands):

|  |  |  |  |  | Equipment |  |  | Project |  |  |
|  | # of |  |  |  |  | Included in |  |  | Development |  |  | Unassigned |
|  | Projects |  |  | CIP |  |  | CIP |  |  | Costs |  |  | Equipment |
Projects in construction(1) |  |  | 10 |  |  | $ | 3,194,530 |  |  | $ | 1,094,490 |  |  | $ | — |  |  | $ | — |
Projects in advanced development |  |  | 10 |  |  |  | 670,806 |  |  |  | 520,036 |  |  |  | 102,829 |  |  |  | — |
Projects in suspended development |  |  | 6 |  |  |  | 421,547 |  |  |  | 168,985 |  |  |  | 38,398 |  |  |  | — |
Projects in early development |  |  | 2 |  |  |  | — |  |  |  | — |  |  |  | 8,952 |  |  |  | — |
Other capital projects |  |  | NA |  |  |  | 35,094 |  |  |  | — |  |  |  | — |  |  |  | — |
Unassigned equipment |  |  | NA |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 66,073 |
Total construction and development costs |  |  |  |  |  | $ | 4,321,977 |  |  | $ | 1,783,511 |  |  | $ | 150,179 |  |  | $ | 66,073 |

(1) | The Company has a total of 11 projects in construction. This includes the 10 projects above that are recorded in CIP and 1 project that is recorded in investments in power projects. Construction activities and the capitalization of interest on one of the construction projects has been suspended or delayed due to current market conditions. The CIP balance on this project was $461.5 million as of December 31, 2004. Subsequent to December 31, 2004, construction activities and the capitalization of interest on two additional construction projects was suspended or delayed. Total CIP on these two projects was $683.0 million as of December 31, 2004.

Projects in Construction — The 10 projects in construction are projected to come on line from March 2005 to November 2007 or later. These projects will bring on line approximately 4,656 MW of base load capacity (5,264 MW with peaking capacity). Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized, unless work has been suspended, in which case capitalization of interest expense is suspended until active construction resumes. At December 31, 2004, the estimated funding requirements to complete these projects, net of expected project financing proceeds, is approximately $84.6 million.
Projects in Advanced Development — There are an additional 10 projects in advanced development. These projects will bring on line approximately 5,307 MW of base load capacity (6,095 MW with peaking capacity). Interest and other costs related to the development activities necessary to bring these projects to their intended use are being capitalized. However, the capitalization of interest has been suspended on 2 projects for which development activities are substantially complete but construction will not commence until a PPA and financing are obtained. The estimated cost to complete the 10 projects in advanced development is approximately $3.0 billion. The Company’s current plan is to finance these project costs as PPAs are arranged.
Suspended Development Projects — Due to current electric market conditions, we have ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met indicating that it is again highly probable that the costs will be recovered through future operations. As is true for all projects, the suspended projects are reviewed for impairment whenever there is an indication of potential reduction in a project’s fair value. Further, if it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to their recoverable value. These projects would bring on line approximately 2,956 MW of base load capacity (3,409 MW with peaking capacity). The estimated cost to complete these projects is approximately $1.8 billion.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Projects in Early Development — Costs for projects that are in early stages of development are capitalized only when it is highly probable that such costs are ultimately recoverable and significant project milestones are achieved. Until then all costs, including interest costs, are expensed. The projects in early development with capitalized costs relate to two projects and include geothermal drilling costs and equipment purchases.
Other Capital Projects — Other capital projects primarily consist of enhancements to operating power plants, oil and gas and geothermal resource and facilities development, as well as software developed for internal use.
Unassigned Equipment — As of December 31, 2004, the Company had made progress payments on 4 turbines and other equipment with an aggregate carrying value of $66.1 million. This unassigned equipment is classified on the balance sheet as other assets because it is not assigned to specific development and construction projects. The Company is holding this equipment for potential use on future projects. It is possible that some of this unassigned equipment may eventually be sold, potentially in combination with the Company’s engineering and construction services. For equipment that is not assigned to development or construction projects, interest is not capitalized.
Capitalized Interest — The Company capitalizes interest on capital invested in projects during the advanced stages of development and the construction period in accordance with SFAS No. 34, “Capitalization of Interest Cost,” (“SFAS No. 34”) as amended by SFAS No. 58, “Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34).” The Company’s qualifying assets include CIP, certain oil and gas properties under development, construction costs related to unconsolidated investments in power projects under construction, advanced stage development costs, as well as such above mentioned assets classified as held for sale. For the years ended December 31, 2004, 2003 and 2002, the total amount of interest capitalized was $376.1 million, $444.5 million and $575.5 million, including $49.1 million, $66.0 million and $114.2 million, respectively, of interest incurred on funds borrowed for specific construction projects and $327.0 million, $378.5 million and $461.3 million, respectively of interest incurred on general corporate funds used for construction. Upon commencement of plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The decrease in the amount of interest capitalized during the year ended December 31, 2004 reflects the completion of construction for several power plants, the suspension of certain of the Company’s development and construction projects, and a reduction in the Company’s development and construction program in general.
In accordance with SFAS No. 34, the Company determines which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. The primary debt instruments included in the rate calculation of interest incurred on general corporate funds are the Company’s Senior Notes, the Company’s term loan facilities and the secured working capital revolving credit facility.
Impairment Evaluation — All construction and development projects and unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in fair value. Equipment assigned to such projects is not evaluated for impairment separately, as it is integral to the assumed future operations of the project to which it is assigned. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value in accordance with the provisions of SFAS No. 144. The Company reviews its unassigned equipment for potential impairment based on probability-weighted alternatives of utilizing the equipment for future projects versus selling the equipment. Utilizing this methodology, the Company does not believe that the equipment held for use is impaired. However, during the year ended December 31, 2004, the Company recorded to the “Equipment cancellation

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
and impairment cost” line of the Consolidated Statement of Operations $3.2 million in net losses in connection with equipment sales. During the year ended December 31 2003, the Company recorded to the same line $29.4 million in losses in connection with the sale of four turbines, and it may incur further losses should it decide to sell more unassigned equipment in the future.

| Asset Retirement Obligations

The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) on January 1, 2003. As required by the new rules, the Company recorded liabilities equal to the present value of expected future asset retirement obligations at January 1, 2003. The Company identified obligations related to operating gas-fired power plants, geothermal power plants and oil and gas properties. The liabilities are partially offset by increases in net assets recorded as if the provisions of SFAS No. 143 had been in effect at the date the obligation was incurred, which for power plants is generally the start of construction, typically building up during construction until commercial operations for the facility is achieved. For oil and gas properties the date the obligation is incurred is generally the start of drilling of a well or the start of construction of a facility, typically building up until completion of drilling a well or completion of construction of a facility.
The information below reconciles the values of the asset retirement obligation from the date the liability was recorded (in thousands):

Asset retirement obligation at January 1, 2003 |  | $ | 33,929 |
| Liabilities incurred |  |  | 4,311 |
| Liabilities settled |  |  | (1,397 | )
| Accretion expense |  |  | 3,842 |
| Revisions in the estimated cash flows |  |  | 1,799 |
| Other (primarily foreign currency translation) |  |  | (6,815 | )
Asset retirement obligation at December 31, 2003 |  | $ | 35,669 |
| Liabilities incurred |  |  | 4,207 |
| Liabilities settled |  |  | (1,279 | )
| Accretion expense |  |  | 6,430 |
| Revisions in the estimated cash flows |  |  | (329 | )
| Other (primarily foreign currency translation) |  |  | (2,350 | )
Asset retirement obligation at December 31, 2004 |  | $ | 42,348 |

5. | Goodwill and Other Intangible Assets

On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” (“SFAS No. 142”) which requires that all intangible assets with finite useful lives be amortized and that goodwill and intangible assets with indefinite lives not be amortized, but rather tested upon adoption and at least annually for impairment. The Company completed its annual goodwill impairment test as required under SFAS No. 142 and determined that the fair value of the reporting units with goodwill exceeded their net carrying values. Therefore, the Company’s goodwill asset was not impaired as of December 31, 2004. Subsequent goodwill impairment tests will be performed, at a minimum, in December of each year, in conjunction with the Company’s annual reporting process.
In accordance with the standard, the Company discontinued the amortization of its recorded goodwill as of January 1, 2002, identified reporting units based on its current segment reporting structure and allocated all

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
recorded goodwill, as well as other assets and liabilities, to the reporting units. The entire balance of goodwill was assigned to the PSM reporting unit, which is included in the Corporate, Other and Eliminations reporting segment as defined by SFAS No. 131. Recorded goodwill, by reporting segment, as of December 31, 2003, was (in thousands):

|  | 2004 |  |  | 2003 |
Electric Generation and Marketing |  | $ | — |  |  | $ | — |
Oil and Gas Production and Marketing |  |  | — |  |  |  | — |
Corporate, Other and Eliminations |  |  | 45,160 |  |  |  | 45,160 |
| Total |  | $ | 45,160 |  |  | $ | 45,160 |

The Company also reassessed the useful lives and the classification of its identifiable intangible assets and determined that they continue to be appropriate. The components of the amortizable intangible assets consist of the following (in thousands):

|  | Weighted |  |  | As of December 31, 2004 |  |  | As of December 31, 2003 |
|  | Average |  |  |  |  |  |  |
|  | Useful Life/ |  |  | Carrying |  |  | Accumulated |  |  | Carrying |  |  | Accumulated |
|  | Contract Life |  |  | Amount(1) |  |  | Amortization(1) |  |  | Amount(1) |  |  | Amortization(1) |
Patents |  |  | 5 |  |  | $ | 485 |  |  | $ | (417 | ) |  | $ | 485 |  |  | $ | (320 | )
Power sales agreements |  |  | 23 |  |  |  | 85,099 |  |  |  | (43,115 | ) |  |  | 86,962 |  |  |  | (40,180 | )
Fuel supply and fuel management contracts |  |  | 23 |  |  |  | 5,000 |  |  |  | (1,826 | ) |  |  | 22,198 |  |  |  | (4,991 | )
Geothermal lease rights |  |  | 20 |  |  |  | 19,518 |  |  |  | (550 | ) |  |  | 19,518 |  |  |  | (450 | )
Steam purchase agreement |  |  | 14 |  |  |  | 6,223 |  |  |  | (1,456 | ) |  |  | 5,766 |  |  |  | (944 | )
Other |  |  | 15 |  |  |  | 4,755 |  |  |  | (526 | ) |  |  | 2,088 |  |  |  | (208 | )
| Total |  |  |  |  |  | $ | 121,080 |  |  | $ | (47,890 | ) |  | $ | 137,017 |  |  | $ | (47,093 | )

(1) | Fully amortized intangible assets are not included.

Amortization expense of Other Intangible Assets was $5.0 million, $5.3 million and $21.5 million, in 2004, 2003 and 2002, respectively. Assuming no future impairments of these assets or additions as the result of acquisitions, annual amortization expense will be $4.3 million in 2005, $4.2 million in 2006, $4.2 million in 2007, $4.2 million in 2008 and $3.9 million in 2009.

6. | Acquisitions

The Company seeks to acquire power generating facilities and certain oil and gas properties that provide significant potential for revenue, cash flow and earnings growth, and that provide the opportunity to enhance the operating efficiency of its plants. Acquisition activity is dependent on the availability of financing on attractive terms and the expectation of returns that meets the Company’s long-term requirements. The following material mergers and acquisitions were consummated during the years ended December 31, 2004 and 2003. There were no mergers or acquisitions consummated during the year ended December 31, 2002. For all business combinations, the results of operations of the acquired companies were incorporated into the Company’s Consolidated Financial Statements commencing on the date of acquisition.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2004 Acquisitions

| Calpine Cogeneration Company Transaction

On March 23, 2004, the Company completed the acquisition of the remaining 20% interest in Calpine Cogeneration Corporation (“Calpine Cogen”), which holds interests in six power facilities, from NRG Energy, Inc. (“NRG”) for approximately $2.5 million. The Company purchased its initial 80% interest in Calpine Cogen (formerly known as Cogeneration Corporation of America) from NRG in 1999. Prior to the acquisition, the Company consolidated the assets of Calpine Cogen in its financial statements and reflected the 20% interest held by NRG as a minority interest. NRG’s minority interest had a carrying value of approximately $37.5 million at the time of acquisition. The carrying value of the underlying assets was adjusted downward on a pro-rata basis for the difference between the purchase price and the carrying value of NRG’s minority interest. As a result of the current transaction, the Company now has a 100% interest in the Newark, Parlin, Morris and Pryor facilities, an 83% interest in the Philadelphia Water Project, and a 50% interest in the Grays Ferry Power Plant.

| Aries Transaction

On March 26, 2004, the Company acquired the remaining 50% interest in the Aries facility from a subsidiary of Aquila, Inc. (Aquila and its subsidiaries referred to collectively as “Aquila”). At the same time, Aries terminated a tolling contract with another subsidiary of Aquila. Aquila paid $5 million in cash and assigned certain transmission and other rights to the Company. Aquila and the Company also amended a master netting agreement between them, and as a result, the Company returned cash margin deposits totaling $10.8 million to Aquila. Contemporaneous with the closing of the acquisition, Aries’ existing construction loan was converted to two term loans totaling $178.8 million. The Company contributed $15 million of equity to Aries in connection with the term out of the construction loan.
The amounts below represents 50% of the fair value of the assets acquired and liabilities assumed in the transaction. These amounts together with 50% of the investment owned by the Company prior to the acquisition are now fully consolidated into the Company’s financial statements.

Current assets |  | $ | 1,028 |
Contracts |  |  | 2,505 |
Property, plant and equipment |  |  | 100,793 |
Other assets |  |  | 1,902 |
Current liabilities |  |  | (1,978 | )
Derivative liability |  |  | (16,022 |
Long-term debt |  | $ | (88,228 | )

| Brazos Valley Power Plant Transaction

On March 31, 2004, the Company closed on the purchase of the 570-megawatt, natural gas-fired, Brazos Valley Power Plant (“Brazos Valley”) in Fort Bend County, Texas, for total consideration of approximately $181.1 million. The Company used the net proceeds from the sale of its undivided interest in the Lost Pines 1 facility (in January 2004) and cash on hand to acquire this facility in a transaction structured as a tax deferred like-kind exchange under IRS Section 1031. The consortium of banks that had provided construction financing for the power plant and had taken possession of the plant from the original developer in 2003 indirectly owned the special purpose companies that owned Brazos Valley. Brazos Valley has become part of the collateral package for the Calpine Construction Finance Company, L.P. (“CCFC I”) First Priority Secured Institutional Term Loans Due 2009 and Second Priority Senior Secured Floating Rate Notes Due

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2011. The fair value of the Brazos Valley facility was equal to the purchase price and as a result, the entire purchase price was allocated to the power plant assets and is recorded in property plant and equipment in the Company’s consolidated balance sheet.
2003 Acquisition

| Thomassen Turbine Systems Transaction

On February 26, 2003, the Company, through its wholly-owned subsidiary Calpine European Finance, LLC, purchased 100% of the outstanding stock of Babcock Borsig Power Turbine Services (“BBPTS”) from its parent company, Babcock Borsig. Immediately following the acquisition, the BBPTS name was changed to Thomassen Turbine Systems B.V. (“TTS”). The Company’s total cost of the acquisition was $12.0 million and was comprised of two pieces. The first was a $7.0 million cash payment to Babcock Borsig to acquire the outstanding stock of TTS. Included in this payment was the right to a note receivable valued at 11.9 million Euro (approximately US$12.9 million on the acquisition date) due from TTS, which the Company acquired from Babcock Borsig for $1. Additionally, as of the date of the acquisition, TTS owed $5.0 million in payments to another of the Company’s wholly owned subsidiaries, PSM, under a pre-existing license agreement. Because of the acquisition, TTS ceased to exist as a third party debtor to the Company, thereby resulting in a reduction of third party receivables of $5.0 million from the Company’s consolidated perspective.

| Pro Forma Effects of Acquisitions

Acquired subsidiaries are consolidated upon closing date of the acquisition. The table below reflects the Company’s unaudited pro forma combined results of operations for all business combinations during 2004 and 2003, as if the acquisitions had taken place at the beginning of fiscal year 2002. The Company’s combined results include the effects of Calpine Cogen, Aries, Brazos Valley and TTS (in thousands, except per share amounts):

|  | 2004 |  |  | 2003 |  |  | 2002 |
Total revenue |  | $ | 9,254,727 |  |  | $ | 8,958,416 |  |  | $ | 7,408,668 |
Income (loss) before discontinued operations and cumulative effect of accounting changes |  | $ | (448,541 | ) |  | $ | 70,831 |  |  | $ | 28,562 |
Net income (loss) |  | $ | (250,176 | ) |  | $ | 266,743 |  |  | $ | 120,458 |
Net income (loss) per basic share |  | $ | (0.58 | ) |  | $ | 0.68 |  |  | $ | 0.34 |
Net income (loss) per diluted share |  | $ | (0.58 | ) |  | $ | 0.67 |  |  | $ | 0.33 |

In management’s opinion, these unaudited pro forma amounts are not necessarily indicative of what the actual combined results of operations might have been if the 2004 and 2003 acquisitions had been effective at the beginning of fiscal year 2002. In addition, they are not intended to be a projection of future results and do not reflect all the synergies that might be achieved from combined operations.

7. | Investments in Power Projects and Oil and Gas Properties

The Company’s investments in power projects and oil and gas properties are integral to its operations. As discussed in Note 2, the Company’s joint venture investments were evaluated under FIN 46-R to determine which, if any, entities were VIEs. Based on this evaluation, the Company determined that the Acadia Power Partners, LLC, Valladolid III Energy Center, Grays Ferry Power Plant, Whitby Cogeneration facility and the Androscoggin Energy Center were VIEs, in which the Company held a significant variable interest. However, all of the entities except for Acadia Power Partners, LLC met the definition of a business and qualified for the business scope exception provided in paragraph 4(h) of FIN 46-R, and consequently were not subject to the VIE consolidated model. Further, based on a qualitative and quantitative assessment of the expected

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
variability in Acadia Power Partners, LLC, the Company was not the Primary Beneficiary. Consequently, the Company continues to account for its joint venture investments in power projects in accordance with APB Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FIN 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18).” However, in the fourth quarter of 2004, the Company changed from the equity method to the cost method to account for its investment in Androscoggin as discussed below.
Acadia Power Partners, LLC (“Acadia”) is the owner of a 1,210-megawatt electric wholesale generation facility located in Louisiana and is a joint venture between the Company and Cleco Corporation. The Company’s involvement in this VIE began upon formation of the entity in March 2000. The Company’s maximum potential exposure to loss at December 31, 2004, is limited to the book value of its investment of approximately $214.5 million.
Valladolid III Energy Center is the owner of a 525-megawatt, natural gas-fired energy center currently under construction for Comision Federal de Electricidad (“CFE”) at Valladolid, Mexico in the Yucatan Peninsula. The facility will deliver electricity to CFE under a 25-year power sales agreement. The project is a joint venture between the Company, Mitsui & Co., Ltd., (“Mitsui”) and Chubu Electric (“Chubu”), both headquartered in Japan. The Company owns 45% of the entity while Mitsui and Chubu each own 27.5%. Construction began in May 2004 and the project is expected to achieve commercial operation in the summer of 2006. The Company’s maximum potential exposure to loss at December 31, 2004, is limited to the book value of its investment of approximately $77.4 million.
Grays Ferry Cogeneration Partnership (“Grays Ferry”) is the owner of a 175-megawatt gas-fired cogeneration facility located in Pennsylvania and is a joint venture between the Company and Trigen-Schuylkill Cogeneration, Inc. The Company’s involvement in this VIE began with its acquisition of the independent power producer, Cogeneration Corporation of America, Inc. (“Cogen America”), now called Calpine Cogen, in December 1999. The Grays Ferry joint venture project was part of the portfolio of assets owned by Cogen America. The Company’s maximum potential exposure to loss at December 31, 2004, is limited to the book value of its investment of approximately $48.6 million.
Whitby Cogeneration Limited Partnership (“Whitby”) is the owner of a 50-megawatt gas-fired cogeneration facility located in Ontario, Canada and is a joint venture between the Company and a privately held enterprise. The Company’s involvement in this VIE began with its acquisition of a portfolio of assets from Westcoast Energy Inc. (“Westcoast”) in September 2001, which included the Whitby joint venture project. The Company’s maximum potential exposure to loss at December 31, 2004, is limited to the book value of its investment of approximately $32.5 million.
Androscoggin Energy LLC (“AELLC”) is the owner of a 136-megawatt gas-fired cogeneration facility located in Maine and is a joint venture between the Company, and affiliates of Wisvest Corporation and International Paper Company (“IP”). The Company’s involvement in this VIE began with its acquisition of the independent power producer, SkyGen Energy LLC (“SkyGen”) in October 2000. Androscoggin Energy LLC project was part of the portfolio of assets owned by SkyGen. The facility had construction debt of $60.3 million and $60.8 million outstanding as of December 31, 2004 and 2003, respectively. The debt is non-recourse to Calpine Corporation. On November 3, 2004, a jury verdict was rendered against AELLC in a breach of contract dispute with IP. See Note 25 for more information about the legal proceeding. The Company recorded its $11.6 million share of the award amount in the third quarter of 2004. On November 26, 2004, AELLC filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. As a result of the bankruptcy, the Company has lost significant influence and control of the project and has adopted the cost method of accounting for its investment in Androscoggin. Also, in December 2004 the Company determined that its investment, in Androscoggin including outstanding notes receivable and O&M receivable, was impaired and recorded a $5.0 million impairment reserve.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following investments are accounted for under the equity method except for Androscoggin Energy Center which is accounted for under the cost method (in thousands):

|  | Ownership |  |  | Investment Balance at |
|  | Interest as of |  |  | December 31, |
|  | December 31, |  |  |  |
|  | 2004 |  |  | 2004 |  |  | 2003 |
Acadia Energy Center(1) |  |  | 50.0 | % |  | $ | 214,501 |  |  | $ | 221,038 |
Valladolid III Energy Center |  |  | 45.0 | % |  |  | 77,401 |  |  |  | 67,320 |
Grays Ferry Power Plant |  |  | 50.0 | % |  |  | 48,558 |  |  |  | 53,272 |
Whitby Cogeneration(2) |  |  | 15.0 | % |  |  | 32,528 |  |  |  | 31,033 |
Aries Power Plant(3) |  |  | 100.0 | % |  |  | — |  |  |  | 58,205 |
Androscoggin Energy Center(4) |  |  | 32.3 | % |  |  | — |  |  |  | 11,823 |
Other |  |  | — |  |  |  | 1,044 |  |  |  | 1,459 |
| Total investments in power projects and oil and gas properties |  |  |  |  |  | $ | 374,032 |  |  | $ | 444,150 |

(1) | On May 12, 2003, the Company completed the restructuring of its interest in Acadia. As part of the transaction, the partnership terminated its 580-megawatt, 20-year tolling arrangement with a subsidiary of Aquila, Inc. in return for a cash payment of $105.5 million. Acadia recorded a gain of $105.5 million and then made a $105.5 million distribution to Calpine. Contemporaneously, the Company’s wholly owned subsidiary, CES, entered into a new 20-year, 580-megawatt tolling contract with Acadia. CES now markets all of the output from the Acadia Power Project under the terms of this new contract and an existing 20-year tolling agreement. Cleco receives a priority cash distributions as its consideration for the restructuring. Also, as a result of this transaction, the Company recorded, as its share of the termination payment from the Aquila subsidiary, a $52.8 million gain as of December 31, 2003, which was recorded within “Income from unconsolidated investments in power projects and oil and gas properties” in the Consolidated Statement of Operations. Due to the restructuring of its interest in Acadia, the Company was required to reconsider its investment in the entity under FIN 46 and determined that it is not the Primary Beneficiary and accordingly will continue to account for its investment using the equity method. See Note 2 for further information. See Note 25 for a legal proceeding involving Acadia Energy Center.
(2) | Whitby is owned 50% by the Company but a 70% economic share in the Company’s ownership interest has been effectively transferred to Calpine Power, Inc. (“CPI”) through a loan from CPI to the Company’s entity which holds the investment interest in Whitby.
(3) | On March 26, 2004, the Company acquired the remaining 50 percent interest in Aries Power Plant. See Note 6 for a discussion of the acquisition.
(4) | Excludes certain Notes Receivable (see Note 8).

On November 26, 2003, the Company completed the sale of its 50 percent interest in the Gordonsville Power Plant. Under the terms of the transaction, the Company received $36.2 million in cash for its $25.4 million investment and recorded a pre-tax gain of $7.1 million. The remaining cash of $0.6 million is to be distributed to the partners in late 2005.
On September 2, 2004, the Company completed the sale of its equity investment in the Calpine Natural Gas Trust (“CNGT”). In accordance with SFAS No. 144 the Company’s 25 percent equity method investment in the CNGT was considered part of the larger disposal group and therefore evaluated and accounted for as a discontinued operation. Accordingly, the Company made reclassifications to current and prior period financial statements to reflect the sale or designation as “held for sale” of the CNGT investment balance and to separately classify the income from the unconsolidated investment as well as the gain on sale of

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
the investment from operating results of continuing operations to discontinued operations. The tables below for distributions from investments and related party transactions with unconsolidated investments in power projects and oil and gas properties include CNGT through the date of sale, September 2, 2004. See Note 10 for more information on the sale of the Canadian natural gas reserves and petroleum assets.
The combined unaudited results of operations and financial position of the Company’s equity and cost method affiliates are summarized below (in thousands):

|  | December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |
Condensed statements of operations: |  |  |  |  |  |  |  |  |  |  |  |
| Revenue |  | $ | 240,527 |  |  | $ | 417,395 |  |  | $ | 372,212 |
| Gross profit |  |  | 47,339 |  |  |  | 147,782 |  |  |  | 151,784 |
| Income from continuing operations before extraordinary items and cumulative effect of a change in accounting principle |  |  | (7,951 | ) |  |  | 175,154 |  |  |  | 70,596 |
| Net income (loss) |  |  | (7,951 | ) |  |  | 175,154 |  |  |  | 70,596 |
Condensed balance sheets: |  |  |  |  |  |  |  |  |  |  |  |
| Current assets |  | $ | 67,928 |  |  | $ | 87,538 |  |  |  |  |
| Non-current assets |  |  | 903,681 |  |  |  | 1,474,607 |  |  |  |  |
| Total assets |  | $ | 971,609 |  |  | $ | 1,562,145 |  |  |  |  |
| Current liabilities |  | $ | 150,845 |  |  | $ | 91,051 |  |  |  |  |
| Non-current liabilities |  |  | 114,620 |  |  |  | 727,827 |  |  |  |  |
| Total liabilities |  | $ | 265,465 |  |  | $ | 818,878 |  |  |  |  |

The debt on the books of the unconsolidated investments is not reflected on the Company’s balance sheet. At December 31, 2004 and 2003, investee debt was approximately $126.3 million and $439.3 million, respectively. Of these amounts, $60.3 million and $60.8 million, respectively, relates to the Company’s investment in AELLC, for which the cost method of accounting was used as of December 31, 2004. Based on the Company’s pro rata ownership share of each of the investments, the Company’s share would be approximately $43.3 million and $140.8 million for the respective periods. These amounts include the Company’s share for AELLC of $19.5 million and $19.7 million, respectively. However, all such debt is non-recourse to the Company.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following details the Company’s income and distributions from investments in unconsolidated power projects and oil and gas properties (in thousands):

|  | Income (loss) from |  |  |  |  |  |  |
|  | Unconsolidated Investments |  |  |  |  |  |  |
|  | in Power Projects and |  |  |
|  | Oil and Gas Properties |  |  | Distributions |
|  | For the Years Ended December 31, |
|  | 2004 |  |  | 2003 |  |  | 2002 |  |  | 2004 |  |  | 2003 |  |  | 2002 |
Acadia Power Partners, LLC |  | $ | 14,142 |  |  | $ | 75,272 |  |  | $ | 14,590 |  |  | $ | 21,394 |  |  | $ | 136,977 |  |  | $ | 11,969 |
Valladolid III Energy Center |  |  | 76 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Grays Ferry Power Plant |  |  | (2,761 | ) |  |  | (1,380 | ) |  |  | (1,499 | ) |  |  | — |  |  |  | — |  |  |  | — |
Whitby Cogeneration |  |  | 1,433 |  |  |  | 303 |  |  |  | 411 |  |  |  | 1,499 |  |  |  | — |  |  |  | — |
Aries Power Plant |  |  | (4,264 | ) |  |  | (3,442 | ) |  |  | (43 | ) |  |  | — |  |  |  | — |  |  |  | — |
Calpine Natural Gas Trust |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6,127 |  |  |  | 1,959 |  |  |  | — |
Androscoggin Energy Center |  |  | (23,566 | ) |  |  | (7,478 | ) |  |  | (3,951 | ) |  |  | — |  |  |  | — |  |  |  |  |
Gordonsville Power Plant |  |  | — |  |  |  | 11,985 |  |  |  | 5,763 |  |  |  | — |  |  |  | 2,672 |  |  |  | 2,125 |
Lockport Power Plant |  |  | — |  |  |  | — |  |  |  | 1,570 |  |  |  | — |  |  |  | — |  |  |  | — |
Other |  |  | 575 |  |  |  | 79 |  |  |  | (351 | ) |  |  | 849 |  |  |  | 19 |  |  |  | 23 |
| Total |  | $ | (14,365 | ) |  | $ | 75,339 |  |  | $ | 16,490 |  |  | $ | 29,869 |  |  | $ | 141,627 |  |  | $ | 14,117 |
Interest income on loans to power projects(1) |  | $ | 840 |  |  | $ | 465 |  |  | $ | 62 |  |  |  |  |  |  |  |  |  |  |  |  |
| Total |  | $ | (13,525 | ) |  | $ | 75,804 |  |  | $ | 16,552 |  |  |  |  |  |  |  |  |  |  |  |  |

The Company provides for deferred taxes to the extent that distributions exceed earnings.

(1) | At December 31, 2004 and 2003, loans to power projects represented an outstanding loan to the Company’s 32.3% owned investment, AELLC, in the amounts of $4.0 million and $13.3 million, respectively, after impairment charges and reserves.

In the fourth quarter of 2002, income from unconsolidated investments in power projects and oil and gas properties was reclassified out of total revenue and is now presented as a component of other income from operations. Prior periods have also been reclassified accordingly.

| Related-Party Transactions with Unconsolidated Investments in Power Projects and Oil and Gas Properties

The Company and certain of its equity and cost method affiliates have entered into various service agreements with respect to power projects and oil and gas properties. Following is a general description of each of the various agreements:

| Operation and Maintenance Agreements — The Company operates and maintains the Acadia and Androscoggin Energy Centers. This includes routine maintenance, but not major maintenance, which is typically performed under agreements with the equipment manufacturers. Responsibilities include development of annual budgets and operating plans. Payments include reimbursement of costs, including Calpine’s internal personnel and other costs, and annual fixed fees.
| Construction Management Services Agreements — The Company provides construction management services to the Valladolid III Energy Center. Payments include reimbursement of costs, including the Company’s internal personnel and other costs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| Administrative Services Agreements — The Company handles administrative matters such as bookkeeping for certain unconsolidated investments. Payment is on a cost reimbursement basis, including Calpine’s internal costs, with no additional fee.
| Power Marketing Agreements — Under agreements with Androscoggin Energy LLC, CES can either market the plant’s power as the power facility’s agent or buy the power directly. Terms of any direct purchase are to be agreed upon at the time and incorporated into a transaction confirmation. Historically, CES has generally bought the power from the power facility rather than acting as its agent.
| Gas Supply Agreement — CES can be directed to supply gas to the Androscoggin Energy Center facility pursuant to transaction confirmations between the facility and CES. Contract terms are reflected in individual transaction confirmations.

The power marketing and gas supply contracts with CES are accounted for as either purchase and sale arrangements or as tolling arrangements. In a purchase and sale arrangement, title and risk of loss associated with the purchase of gas is transferred from CES to the project at the gas delivery point. In a tolling arrangement, title to fuel provided to the project does not transfer, and CES pays the project a capacity and a variable fee based on the specific terms of the power marketing and gas supply agreements. In addition to the contracts specified above, CES maintains two tolling agreements with the Acadia facility which are accounted for as leases. These tolling agreements expire in 2022. In accordance with the terms of the contracts, CES supplies all necessary fuel to generate the energy it takes and pays a capacity charge as well as an operations and maintenance fee to Acadia. The Company reflects 100% of the lease expense through CES, a consolidated subsidiary, and 50% of the lease revenue in equity in earnings of an unconsolidated subsidiary. The total future minimum lease payments for the tolling agreements are as follows (in thousands):

2005 |  | $ | 63,967 |
2006 |  |  | 63,967 |
2007 |  |  | 65,902 |
2008 |  |  | 67,836 |
2009 |  |  | 67,836 |
Thereafter |  |  | 847,952 |
| Total |  | $ | 1,177,460 |

All of the other power marketing and gas supply contracts are accounted for as purchases and sales.
The related party balances as of December 31, 2004 and 2003, reflected in the accompanying consolidated balance sheets, and the related party transactions for the years ended December 31, 2004, 2003 and 2002, reflected in the accompanying consolidated statements of operations are summarized as follows (in thousands):

|  | 2004 |  |  | 2003 |
As of December 31, |  |  |  |  |  |  |  |
Accounts receivable |  | $ | 765 |  |  | $ | 1,156 |
Accounts payable |  |  | 9,489 |  |  |  | 12,172 |
Interest receivable |  |  | — |  |  |  | 2,074 |
Note Receivable |  |  | 4,037 |  |  |  | 13,262 |
Other receivables |  |  | — |  |  |  | 8,794 |

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

|  | 2004 |  |  | 2003 |  |  | 2002 |
For the Years Ended December 31, |  |  |  |  |  |  |  |  |  |  |  |
Revenue |  | $ | 1,241 |  |  | $ | 3,493 |  |  | $ | 4,729 |
Cost of Revenue |  |  | 115,008 |  |  |  | 82,205 |  |  |  | 36,290 |
Interest income |  |  | 840 |  |  |  | 1,117 |  |  |  | 132 |
Gain on sale of assets |  |  | 6,240 |  |  |  | 62,176 |  |  |  | — |

8. | Notes Receivable

Generally, notes receivable are recorded at the face amount, net of allowances. These notes bear interest at rates that approximate current market interest rates at the time of issuance. Certain long-term notes receivable have no stated rate and are recorded by discounting expected future cash flows using then current interest rates at which similar loans would be made to borrowers with similar credit ratings and remaining maturities. The Company intends to hold these notes to maturity. The amortization of the discount is recognized as interest income, using the effective interest method, over the repayment term of the notes. The Company reviews the financial condition of customers prior to granting credit. The allowance represents the Company’s best estimate of the amount of probable credit losses in the Company’s existing notes receivable. The Company determines the allowance based on a variety of factors, including economic trends and conditions and significant one-time events affecting the note issuer, the length of time principal and interest payments are past due and historical write off experience. Also, specific provisions are recorded for individual notes receivables when the Company becomes aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. The Company reviews the adequacy of its notes receivable allowance quarterly. Generally, individual past due amounts are reviewed for collectibility. Interest income is reserved when amounts are more than 90 days past due or sooner if circumstances indicated that recoverability is not reasonably assured. Past due amounts are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.
As of December 31, 2004, and 2003, the components of notes receivable were (in thousands):

|  | 2004 |  |  | 2003 |
PG&E (Gilroy) note |  | $ | 145,853 |  |  | $ | 155,901 |
Panda note |  |  | 38,644 |  |  |  | 38,644 |
Eastman note |  |  | 19,748 |  |  |  | — |
Androscoggin note |  |  | 4,037 |  |  |  | 13,262 |
Mitsui & Co., Ltd note |  |  | — |  |  |  | 8,779 |
Other |  |  | 7,168 |  |  |  | 8,506 |
| Total notes receivable |  |  | 215,450 |  |  |  | 225,092 |
Less: Notes receivable, current portion included in other current assets |  |  | (11,770 | ) |  |  | (11,463 | )
Notes receivable, net of current portion |  | $ | 203,680 |  |  | $ | 213,629 |

| Gilroy Note

Calpine Gilroy Cogen, L.P. (“Gilroy”) had a long-term PPA with Pacific Gas and Electric Company (“PG&E”) for the sale of energy through 2018. The terms of the PPA provided for 120 megawatts of firm capacity and up to 10 megawatts of as-delivered capacity. On December 2, 1999, the California Public Utilities Commission (“CPUC”) approved the restructuring of the PPA between Gilroy and PG&E. Under the terms of the restructuring, PG&E and Gilroy were each released from performance under the PPA

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
effective November 1, 2002. Under the restructured contract, in addition to the normal capacity revenue for the period, Gilroy had earned from September 1999 to October 2002 restructured capacity revenue it would have earned over the November 2002 through March 2018 time period, for which PG&E had issued notes to the Company. These notes are scheduled to be paid by PG&E during the period from February 2003 to September 2014. The first scheduled note repayment of $1.7 million was received in February 2003.
On December 4, 2003, the Company announced that it had sold to a group of institutional investors its right to receive payments from PG&E under the Agreement between PG&E and Gilroy, a California Limited Partnership (PG&E Log No. 08C002) For Termination and Buy-Out of Standard Offer 4 Power Purchase Agreement, executed by PG&E on July 1, 1999 (the “Gilroy Receivable”) for $133.4 million in cash. Because the transaction did not satisfy the criteria for sales treatment under SFAS No. 140 it was reflected in the Consolidated Financial Statements as a secured financing, with a note payable of $133.4 million. The receivable balance and note payable balance are both reduced as PG&E makes payments to the buyer of the Gilroy Note. The $24.1 million difference between the $157.5 million book value of the Gilroy Note at the transaction date and the cash received is recognized as additional interest expense over the repayment term. The Company will continue to record interest income over the repayment term and interest expense will be accreted on the amortizing note payable balance.
Pursuant to the applicable transaction agreements, each of Gilroy and Calpine Gilroy 1, Inc., the general partner of Gilroy, has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. The Company consolidates these entities.

| Panda Note

In June 2000, the Company entered into a series of turbine sale contracts with, and acquired the development rights to construct, own and operate the Oneta Energy Center (“Oneta”) from Panda Energy International, Inc. and certain related entities. As part of the transaction, the Company extended PLC II, LLC (“PLC”) a loan bearing an interest rate of LIBOR plus 5%. The loan is collateralized by PLC’s carried interest in the income generated from Oneta, which achieved full commercial operations in June 2003. Additionally, Panda Energy International, Inc. executed a parental Guaranty as to the loan.
On November 5, 2003, Panda Energy International, Inc. and certain related parties, including PLC, (collectively “Panda”) filed suit against the Company and certain of its affiliates alleging, among other things, that the Company breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate Oneta in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits from Oneta and that the Company’s actions have reduced the profits from Oneta, thereby undermining Panda’s ability to repay monies owed to the Company under the loan. The Company has filed a counterclaim against PLC based on a guaranty and a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The court recently granted the Company’s motion to dismiss, but allowed Panda an opportunity to re-plead. The Company considers Panda’s lawsuit to be without merit and intends to defend vigorously against it. Discovery is currently in progress.
Panda defaulted on the loan, which was due on December 1, 2003. Because of the Guaranty and the collateral, the Company determined that a reserve was not needed as of December 31, 2004. However, the Company ceased accruing interest after the default date and continues to closely monitor the receivable pending the resolution of the litigation. See Note 25 for more information on the litigation.

| Eastman Note

In August 2000, the Company entered into an Energy Services Agreement (“ESA”) with Eastman Chemical Company (“Eastman”) at its Columbia facility in South Carolina. As part of the agreement, the Company financed the construction of the Heat Thermal Medium Heater System (“HTM”) facilities. Under

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
this agreement, Eastman will repay the Company $20.0 million for the HTM financed facilities over a period of 20 years with an annual interest rate of 9.76%. The first note receivable payment was received in April 2004.

| Androscoggin Note

The Company has a note receivable from its unconsolidated cost method investee AELLC. The Company ceased accruing interest income on its note receivable related to unreimbursed administration costs associated with the Company’s management of the project after a jury verdict was rendered against AELLC in a breach of contract dispute. In December 2004, the Company determined that its investment in Androscoggin was impaired and recorded a $5.0 million impairment reserve. On December 31, 2004, the carrying value after reserves of the Company’s notes receivable balance due from AELLC was $4.0 million. See Note 7 for further information.

| Mitsui Note

In December 2003, the Company contributed two gas turbines with a book value of approximately $76.0 million in exchange for a 45% interest in the Valladolid Joint Venture project with Mitsui in Mexico. The Company recorded its interest in the project at a value of $67.0 million, which reflected the cost of the turbines less a $9.0 million note receivable that was booked upon transfer of the turbines, representing a return of capital. Subsequently, Mitsui assumed the note receivable from the project and received additional equity in the project. At the time of the original investment, the Company’s investment in and notes receivable from Mitsui exceeded its share of its underlying equity by $31 million, which will be amortized as an adjustment to the Company’s share of the project’s net income over the depreciable life of the underlying assets. In October 2004, the note receivable matured and all payments were received.

9. | Canadian Power and Gas Trusts

Calpine Power Income Fund — On August 29, 2002, the Company announced it had completed a Cdn$230 million (US$147.5 million) initial public offering of its Canadian income fund — Calpine Power Income Fund (“CPIF”). The 23 million Trust Units issued to the public were priced at Cdn$10 per unit, to initially yield 9.35% per annum. On September 20, 2002, the syndicate of underwriters fully exercised the over-allotment option that it was granted as part of the initial public offering of Trust Units and acquired 3,450,000 additional Trust Units of CPIF at Cdn$10 per Trust Unit, generating Cdn$34.5 million (US$21.9 million). CPIF used the proceeds of the initial offering and over-allotment to purchase an equity interest in CPLP, which holds two of Calpine’s Canadian power generating assets, the Island Cogeneration Facility and the Calgary Energy Centre. CPIF also used the proceeds to make a loan to a Calpine subsidiary which owns Calpine’s other Canadian power generating asset, the equity investment in the Whitby cogeneration plant. Combined, these assets represent approximately 168.3 net megawatts of power generating capacity.
On February 13, 2003, the Company completed a secondary offering of 17,034,234 Warranted Units of CPIF for gross proceeds of Cdn$153.3 million (US$100.9 million). The Warranted Units were sold to a syndicate of underwriters at a price of Cdn$9.00. Each Warranted Unit consisted of one Trust Unit and one-half of one Trust Unit purchase warrant. Each Warrant entitled the holder to purchase one Trust Unit at a price of Cdn$9.00 per Trust Unit at any time on or prior to December 30, 2003, after which time the Warrant became null and void. During 2003 a total of 8,508,517 Warrants were exercised, resulting in cash proceeds to the Company of Cdn$76.6 million (US$56.7 million). CPIF used the proceeds from the secondary offering and Warrant exercise to purchase an additional equity interest in CPLP.
The Company currently holds less than 1% of CPIF’s trust units; however, the Company retains a 30% subordinated equity interest in CPLP and has a significant continuing involvement in the assets transferred to CPLP. The assets of CPLP are included in the Company’s consolidated balance sheet under the

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
guidance of SFAS No. 66, “Accounting for Sales of Real Estate” due to the Company’s significant continuing involvement in the assets transferred to CPLP. Therefore, the financial results of CPLP are consolidated in the Company’s financial statements. The proceeds from the initial public offering, the exercise of the underwriters over-allotment, the proceeds from the secondary offering of Trust Units and the proceeds from the exercise of Warrants represent the Fund’s 70% equity interest in CPLP and its underlying generating assets and have been recorded as minority interests in the Company’s consolidated balance sheet. Because of this equity ownership in CPLP, the Company considers CPIF a related party. See Note 13 for a discussion of the capital lease transaction with CPIF.
Calpine Natural Gas Trust — On October 15, 2003, the Company closed the initial public offering of CNGT. A total of 18,454,200 trust units were issued at a price of Cdn$10.00 per trust unit for gross proceeds of approximately Cdn$184.5 million (US$139.4 million). CNGT acquired select natural gas and petroleum properties from Calpine with the proceeds from the initial public offering, Cdn$61.5 million (US$46.5 million) proceeds from a concurrent issuance of units to a Canadian affiliate of Calpine, and Cdn$40.0 million (US$30.2 million) proceeds from bank debt. Net proceeds to Calpine, totaled approximately Cdn$207.9 million (US$157.1 million), reflecting a gain of $62.2 million on the sale of the properties. On October 22, 2003, the syndicate of underwriters fully exercised the over-allotment option associated with the initial public offering resulting in additional cash to the CNGT. As a result of the exercise of the over-allotment option, Calpine acquired an additional 615,140 trust units at Cdn$10.0 per trust unit for a cash payment to the CNGT of Cdn$6.2 million (US$4.7 million). Prior to the subsequent sale of this investment, the Company held 25 percent of the outstanding trust units of CNGT and accounted for it using the equity method.
On September 2, 2004, the Company completed the sale of its equity investment in the CNGT. In accordance with SFAS No. 144 the Company’s 25 percent equity method investment in the CNGT was considered part of the larger disposal group and therefore evaluated and accounted for as a discontinued operation. See Note 10 for more information on the sale of the Canadian natural gas reserves and petroleum assets. In addition, the Company considered CNGT a related party and disclosed all transactions up through the date of sale as such. See Note 7 for more information on related party transactions with unconsolidated investments.

10. | Discontinued Operations

The Company has adopted a strategy of conserving its core strategic assets and selectively disposing of certain less strategically important assets, which serves primarily to raise cash for general corporate purposes and strengthen the Company’s balance sheet through repayment of debt. Set forth below are the Company’s material asset disposals by reportable segment that impacted the Company’s Consolidated Financial Statements as of December 31, 2004 and December 31, 2003:

| Corporate and Other

On July 31, 2003, the Company completed the sale of its specialty data center engineering business and recorded a pre-tax loss on the sale of $11.6 million.

| Oil and Gas Production and Marketing

On August 29, 2002, the Company completed the sale of certain non-strategic oil and gas properties (“Medicine River properties”) located in central Alberta to NAL Oil and Gas Trust and another institutional investor for Cdn$125.0 million (US$80.1 million). As a result of the sale, the Company recorded a pre-tax gain of $21.9 million in the third quarter 2002.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
On October 1, 2002, the Company completed the sale of substantially all of its British Columbia oil and gas properties to Calgary, Alberta-based Pengrowth Corporation for gross proceeds of approximately Cdn$387.5 million (US$244.3 million). Of the total consideration, the Company received US$155.9 million in cash. The remaining US$88.4 million of consideration was paid by Pengrowth Corporation’s purchase in the open market of US$203.2 million in aggregate principal amount of the Company’s debt securities. As a result of the transaction, the Company recorded a US$37.4 million pre-tax gain on the sale of the properties and a gain on the extinguishment of debt of US$114.8 million in the fourth quarter 2002. The Company used approximately US$50.4 million of cash proceeds to repay amounts outstanding under its US$1.0 billion term loan.
On October 31, 2002, the Company sold all of its oil and gas properties in Drake Bay Field located in Plaquemines Parish, Louisiana for approximately $3 million to Goldking Energy Corporation. As a result of the sale, the Company recognized a pre-tax loss of $0.02 million in the fourth quarter 2002.
On November 20, 2003, the Company completed the sale of its Alvin South Field oil and gas assets located near Alvin, Texas for approximately $0.06 million to Cornerstone Energy, Inc. As a result of the sale, the Company recognized a pre-tax loss of $0.2 million.
On September 1, 2004, the Company along with Calpine Natural Gas L.P., a Delaware limited partnership, completed the sale of its Rocky Mountain gas reserves that were primarily concentrated in two geographic areas: the Colorado Piceance Basin and the New Mexico San Juan Basin. Together, these assets represented approximately 120 billion cubic feet equivalent (“Bcfe”) of proved gas reserves, producing approximately 16.3 million net cubic feet equivalent (“Mmcfe”) per day of gas. Under the terms of the agreement Calpine received net cash payments of approximately $218.7 million, and recorded a pre-tax gain of approximately $103.7 million.
On September 2, 2004, the Company completed the sale of its Canadian natural gas reserves and petroleum assets. These Canadian assets represented approximately 221 Bcfe of proved reserves, producing approximately 61 Mmcfe per day. Included in this sale was the Company’s 25% interest in approximately 80 Bcfe of proved reserves (net of royalties) and 32 Mmcfe per day of production owned by the CNGT. In accordance with SFAS No. 144 the Company’s 25% equity method investment in the CNGT was considered part of the larger disposal group (i.e., assets to be disposed of together as a group in a single transaction to the same buyer), and therefore evaluated and accounted for as discontinued operations. Under the terms of the agreement, Calpine received cash payments of approximately Cdn$808.1 million, or approximately US$626.4 million. Calpine recorded a pre-tax gain of approximately $104.5 million on the sale of these Canadian assets net of $20.1 million in foreign exchange losses recorded in connection with the settlement of forward contracts entered into to preserve the US dollar value of the Canadian proceeds.
In connection with the sale of the oil and gas assets in Canada, the Company entered into a seven-year gas purchase agreement beginning on March 31, 2005, and expiring on October 31, 2011, that allows, but does not require, the Company to purchase gas from the buyer at current market index prices. The agreement is not asset specific and can be settled by any production that the buyer has available.
In connection with the sale of the Rocky Mountain gas reserves, the New Mexico San Juan Basin sales agreement allows for the buyer and the Company to execute a ten-year gas purchase agreement for 100% of the underlying gas production of sold reserves, at market index prices. Any agreement would be subject to mutually agreeable collateral requirements and other customary terms and provisions. As of October 1, 2004, the gas purchase agreement was finalized and executed between the Company and the buyer.
The Company believes that all final terms of the gas purchase agreements described above, are on a market value and arm’s length basis. If the Company elects in the future to exercise a call option over production from the disposed components, the Company will consider the call obligation to have been met as

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
if the actual production delivered to the Company under the call was from assets other than those constituting the disposed components.

| Electric Generation and Marketing

On December 16, 2002, the Company completed the sale of the 180-megawatt DePere Energy Center in DePere, Wisconsin. The facility was sold to Wisconsin Public Service for $120.4 million, which included $72.0 million in cash at closing and a $48.4 million payment due in December 2003. As a result of the sale, the Company recognized a pre-tax gain of $35.8 million. On December 17, 2002, the Company sold its right to the December 2003 payment to a third party for $46.3 million, and recognized a pre-tax loss of $2.1 million thereon.
On January 15, 2004, the Company completed the sale of its 50-percent undivided interest in the 545-megawatt Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the Lower Colorado River Authority (“LCRA”). Under the terms of the agreement, Calpine received a cash payment of $148.6 million and recorded a pre-tax gain of $35.3 million. In addition, CES entered into a tolling agreement with LCRA providing for the option to purchase 250 megawatts of electricity through December 31, 2004. At December 31, 2003, the Company’s undivided interest in the Lost Pines facility was classified as “held for sale” and subsequently sold in 2004.

| Summary

The Company made reclassifications to current and prior period financial statements to reflect the sale of these oil and gas and power plant assets and liabilities and to separately reclassify the operating results of the assets sold and the gain (loss) on sale of those assets from the operating results of continuing operations to discontinued operations.
The tables below present significant components of the Company’s income from discontinued operations for 2004, 2003 and 2002, respectively (in thousands):

|  | 2004 |
|  | Electric |  |  | Oil and Gas |  |  |
|  | Generation |  |  | Production |  |  | Corporate |  |
|  | and Marketing |  |  | and Marketing |  |  | and Other |  | Total |
Total revenue |  | $ | 2,679 |  |  | $ | 32,415 |  |  | $ | — |  |  | $ | 35,094 |
Gain on disposal before taxes |  | $ | 35,326 |  |  | $ | 208,172 |  |  | $ | — |  |  | $ | 243,498 |
Operating income from discontinued operations before taxes |  |  | 24 |  |  |  | 4,938 |  |  |  | — |  |  |  | 4,962 |
Income from discontinued operations before taxes |  | $ | 35,350 |  |  | $ | 213,110 |  |  | $ | — |  |  | $ | 248,460 |
Income tax provision |  | $ | (12,394 | ) |  | $ | (37,701 | ) |  | $ | — |  |  | $ | (50,095 | )
Income from discontinued operations, net of tax |  | $ | 22,956 |  |  | $ | 175,409 |  |  | $ | — |  |  | $ | 198,365 |

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

|  | 2003 |
|  | Electric |  |  | Oil and Gas |  |  |
|  | Generation |  |  | Production |  |  | Corporate |  |  |
|  | and Marketing |  |  | and Marketing |  |  | and Other |  |  | Total |
Total revenue |  | $ | 72,968 |  |  | $ | 49,656 |  |  | $ | 3,748 |  |  | $ | 126,372 |
Loss on disposal before taxes |  | $ | — |  |  | $ | (235 | ) |  | $ | (11,571 | ) |  | $ | (11,806 | )
Operating income (loss) from discontinued operations before taxes |  |  | 4,147 |  |  |  | 15,130 |  |  |  | (6,918 | ) |  |  | 12,359 |
Income (loss) from discontinued operations before taxes |  | $ | 4,147 |  |  | $ | 14,895 |  |  | $ | (18,489 | ) |  | $ | 553 |
Income tax (provision) benefit |  |  | (1,453 | ) |  |  | 8,651 |  |  |  | 7,218 |  |  |  | 14,416 |
Income from discontinued operations, net of tax |  | $ | 2,694 |  |  | $ | 23,546 |  |  | $ | (11,271 | ) |  | $ | 14,969 |

|  | 2002 |
|  | Electric |  |  | Oil and Gas |  |  |
|  | Generation |  |  | Production |  |  | Corporate |  |  |
|  | and Marketing |  |  | and Marketing |  |  | and Other |  |  | Total |
Total revenue |  | $ | 75,004 |  |  | $ | 134,200 |  |  | $ | 7,653 |  |  | $ | 216,857 |
Gain on disposal before taxes |  | $ | 35,840 |  |  | $ | 59,288 |  |  | $ | — |  |  | $ | 95,128 |
Operating income (loss) from discontinued operations before taxes |  |  | 16,388 |  |  |  | 14,452 |  |  |  | (16,968 | ) |  |  | 13,872 |
Income (loss) from discontinued operations before taxes |  | $ | 52,228 |  |  | $ | 73,740 |  |  | $ | (16,968 | ) |  | $ | 109,000 |
Income tax (provision) benefit |  |  | (20,151 | ) |  |  | (3,868 | ) |  |  | 6,915 |  |  |  | (17,104 | )
Income from discontinued operations, net of tax |  | $ | 32,077 |  |  | $ | 69,872 |  |  | $ | (10,053 | ) |  | $ | 91,896 |

The table below presents the assets and liabilities designated as held for sale on the Company’s balance sheet as of December 31, 2003 (in thousands). At December 31, 2004, there were no held-for-sale assets:

|  | 2003 |  |
|  | Electric |  |  | Oil and Gas |  |  |  |  |
|  | Generation |  |  | Production |  |  | Corporate |  |
|  | and Marketing |  |  | and Marketing |  |  | and Other |  | Total |
Current assets of discontinued operations |  | $ | 651 |  |  | $ | 1,914 |  |  | $ | — |  |  | $ | 2,565 |
Long-term assets of discontinued operations |  |  | 112,148 |  |  |  | 631,001 |  |  |  | — |  |  |  | 743,149 |
Total assets of discontinued operations |  | $ | 112,799 |  |  | $ | 632,915 |  |  | $ | — |  |  | $ | 745,714 |
Current liabilities of discontinued operations |  | $ | — |  |  | $ | 221 |  |  | $ | — |  |  | $ | 221 |
Long-term liabilities of discontinued operations |  |  | 161 |  |  |  | 17,667 |  |  |  | — |  |  |  | 17,828 |
Total liabilities of discontinued operations |  | $ | 161 |  |  | $ | 17,888 |  |  | $ | — |  |  | $ | 18,049 |

The Company allocates interest to discontinued operations in accordance with EITF Issue No. 87-24, “Allocation of Interest to Discontinued Operations.” The Company includes interest expense on debt which is required to be repaid as a result of a disposal transaction in discontinued operations. Additionally, other interest expense that cannot be attributed to other operations of the Company is allocated based on the ratio of

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
net assets to be sold less debt that is required to be paid as a result of the disposal transaction to the sum of total net assets of the Company plus consolidated debt of the Company, excluding (a) debt of the discontinued operation that will be assumed by the buyer, (b) debt that is required to be paid as a result of the disposal transaction and (c) debt that can be directly attributed to other operations of the Company. Using the methodology above, the Company allocated interest expense to its British Columbia oil and gas properties for approximately $50.4 million of debt the Company is required to pay under the terms of its $1.0 billion term loan. In addition, the Company allocated interest expense associated with the debt to be repaid as a result of the sale of the Canadian and Rocky Mountain natural gas reserves and petroleum assets as well as other debt related to the Company’s operations in the amount of $17.9 million, $19.8 million and $11.0 million in 2004, 2003 and 2002, respectively.

11. | Debt

The annual principal repayments or maturities of the Company’s debt obligations as of December 31, 2004, are as follows (in thousands):

2005 |  | $ | 1,033,956 |
2006 |  |  | 944,046 |
2007 |  |  | 1,851,022 |
2008 |  |  | 2,221,435 |
2009 |  |  | 1,667,272 |
Thereafter |  |  | 10,257,034 |
| Total |  | $ | 17,974,765 |

Covenant Restrictions — The covenants in certain of the Company’s debt agreements currently impose the following restrictions on its activities:

| • | Certain of the Company’s indentures place conditions on its ability to issue indebtedness if the Company’s interest coverage ratio (as defined in those indentures) is below 2:1. Currently, the Company’s interest coverage ratio (as so defined) is below 2:1 and, consequently, the Company generally would not be allowed to issue new debt, except for (i) certain types of new indebtedness that refinances or replaces existing indebtedness, and (ii) non-recourse debt and preferred equity interests issued by the Company’s subsidiaries for purposes of financing certain types of capital expenditures, including plant development, construction and acquisition expenses. In addition, if and so long as the Company’s interest coverage ratio is below 2:1, the Company’s ability to invest in unrestricted subsidiaries and non-subsidiary affiliates and make certain other types of restricted payments will be limited. As of December 31, 2004, the Company’s interest coverage ratio (as so defined) has fallen below 1.75:1 and, until the ratio is greater than 1.75:1, certain of the Company’s indentures will prohibit any further investments in non-subsidiary affiliates.
| • | Certain of the Company’s indebtedness issued in the last half of 2004 was permitted under the Company’s indentures on the basis that the proceeds would be used to repurchase or redeem existing indebtedness. While the Company completed a portion of such repurchases during the fourth quarter of 2004 and the first quarter of 2005, the Company is still in the process of completing the required amount of repurchases. While the amount of indebtedness that must still be repurchased will ultimately depend on the market price of the Company’s outstanding indebtedness at the time the indebtedness is repurchased, based on current market conditions, the Company currently anticipates that it will spend up to approximately $202.9 million on additional repurchases in order to fully satisfy this requirement. The Company’s bond purchase requirement was estimated to be approximately

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

|  | $270 million as of December 31, 2004, and this amount has been classified as Senior Notes, current portion on the Company’s consolidated balance sheet.
| • | When the Company or one of its subsidiaries sells a significant asset or issues preferred equity, the Company’s indentures generally require that the net proceeds of the transaction be used to make capital expenditures or to repurchase or repay certain types of subsidiary indebtedness, in each case within 365 days of the closing date of the transaction. In light of this requirement, and taking into account the amount of capital expenditures currently budgeted for 2005, the Company anticipates that it will need to use approximately $250.0 of the net proceeds of the $360.0 million Two-Year Redeemable Preferred Shares issued on October 26, 2004, and approximately $200.0 million of the net proceeds of the $260.0 million Redeemable Preferred Shares issued on January 31, 2005, to repurchase or repay certain subsidiary indebtedness. The $250.0 million of long-term debt has been reclassified as Senior Notes, current portion liability on the Company’s consolidated balance sheet. The actual amount of the net proceeds that will be required to be used to repurchase or repay subsidiary debt will depend upon the actual amount of the net proceeds that is used to make capital expenditures, which may be more or less than the amount currently budgeted.

Deferred Financing Costs — The deferred financing costs related to the Company’s Senior Notes and the Convertible Senior Notes are amortized over the life of the related debt, ranging from 4 to 20 years, using the effective interest rate method. Costs incurred in connection with obtaining other financing are deferred and amortized over the life of the related debt. However, when timing of debt transactions involve contemporaneous exchanges of cash between the Company and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, deferred financing costs are accounted for in accordance with EITF Issue No. 96-19, “Debtor’s Accounting for a Modification or Exchange of Debt Instruments” (“EITF Issue No. 96-19”). Depending on whether the transaction qualifies as an extinguishment or modification, EITF Issue No. 96-19 requires the Company to either write-off the original deferred financing costs and capitalize the new issuance costs or continue to amortize the original deferred financing costs and immediately expense the new issuance costs.
See Notes 12-18 below for a description of each of the Company’s debt obligations.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

12. | Notes Payable and Borrowings Under Lines of Credit, Notes Payable to Calpine Capital Trusts and Preferred Interests

The components of notes payable and borrowings under lines of credit and related outstanding letters of credit are (in thousands):

|  |  |  | Letters of Credit |
|  | Borrowings Outstanding |  |  | Outstanding |
|  | December 31, |  |  | December 31, |
|  | 2004 |  |  | 2003 |  |  | 2004 |  |  | 2003 |
Corporate Cash Collateralized Letter of Credit Facility |  | $ | — |  |  | $ | — |  |  | $ | 233,271 |  |  | $ | — |
Power Contract Financing, L.L.C. |  |  | 688,366 |  |  |  | 802,246 |  |  |  | — |  |  |  | — |
Gilroy note payable(1) |  |  | 125,478 |  |  |  | 132,385 |  |  |  | — |  |  |  | — |
Siemens Westinghouse Power Corporation |  |  | — |  |  |  | 107,994 |  |  |  | — |  |  |  | — |
Calpine Northbrook Energy Marketing, LLC (“CNEM”) note |  |  | 52,294 |  |  |  | 74,632 |  |  |  | — |  |  |  | — |
Corporate revolving lines of credit |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 135,600 |
Power Contract Financing III, LLC |  |  | 51,592 |  |  |  | — |  |  |  | — |  |  |  | — |
Calpine Commercial Trust |  |  | 34,255 |  |  |  | — |  |  |  | — |  |  |  | — |
Other |  |  | 22,280 |  |  |  | 10,606 |  |  |  | 6,158 |  |  |  | 603 |
| Total notes payable and borrowings under lines of credit |  |  | 974,265 |  |  |  | 1,127,863 |  |  |  | 239,429 |  |  |  | 136,203 |
| Total notes payable to Calpine Capital Trusts |  |  | 517,500 |  |  |  | 1,153,500 |  |  |  | — |  |  |  | — |
Preferred interest in Saltend Energy Centre |  |  | 360,000 |  |  |  | — |  |  |  | — |  |  |  | — |
Preferred interest in Auburndale Power Plant |  |  | 79,135 |  |  |  | 87,632 |  |  |  | — |  |  |  | — |
Preferred interest in King City Power Plant |  |  | — |  |  |  | 82,000 |  |  |  | — |  |  |  | — |
Preferred interest in Gilroy Energy Center, LLC |  |  | 67,402 |  |  |  | 74,000 |  |  |  | — |  |  |  | — |
| Total preferred interests |  |  | 506,537 |  |  |  | 243,632 |  |  |  | — |  |  |  | — |
| Total notes payable and borrowings under lines of credit, notes payable to Calpine Capital Trusts, preferred interests, and term loan |  | $ | 1,998,302 |  |  | $ | 2,524,995 |  |  | $ | 239,429 |  |  | $ | 136,203 |
|  | Less: notes payable and borrowings under lines of credit, current portion, notes payable to Calpine Capital Trusts, current portion and preferred interests, current portion |  |  | 213,416 |  |  |  | 265,512 |  |  |  |  |  |  |  |  |
Notes payable and borrowings under lines of credit, net of current portion, notes payable to Calpine Capital Trusts, net of current portion, preferred interests, net of current portion, and term loan |  | $ | 1,784,886 |  |  | $ | 2,259,483 |  |  |  |  |  |  |  |  |

(1) | See Note 8 for information regarding this note.

| Notes Payable and Borrowings Under Lines of Credit and Term Loan

Corporate Cash Collateralized Letter of Credit Facility — On September 30, 2004, the Company established a new $255 million Cash Collateralized Letter of Credit Facility with Bayerische Landesbank, under which all letters of credit previously issued under the $300 million Working Capital Revolver and the $200 million Cash Collateralized Letter of Credit Facility have been transitioned into that new Facility.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Power Contract Financing, L.L.C. — On June 13, 2003, PCF, an indirect wholly owned subsidiary of Calpine, completed an offering of $339.9 million of 5.2% Senior Secured Notes Due 2006 and $462.3 million of 6.256% Senior Secured Notes Due 2010. The two tranches of Senior Secured Notes, totaling $802.2 million of gross proceeds, are secured by fixed cash flows from a fixed-priced, long-term PPA with the State of California Department of Water Resources (“CDWR”) and a fixed-priced, long-term power purchase agreement with a third party and are non- recourse to the Company’s other consolidated subsidiaries. The two tranches of Senior Secured Notes have been rated Baa2 by Moody’s Investor Service, Inc. and BBB (with a negative outlook) by Standard & Poor’s (“S&P”). During the year 2004, $113.9 million was repaid based on the agreed upon bond repayment schedule. The effective interest rates on the 5.2% Senior Secured Notes Due 2006 and 6.256% Senior Secured Notes Due 2010, after amortization of deferred financing costs, were 8.3% and 9.4%, respectively, per annum at December 31, 2004 and 2003.
Pursuant to the applicable transaction agreements, PCF has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. In accordance with FIN 46 the Company consolidates this entity. See Note 2 for more information on FIN 46. The above mentioned power sales and PPAs, which have been acquired by PCF from CES, and the PCF Notes are assets and liabilities of PCF, separate from the assets and liabilities of the Company and other subsidiaries of the Company. The proceeds of the Senior Secured Notes were primarily used by PCF to purchase the power sales and PPAs.
Siemens Westinghouse Power Corporation — On January 31, 2002, the Company’s subsidiary, Calpine Construction Management Company, Inc., entered into an agreement with Siemens Westinghouse Power Corporation (“SWPC”) including vendor financing of up to $232.0 million bearing variable interest for gas and steam turbine generators and related equipment with monthly payment due dates through January 28, 2005. The remaining balance under this agreement was repaid in 2004. The interest rate at December 31, 2004 and 2003, was 8.5%.
Calpine Northbrook Energy Marketing, LLC (“CNEM”) Note — On May 15, 2003, CNEM, a wholly owned stand-alone subsidiary of CNEM Holdings, LLC, which is a wholly owned indirect subsidiary of CES, completed an offering of $82.8 million secured by an existing power sales agreement with the BPA. Under the existing 100-megawatt fixed-price contract, CNEM delivers baseload power to BPA through December 31, 2006. As a part of the secured transaction, CNEM entered into a contract with a third party to purchase that power based on spot prices and a fixed-price swap agreement with an affiliate of Deutsche Bank to lock in the price of the purchased power. The terms of both agreements are through December 31, 2006. To complete the transactions, CNEM then entered into an agreement with an affiliate of Deutsche Bank and borrowed $82.8 million secured by the BPA contract, the spot market PPA, the fixed price swap agreement and the equity interests in CNEM. The spread between the price for power under the BPA contract and the price for power under the fixed price swap agreement provides the cash flow to pay CNEM’s debt and other expenses. Proceeds from the borrowing were used to pay transaction expenses for plant construction and general corporate purposes, as well as fees and expenses associated with this transaction. CNEM will make quarterly principal and interest payments on the loan that matures on December 31, 2006. The effective interest rate, after amortization of deferred financing charges, was 12.2% and 12.7% per annum at December 31, 2004 and 2003, respectively.
Pursuant to the applicable transaction agreements, each of CNEM and its parent, CNEM Holdings, LLC, has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. In accordance with FIN 46-R the Company consolidates these entities. The above mentioned power sales agreement with BPA has been acquired by CNEM from CES and the spot market PPA with a third party and the swap agreement have been entered into by CNEM and, together with the $82.8 million loan, are assets and liabilities of CNEM, separate from the assets and liabilities of the Company and other subsidiaries of the Company. The only significant asset of CNEM Holdings, LLC is its equity interest in

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CNEM. The proceeds of the $82.8 million loan were primarily used by CNEM to purchase the power sales agreement with BPA.
Corporate Revolving Lines of Credit — On July 16, 2003, the Company entered into agreements for a new $500 million working capital facility. This first-priority senior secured facility consisted of a two-year, $300 million working capital revolver and a four-year, $200 million term loan that together provide up to $500 million in combined cash borrowing and letter of credit capacity. The facility replaced the Company’s prior $600 million and $400 million working capital facilities and is secured by a first-priority lien on the same assets that collateralize the Company’s $3.3 billion term loan and second-priority senior secured notes offering (the “$3.3 billion offering”).
On July 16, 2003, the Company entered into a cash collateralized letter of credit facility with The Bank of Nova Scotia under which it was able to issue up to $200 million of letters of credit through July 15, 2005. Amounts outstanding under letters of credit issued under this facility had a corresponding amount of cash on deposit and held by The Bank of Nova Scotia as collateral, which was classified as restricted cash in the Company’s Consolidated Balance Sheet.
As a result of the sale of certain natural gas properties during 2004, the Company repaid all amounts outstanding under its First Priority Senior Secured Term Loan B Notes Due 2007 and the $300 million Working Capital Revolver.
Power Contract Financing III, LLC — On June 2, 2004, the Company’s wholly owned subsidiary, PCF III issued $85.0 million of zero coupon notes collateralized by PCF III’s ownership of PCF. PCF III owns all of the equity interests in PCF, which holds the CDWR I contract monetized in June 2003 and maintains a debt reserve fund, which had a balance of approximately $94.4 million at December 31, 2004. The Company received cash proceeds of approximately $49.8 million from the issuance of the notes. At December 31, 2004, the interest rate was 12% per annum.
Calpine Commercial Trust — In May 2004, in connection with the King City transaction, Calpine Canada Power Limited, a wholly owned subsidiary of the Company, entered into a financing with Calpine Commercial Trust. Interest accrues at 13%, and the loan has principal and interest payments scheduled through maturity in December 2010. The effective interest rate of this loan is 17%.
Calpine Energy Management, L.P. Letter of Credit Facility — On August 5, 2004, the Company announced that its newly created entity, Calpine Energy Management, L.P. (“CEM”), entered into a $250.0 million letter of credit facility with Deutsche Bank (rated Aa3/ AA-) that expires in October 2005. Deutsche Bank will guarantee CEM’s power and gas obligations by issuing letters of credit. Receivables generated through power sales serve as collateral to support the letters of credit. As of December 31, 2004, there was approximately $9.6 million in letters of credit outstanding.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| Notes Payable to Calpine Capital Trusts

In 1999 and 2000, the Company, through its wholly owned subsidiaries, Calpine Capital Trust I, Calpine Capital Trust II, and Calpine Capital Trust III, statutory business trusts created under Delaware law, (collectively, “the Trusts”) completed offerings of Remarketable Term Income Deferrable Equity Securities (“HIGH TIDES”) at a value of $50.00 per share. A summary of these offerings follows in the table below ($ in thousands):

|  |  |  |  |  |  |  | Effective |  |  |  |  |  |  | Conversion |  |  |  |  |
|  |  |  |  |  |  |  | Interest Rate |  |  |  |  |  |  | Ratio — |  |  |  |  |
|  |  |  |  |  |  |  | per Annum |  |  |  |  |  |  | Number of |  |  |  |  |
|  |  |  |  |  | Stated |  |  | as of |  |  | Balance |  |  | Balance |  |  | Common |  |  |  |  | Initial |
|  |  |  |  |  | Interest |  |  | December 31, |  |  | December 31, |  |  | December 31, |  |  | Shares per 1 |  |  | First |  |  | Redemption |
|  | Issue Date |  |  | Shares |  |  | Rate |  |  | 2004 |  |  | 2004 |  |  | 2003 |  |  | High Tide |  |  | Redemption Date |  |  | Price |
HIGH TIDES I |  |  | October 1999 |  |  |  | 5,520,000 |  |  |  | 5.75 | % |  |  | 5.38 | % |  | $ | — |  |  | $ | 276,000 |  |  |  | 3.4620 |  |  |  | November 5, 2002 |  |  |  | 101.440 | %
HIGH TIDES II |  |  | January and |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  | February 2000 |  |  |  | 7,200,000 |  |  |  | 5.50 | % |  |  | 5.79 | % |  |  | — |  |  |  | 360,000 |  |  |  | 1.9524 |  |  |  | February 5, 2003 |  |  |  | 101.375 | %
HIGH TIDES III |  |  | August 2000 |  |  |  | 10,350,000 |  |  |  | 5.00 | % |  |  | 5.09 | % |  |  | 517,500 |  |  |  | 517,500 |  |  |  | 1.1510 |  |  |  | August 5, 2003 |  |  |  | 101.250 | %
|  |  |  |  |  |  | 23,070,000 |  |  |  |  |  |  |  |  |  |  | $ | 517,500 |  |  | $ | 1,153,500 | (1) |  |  |  |  |  |  |  |  |  |  |  |

(1) | Prior to the adoption of FIN 46 as of December 31, 2003, the Trusts were consolidated in the Company’s Consolidated Balance Sheet, and the HIGH TIDES were recorded between total liabilities and stockholders equity as Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts. However, upon adoption of FIN 46 as of December 31, 2003, the Company deconsolidated the Trusts as of October 1, 2003, and therefore no longer records the HIGH TIDES in its Consolidated Balance Sheet. As a result, the Company’s convertible subordinated debentures (as discussed below) issued to the Trusts were no longer eliminated in consolidation and were reflected as notes payable to Calpine Capital Trusts in the Company’s Consolidated Balance Sheet with an outstanding balance of $1.2 billion and $517.5 million at December 31, 2003 and December 31, 2004, respectively. During 2003 and 2004, the Company exchanged 30.8 million Calpine common shares in privately negotiated transactions for approximately $77.5 million par value of HIGH TIDES I, and $75.0 million of HIGH TIDES II. The Company also repurchased $115.0 million par value of HIGH TIDES III for cash of $111.6 million. The repurchased HIGH TIDES III are reflected in the Company’s consolidated balance sheet in Other Assets as available-for-sale securities as the repurchase did not meet the debt extinguishment criteria in SFAS No. 140. See Note 2 for further information regarding the adoption of FIN 46 and Note 3 regarding the Company’s available-for-sale securities.

The net proceeds from each of the offerings were used by the Trusts to invest in convertible subordinated debentures of the Company, which represent substantially all of the respective Trusts’ assets. The Company effectively guaranteed all of the respective Trusts’ obligations under the trust preferred securities. The trust preferred securities had or have liquidation values of $50.00 per share, or $1.2 billion in total for all of the issuances. The Company had or has the right to defer the interest payments on the debentures for up to twenty consecutive quarters, which would also cause a deferral of distributions on the trust preferred securities. Currently, the Company has no intention of deferring interest payments on the debentures remaining outstanding. The Company considers the Trusts related parties.
On October 20, 2004, the Company repaid the $276.0 million and $360.0 million convertible subordinate debentures held by Trust I (“HIGH TIDES I”) and Trust II (“HIGH TIDES II”) respectively, which used those proceeds to redeem its outstanding 53/4% convertible preferred securities issued by Trust I, and 51/2% convertible preferred securities issued by Trust II. The redemption of the HIGH TIDES I and HIGH TIDES II available-for-sale securities previously purchased and held by the Company resulted in a realized gain of approximately $6.1 million. The Company intends to cause both Trusts, which are related parties, to be terminated.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| Preferred Interests

In May 2003, FASB issued SFAS No. 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 applies specifically to a number of financial instruments that companies have historically presented within their financial statements either as equity or between the liabilities section and the equity section, rather than as liabilities. SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. The Company adopted SFAS No. 150 on July 1, 2003. For those instruments required to be recoded as debt, SFAS No. 150 does not permit reclassification of prior period amounts to conform to the current period presentation. The adoption of SFAS No. 150 and related balance sheet reclassifications did not have an effect on net income or total stockholders’ equity but have impacted the Company’s debt-to-equity and debt-to-capitalization ratios.
In November 2003, FASB indefinitely deferred certain provisions of SFAS No. 150 as they apply to mandatorily redeemable non-controlling (minority) interests associated with finite-lived subsidiaries. The Company owns approximately 30% of CPLP, which is finite-lived, terminating on December 31, 2050. See Note 7 for a discussion of the Company’s investment in CPLP. Upon FASB’s finalization of this issue, the Company may be required to reclassify the minority interest relating to the Company’s investment in Calpine Power Limited Partnership (“CPLP”) to debt. As of December 31, 2004, the minority interest related to CPLP was approximately $393.4 million. The assets of CPLP are included in the Company’s consolidated balance sheet under the guidance of SFAS No. 66, “Accounting for Sales of Real Estate” due to the Company’s significant continuing involvement in the assets transferred to CPLP.
Saltend Energy Centre — On October 26, 2004, the Company, through its indirect, wholly owned subsidiary Calpine (Jersey) Limited completed a $360 million offering of two-year, Redeemable Preferred Shares. The Redeemable Preferred Shares will distribute dividends priced at 3-month U.S. LIBOR plus 700 basis points to the shareholders on a quarterly basis. The proceeds of the offering of the Redeemable Preferred Shares were initially loaned to Calpine’s 1,200-megawatt Saltend Energy Centre located in Hull, Yorkshire England, and the future payments of principal and interest on such loan will fund payments on the Redeemable Preferred Shares. The net proceeds of the Redeemable Preferred Shares offering are to be used as permitted by the Company’s indentures. The maximum cost that the Company would incur to repurchase the Redeemable Preferred Shares at December 31, 2004, is $370.8 million. The effective interest rate, after amortization of deferred financing charges, was 11.6% per annum at December 31, 2004.
Auburndale Power Plant — On September 3, 2003, the Company announced that it had completed the sale of a 70% preferred interest in its Auburndale power plant to Pomifer Power Funding, LLC, (“PPF”), a subsidiary of ArcLight Energy Partners Fund I, L.P., for $88.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, due to certain preferential distributions to PPF. The preferential distributions are to be paid quarterly beginning in November 2003 and total approximately $204.7 million over the 11-year period. The preferred interest holders’ recourse is limited to the net assets of the entity and distribution terms are defined in the agreement. The Company has not guaranteed the payment of these preferential distributions. Calpine will hold the remaining interest in the facility and will continue to provide O&M services. Although the Company cannot readily determine the potential cost to repurchase the interest in Auburndale Holdings, LLC, the carrying value at December 31, 2004, of its aggregate partners’ interests was $79.1 million. The effective interest rate, after amortization of deferred financing charges, was 17.1% and 16.8% per annum at December 31, 2004 and 2003, respectively.
King City Power Plant — On April 29, 2003, the Company sold a preferred interest in a subsidiary that leases and operates the 120-megawatt King City Power Plant to GE Structured Finance for $82.0 million. As a result of adopting SFAS No. 150, approximately $82 million of mandatorily redeemable non-controlling

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
interest in the King City facility, which had previously been included within the balance sheet caption “Minority interests,” was reclassified to “Notes payable.” The distributions and accretion of issuance costs related to this preferred interest, which was previously reported as a component of “Minority interest expense” in the Consolidated Condensed Statements of Operations, was accounted for as interest expense. Distributions and related accretion associated with this preferred interest was $5.3 million for the six months ended December 31, 2003. As of December 31, 2003, there was $82.0 million outstanding under the preferred interest. The effective interest rate, after amortization of deferred financing charges, was 13.1% and 12.8% per annum at May 2004 (redemption date) and December 31, 2003, respectively. In connection with the acquisition of the King City Power Plant by CPIF in May 2004, which was subject to the Company’s pre-existing operating lease, proceeds from the sale of the Company’s Collateral Securities, which supported the lease payments, were used in part to redeem the balance due under this preferred interest. See Note 3 for a discussion of the Collateral Securities. The Company expensed approximately $1.2 million in deferred finance costs related to the original issuance of the preferred interest and paid a $3.0 million termination fee. These debt extinguishment costs were recorded in Other Expense.
Pursuant to the applicable transaction agreements, each of Calpine King City Cogen, LLC, Calpine Securities Company, L.P., a parent company of Calpine King City Cogen, LLC and Calpine King City, LLC, an indirect parent company of Calpine Securities Company, L.P., has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. The Company consolidates these entities.
Gilroy Energy Center, LLC — On September 30, 2003, GEC, a wholly owned subsidiary of the Company’s subsidiary GEC Holdings, LLC, completed an offering of $301.7 million of 4% Senior Secured Notes Due 2011 (see Note 16 for more information on this secured financing). In connection with this secured notes borrowing, the Company received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, due to certain preferential distributions to the third party. The preferential distributions are due semi-annually beginning in March 2004 through September 2011 and total approximately $113.3 million over the eight-year period. Although the Company cannot readily determine the potential cost to repurchase the interest in GEC Holdings, LLC, the carrying value at December 31, 2004, of its aggregate partners’ interests was $67.4 million. The effective interest rate, after amortization of deferred financing charges, was 12.2% and 11.3% per annum at December 31, 2004 and 2003, respectively.
Pursuant to the applicable transaction agreements, GEC has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. The Company consolidates this entity. The long-term power sales agreement with the CDWR has been acquired by GEC by means of a series of capital contributions by CES and certain of its affiliates and is an asset of GEC, and the Senior Secured Notes and preferred interest are liabilities of GEC, separate from the assets and liabilities of the Company and other subsidiaries of the Company. Aside from seven peaker power plants owned directly and the power sales agreement, GEC’s assets include cash and a 100% equity interest in each of Creed Energy Center, LLC (“Creed”) and Goose Haven Energy Center, LLC (“Goose Haven”) each of which is a wholly owned subsidiary of GEC. Each of Creed and Goose Haven has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. Creed and Goose Haven each have assets consisting of various power plants and other assets.

13. | Capital Lease Obligations

In the first quarter of 2004, CPIF, a related party, acquired the King City power plant from a third party in a transaction that closed May 19, 2004. See Note 9 for a discussion of the Company’s relationship with CPIF. CPIF became the new lessor of the facility, which it purchased subject to the Company’s pre-existing

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
operating lease. The Company restructured certain provisions of the operating lease, including a 10-year extension and the elimination of the collateral requirements necessary to support the original lease payments. The base term of the restructured lease expires in 2028 with a renewal option at the then fair market rental value of the facility. See Note 3 for more information on the elimination of the collateral requirements. Due to the lease extension and other modifications to the original lease, the lease was reevaluated under SFAS No. 13 and determined to be a capital lease. The present value of the minimum lease payments totaled approximately $114.9 million which represented more than 90% of the fair value of the facility. As a result, the Company recorded a capital lease asset of $114.9 million as property, plant and equipment in the Consolidated Balance Sheet. This asset will be depreciated over the 24 year base lease term. In recording the capital lease obligation, the outstanding deferred lease incentive liability ($53.7 million including the current portion as of December 31, 2003) recorded as part of the original operating lease transaction, and the prepaid operating lease payments asset ($69.4 million including the current portion as of December 31, 2003) accumulated under the original operating lease terms, were eliminated. The difference between these two balances on May 19, 2004 was approximately $19.9 million and is reflected as a discount to the $114.9 million capital lease obligation. This discount will be accreted as additional interest expense using the effective interest method over the 24 year lease term. The net capital lease obligation originally recorded as debt in the Consolidated Balance Sheet was $94.9 million.
The Company assumed and consolidated its other capital leases in conjunction with certain acquisitions that occurred during 2001. As of December 31, 2004 and 2003, the asset balances for the leased assets totaled $322.3 million and $201.5 million, respectively, with accumulated amortization of $41.8 million and $26.0 million, respectively. Of these balances as of December 31, 2004, $114.9 million of leased assets and $2.7 million of accumulated amortization related to the King City power plant, which is leased from a related party. The primary types of property leased by the Company are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The lease terms range up to 28 years. Some of the lease agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project financing agreements. In determining whether a lease qualifies for capital lease treatment, in accordance with SFAS No. 13, the Company includes all increases due to step rent provisions/escalation clauses in its minimum lease payments for its capital lease obligations. Certain capital improvements associated with leased facilities may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Lease concessions including taxes and insurance are excluded from the minimum lease payments. The Company’s minimum lease payments are not tied to an existing variable index or rate.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2004 (in thousands):

|  | King City |  |  |  |  |
|  | Capital Lease |  |  |  |  |
|  | with related |  |  | Other Capital |  |  |
|  | party |  |  | Leases |  |  | Total |
Years Ending December 31: |  |  |  |  |  |  |  |  |  |  |  |
| 2005 |  | $ | 16,699 |  |  | $ | 19,154 |  |  | $ | 35,853 |
| 2006 |  |  | 16,458 |  |  |  | 19,760 |  |  |  | 36,218 |
| 2007 |  |  | 16,552 |  |  |  | 19,918 |  |  |  | 36,470 |
| 2008 |  |  | 16,199 |  |  |  | 21,753 |  |  |  | 37,952 |
| 2009 |  |  | 16,592 |  |  |  | 21,600 |  |  |  | 38,192 |
| Thereafter |  |  | 175,492 |  |  |  | 268,317 |  |  |  | 443,809 |
|  | Total minimum lease payments |  |  | 257,992 |  |  |  | 370,502 |  |  |  | 628,494 |
Less: Amount representing interest(1) |  |  | 162,095 |  |  |  | 177,480 |  |  |  | 339,575 |
| Present value of net minimum lease payments |  |  | 95,897 |  |  |  | 193,022 |  |  |  | 288,919 |
Less: Capital lease obligation, current portion |  |  | 1,199 |  |  |  | 4,291 |  |  |  | 5,490 |
| Capital lease obligation, net of current portion |  | $ | 94,698 |  |  | $ | 188,731 |  |  | $ | 283,429 |

(1) | Amount necessary to reduce net minimum lease payments to present value calculated at the incremental borrowing rate at the time of acquisition.

14. | CCFC I Financing

The components of CCFC I financing as of December 31, 2004 and 2003, are (in thousands):

|  | Outstanding at |
|  | December 31, |
|  | 2004 |  |  | 2003 |
Calpine Construction Finance Company I Second Priority Senior Secured Floating Rate Notes Due 2011 |  | $ | 408,568 |  |  | $ | 407,598 |
| First Priority Secured Institutional Term Loans Due 2009 |  |  | 378,182 |  |  |  | 381,391 |
|  | Total |  |  | 786,750 |  |  |  | 788,989 |
Less: Current portion |  |  | 3,208 |  |  |  | 3,208 |
CCFC I financing, net of current portion |  | $ | 783,542 |  |  | $ | 785,781 |

In November 1999, the Company entered into a credit agreement for $1.0 billion through its wholly owned subsidiary CCFC I with a consortium of banks. The lead arranger was The Bank of Nova Scotia and the lead arranger syndication agent was Credit Suisse First Boston. The non-recourse credit facility was utilized to finance the construction of certain of the Company’s gas-fired power plants. The Company repaid the outstanding balance of $880.1 million in August 2003.
On August 14, 2003, the Company’s wholly owned subsidiaries, CCFC I and CCFC Finance Corp., closed a $750.0 million institutional term loans and secured notes offering, proceeds from which were utilized to repay a majority of CCFC I’s indebtedness which would have matured in the fourth quarter of 2003. The offering included $385.0 million of First Priority Secured Institutional Term Loans Due 2009 (the “CCFC I Term Loans”) offered at 98% of par and priced at LIBOR plus 600 basis points, with a LIBOR floor of

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
150 basis points, and $365.0 million of Second Priority Senior Secured Floating Rate Notes Due 2011 (the “CCFC I Senior Notes”) offered at 98.01% of par and priced at LIBOR plus 850 basis points, with a LIBOR floor of 125 basis points. On September 25, 2003, CCFC I and CCFC Finance Corp. closed on an additional $50.0 million of the CCFC I Senior Notes offered at 99% of par. The noteholders’ recourse is limited to seven of CCFC I’s natural gas-fired electric generating facilities located in various power markets in the United States, and related assets and contracts. S&P has assigned a B corporate credit rating to CCFC I. S&P also assigned a B+ rating (with a negative outlook) to the CCFC I Term Loans and a B- rating (with a negative outlook) to the CCFC I Senior Notes. The interest rate of the CCFC I Senior Notes was 10.5% at December 31, 2004, and 9.8% at December 31, 2003. The effective interest rate, after amortization of deferred financing costs, was 10.8% per annum at December 31, 2004, and 10.0% at December 31, 2003. The interest rate of the CCFC I Term Loans was 8.4% at December 31, 2004, and 7.5% at December 31, 2003. The effective interest rate, after amortization of deferred financing costs, was 8.5% per annum at December 31, 2004, and 8.2% at December 31, 2003.

15. | CalGen/ CCFC II Financing

The components of CalGen/ CCFC II financing as of December 31, 2004 and 2003, are (in thousands):

|  |  |  | Letters of Credit |
|  | Outstanding at |  |  | Outstanding at |
|  | December 31, |  |  | December 31, |
|  | 2004 |  |  | 2003 |  |  | 2004 |  |  | 2003 |
Calpine Generating Company, LLC |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Third Priority Secured Floating Rate Notes Due 2011 |  | $ | 680,000 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
| Second Priority Secured Floating Rate Notes Due 2010 |  |  | 631,639 |  |  |  | — |  |  |  | — |  |  |  | — |
| First Priority Secured Term Loans Due 2009 |  |  | 600,000 |  |  |  | — |  |  |  | — |  |  |  | — |
| First Priority Secured Floating Rate Notes Due 2009 |  |  | 235,000 |  |  |  | — |  |  |  | — |  |  |  | — |
| Third Priority Secured Fixed Rate Notes Due 2011 |  |  | 150,000 |  |  |  | — |  |  |  | — |  |  |  | — |
| Second Priority Secured Term Loans Due 2010 |  |  | 98,693 |  |  |  | — |  |  |  | — |  |  |  | — |
| First Priority Secured Revolving Loans |  |  | — |  |  |  | — |  |  |  | 189,958 |  |  |  | — |
Calpine Construction Finance Company II Revolver |  |  | — |  |  |  | 2,200,358 |  |  |  | — |  |  |  | 53,190 |
Total CalGen/ CCFC II financing |  | $ | 2,395,332 |  |  | $ | 2,200,358 |  |  | $ | 189,958 |  |  | $ | 53,190 |

In October 2000, the Company entered into a credit agreement for $2.5 billion through its wholly owned subsidiary Calpine Construction Finance Company II, LLC (“CCFC II”) with a consortium of banks. The lead arrangers were The Bank of Nova Scotia and Credit Suisse First Boston. The non-recourse credit facility was utilized to finance the construction of certain of the Company’s gas-fired power plants. The interest rate at December 31, 2003 was 2.6%. The interest rate ranged from 2.6% to 4.8% during 2004 and 2.6% to 2.9% during 2003. The effective interest rate, after amortization of deferred financing costs, was 7.2% and 3.4% per annum at December 31, 2004 and 2003, respectively.
On March 23, 2004, the Company’s wholly owned subsidiary Calpine Generating Company, LLC (“CalGen”), formerly known as CCFC II, completed its offering of secured term loans and secured notes. As expected, the Company realized net total proceeds from the offerings (after payment of transaction fees and

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
expenses, including the fee payable to Morgan Stanley in connection with an index hedge) in the approximate amount of $2.3 billion. The interest rates associated with the instruments are as follows:

Description |  | Interest Rate |
First Priority Secured Floating Rate Notes Due 2009 |  |  | LIBOR plus 375 basis points |
Second Priority Secured Floating Rate Notes Due 2010 |  |  | LIBOR plus 575 basis points |
Third Priority Secured Floating Rate Notes Due 2011 |  |  | LIBOR plus 900 basis points |
Third Priority Secured Notes Due 2011 |  |  | 11.50% |
First Priority Secured Term Loans due 2009 |  |  | LIBOR plus 375 basis points(1) |
Second Priority Secured Term Loans due 2010 |  |  | LIBOR plus 575 basis points(2) |

(1) | The Company may also elect a Base Rate plus 275 basis points.
(2) | The Company may also elect a Base Rate plus 475 basis points.

The secured term loans and secured notes described above in each case are collateralized, through a combination of pledges of the equity interests in CalGen and its first tier subsidiary, CalGen Expansion Company, liens on the assets of CalGen’s power generating facilities (other than its Goldendale facility) and related assets located throughout the United States. The lenders’ recourse is limited to such collateral, and none of the indebtedness is guaranteed by Calpine. Net proceeds from the offerings were used to refinance amounts outstanding under the $2.5 billion CCFC II revolving construction credit facility, which was scheduled to mature in November 2004, and to pay fees and transaction costs associated with the refinancing. Concurrently with this refinancing, the Company amended and restated the CCFC II credit facility (as amended and restated, the “CalGen revolving credit facility”) to reduce the commitments under the facility to $200.0 million and extend its maturity to March 2007. Borrowings under the CalGen revolving credit facility bear interest at LIBOR plus 350 basis points (or, at the Company’s election, the Base Rate plus 250 basis points). Interest rates and effective interest rates, after amortization of deferred financing costs are as follows:

|  |  |  | 2004 Effective Interest |
|  | Interest Rate at |  |  | Rate after Amortization of |
|  | December 31, 2004 |  |  | Deferred Financing Costs |
First Priority Secured Floating Rate Notes Due 2009 |  |  | 6.0 | % |  |  | 5.8 | %
Second Priority Secured Floating Rate Notes Due 2010 |  |  | 8.0 | % |  |  | 8.1 | %
Third Priority Secured Floating Rate Notes Due 2011 |  |  | 11.2 | % |  |  | 10.9 | %
Third Priority Secured Fixed Rate Notes Due 2011 |  |  | 11.5 | % |  |  | 11.8 | %
First Priority Secured Term Loans Due 2009 |  |  | 6.0 | % |  |  | 5.8 | %
Second Priority Secured Term Loans Due 2010 |  |  | 8.0 | % |  |  | 8.0 | %
First Priority Secured Revolving Loans |  |  | — |  |  |  | 17.5 | %

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

16. | Other Construction/ Project Financing

The components of the Company’s other construction/project financing as of December 31, 2004 and 2003, are (in thousands):

|  |  |  | Letters of Credit
|  | Outstanding at |  |  | Outstanding at
|  | December 31, |  |  | December 31,
Projects |  | 2004 |  |  | 2003 |  |  | 2004 |  |  | 2003
Riverside Energy Center, LLC |  | $ | 368,500 |  |  | $ | 165,347 |  |  | $ | — |  |  | $ | — |
Pasadena Cogeneration, L.P. |  |  | 282,896 |  |  |  | 289,115 |  |  |  | — |  |  |  | — |
Broad River Energy LLC |  |  | 275,112 |  |  |  | 291,612 |  |  |  | — |  |  |  | — |
Fox Energy Company LLC |  |  | 266,075 |  |  |  | — |  |  |  | 75,000 |  |  |  | — |
Rocky Mountain Energy Center, LLC |  |  | 264,900 |  |  |  | — |  |  |  | — |  |  |  | — |
Gilroy Energy Center, LLC, 4% Senior Secured Notes Due 2011 |  |  | 261,382 |  |  |  | 298,065 |  |  |  | — |  |  |  | — |
Aries Power Plant |  |  | 174,914 |  |  |  | — |  |  |  | — |  |  |  | — |
Blue Spruce Energy Center, LLC |  |  | 98,272 |  |  |  | 140,000 |  |  |  | — |  |  |  | — |
Otay Mesa Energy Center, LLC — Ground Lease |  |  | 7,000 |  |  |  | 7,000 |  |  |  | — |  |  |  | — |
Calpine Newark, LLC |  |  | — |  |  |  | 47,816 |  |  |  | — |  |  |  | — |
Calpine Parlin, LLC |  |  | — |  |  |  | 32,451 |  |  |  | — |  |  |  | — |
| Total |  |  | 1,999,051 |  |  |  | 1,271,406 |  |  | $ | 75,000 |  |  | $ | — |
Less: Current portion |  |  | 93,393 |  |  |  | 61,900 |  |  |  |  |  |  |  |  |
Long-term construction/project financing |  | $ | 1,905,658 |  |  | $ | 1,209,506 |  |  |  |  |  |  |  |  |

Riverside Energy Center — On August 25, 2003, the Company announced that it had completed a $230.0 million non-recourse project financing for its 603-megawatt Riverside Energy Center. The natural gas-fueled electric generating facility is currently under construction in Beloit, Wisconsin. Upon completion of the project, which was scheduled for June 2004, Calpine was required to sell 450 megawatts of electricity to Wisconsin Power and Light under the terms of a nine-year tolling agreement and provide 75 megawatts of capacity to Madison Gas & Electric under a nine-year power sales agreement. A group of banks, including Credit Lyonnais, Co-Bank, Bayerische Landesbank, HypoVereinsbank and NordLB, were to finance construction of the plant at a rate of Libor plus 250 basis points. Upon commercial operation of the Riverside Energy Center, the banks were required to provide a three-year term-loan facility initially priced at Libor plus 275 basis points. The interest rate at refinancing on June 29, 2004, and December 31, 2003, was 3.7%. The interest rate ranged from 3.6% to 3.7% during 2004. The effective interest rate, after amortization of deferred financing costs, was 4.7% and 5.3% per annum at refinancing on June 29, 2004, and December 31, 2003, respectively. This facility was refinanced along with Rocky Mountain on June 29, 2004.
Pasadena Cogeneration, L.P. — In September 2000, the Company completed the financing, which matures in 2048, for both Phase I and Phase II of the Pasadena, Texas cogeneration project. Under the terms of the project financing, the Company received $400.0 million in gross proceeds. The interest rate at December 31, 2004 and 2003, was 8.6%.
Broad River Energy LLC — In October 2001, the Company completed the financing, which matures in 2041, for the Broad River Energy Center in South Carolina. Under the terms of the project financing, the Company received $300.0 million in gross proceeds. The interest rate at December 31, 2004 and 2003, was 7.9% and 8.1%, respectively.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fox Energy Company LLC — On November 19, 2004, the Company entered into a $400 million, 25-year, non-recourse sale/leaseback transaction with affiliates of GE Commercial Finance Energy Financial Services (“GECF”) for the 560-megawatt Fox Energy Center under construction in Wisconsin. The proceeds will be used to reimburse Calpine for construction capital spent to date on the project, to repay existing debt associated with equipment for the project and to complete the construction of the facility. Once construction is complete, the Company will lease the power plant from GECF under a 25-year facility lease. The Company also has an option to renew the lease for a 15-year term. Due to significant continuing involvement, as defined in SFAS No. 98, “Accounting for Leases,” the transaction does not currently qualify for sale lease-back accounting under that statement and has been accounted for as a financing. The proceeds received from GECF are recorded as debt in the Company’s consolidated balance sheet. The power plant assets will be depreciated over their estimated useful life and the lease payments will be applied to principal and interest expense using the effective interest method until such time as the Company’s continuing involvement is removed, expires or is otherwise eliminated. Once the Company no longer has significant continuing involvement in the power plant assets, the legal sale will be recognized for accounting purposes and the underlying lease will be evaluated and classified in accordance with SFAS No. 13. The effective interest rate at December 31, 2004 was 7.1%.
Rocky Mountain Energy Center, LLC — On February 20, 2004, the Company completed a $250.0 million, non-recourse project financing for the 621-megawatt Rocky Mountain Energy Center. A consortium of banks financed the construction of the plant at a rate of LIBOR plus 250 basis points. This loan was refinanced in June 2004, as described below.
Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC — On June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC, wholly owned stand-alone subsidiaries of the Company’s Calpine Riverside Holdings, LLC subsidiary, received funding in the aggregate amount of $661.5 million comprised of $633.4 million of First Priority Secured Floating Rate Term Loans Due 2011 priced at LIBOR plus 425 basis points and $28.1 million letter of credit-linked deposit facility. Net proceeds from the loans, after transaction costs and fees, were used to pay final construction costs and refinance amounts outstanding under the $250 million non-recourse project financing for the Rocky Mountain facility and the $230 million non-recourse project financing for the Riverside facility. In connection with this refinancing, the Company wrote off $13.2 million in deferred financing costs. In addition, approximately $160.0 million was used to reimburse the Company for costs incurred in connection with the development and construction of the Rocky Mountain and Riverside facilities. The Company also received approximately $79.0 million in proceeds via a combination of cash and increased credit capacity as a result of the elimination of certain reserves and cancellation of letters of credit associated with the original non-recourse project financings. The interest rate of the Rocky Mountain facility at December 31, 2004, was 8.6%. The interest rate of the Riverside facility at December 31, 2004 was 6.4%.
Gilroy Energy Center, LLC — On September 30, 2003, GEC, a wholly owned, stand-alone subsidiary of the Company’s subsidiary GEC Holdings, LLC, closed on $301.7 million of 4% Senior Secured Notes Due 2011. The senior secured notes are secured by GEC’s and its subsidiaries’ 11 peaking units located at nine power-generating sites in northern California. The notes also are secured by a long-term power sales agreement for 495 megawatts of peaking capacity with the CDRW, which is being served by the 11 peaking units. In addition, payment of the principal and interest on the notes when due is insured by an unconditional and irrevocable financial guaranty insurance policy that was issued simultaneously with the delivery of the notes. Proceeds of the notes offering (after payment of transaction expenses, including payment of the financial guaranty insurance premium, which are capitalized and included in deferred financing costs on the balance sheet) will be used to reimburse costs incurred in connection with the development and construction of the peaker projects. The noteholders’ recourse is limited to the financial guaranty insurance policy and, insofar as payment has not been made under such policy, to the assets of GEC and its subsidiaries. The Company has not guaranteed repayment of the notes. The effective interest rate, after amortization of deferred

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
financing charges, was 6.7% and 5.1% per annum at December 31, 2004 and 2003, respectively. In connection with this offering, the Company has received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0 million. See Note 12 for more information regarding this preferred interest.
Aries Power Plant — On March 26, 2004, in connection with the closing of the acquisition of the Aries Power Plant, the existing construction loan was converted to two term loans totaling $178.8 million. At December 31, 2004, Tranche A had an aggregate principal amount of $126.8 million, with quarterly payments maturing in December 2016. At December 31, 2004, Tranche B had an aggregate principal amount of $48.1 million, with quarterly payments maturing in December 2019. After taking interest rate swaps into consideration, the interest rates on Tranches A and B were 9.25% and 10.32%, respectively.
Blue Spruce Energy Center, LLC — On August 22, 2002, the Company completed a $106.0 million non-recourse project financing for the construction of its 285-megawatt Blue Spruce Energy Center. On November 7, 2003, the Company repaid the outstanding balance of $102.0 million with the proceeds of a new term financing described below.
On November 7, 2003, the Company completed a new $140.0 million term loan financing for the Blue Spruce Energy Center. The term loan is made up of two facilities, Tranche A and Tranche B, which have 15-year and 6-year repayment terms, respectively. At December 31, 2004, there was $98.3 million outstanding under Tranche A while Tranche B was repaid. The effective interest rate, after amortization of deferred financing costs, for Tranche A and Tranche B was 8.2% and 8.6%, respectively, per annum at December 31, 2003. The effective interest rate, after amortization of deferred financing costs, for Tranche A was 14.4% per annum at December 31, 2004.
Otay Mesa Energy Center, LLC — On July 8, 2003, Otay Mesa Generating Company, LLC, entered into a ground lease and easement agreement with D&D Landholdings, a Limited Partnership. The interest rate at December 31, 2004 and 2003 was 12.6%.
Calpine Newark, LLC and Calpine Parlin, LLC — In December 2002, the Company completed a $50.0 million project financing secured by the Newark Power Plant. This financing was fully repaid in May 2004 in connection with the contract termination discussed below. The interest rate at repayment in May 2004 and at December 31, 2003, was 10.6%.
In December 2002, the Company completed a $37.0 million project financing secured by the Parlin Power Plant. This financing was fully repaid in May 2004 in connection with the contract termination discussed below. The interest rate at repayment in May 2004 and at December 31, 2003, was 9.8%.
On May 26, 2004, the Company and Jersey Central Power & Light Company (“JCPL”) terminated their existing toll arrangements with the Newark and Parlin power plants, resulting in a pre-tax gain of $100.6 million. Proceeds from this transaction were used to retire project financing debt of $78.8 million. In conjunction with this termination, Utility Contract Funding II, LLC (“UCF”), a wholly owned subsidiary of CES, entered into a long-term PPA with JCPL. UCF was then sold. The Company recognized an $85.4 million pre-tax gain on the sale of UCF. The total pre-tax gain, net of transaction costs and the write-off of unamortized deferred financing costs, was $171.5 million.
California Peaker Financing — On May 14, 2002, the Company’s subsidiary, Calpine California Energy Finance, LLC, entered into an $100.0 million amended and restated credit agreement with ING Capital LLC for the funding of 9 California peaker facilities, of which $100.0 million was drawn on May 24, 2002, and $50.0 million was repaid on August 7, 2002, and the remaining $50.0 million was repaid on July 21, 2003. The interest rate ranged from 3.5% to 3.9% during 2003. The effective interest rate, after amortization of deferred financing costs, was 4.0% per annum at December 31, 2003.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

17. | Convertible Senior Notes

| 4% Convertible Senior Notes Due 2006

In December 2001 and January 2002, the Company completed the issuance of $1.2 billion in aggregate principal amount of 4% Convertible Senior Notes Due 2006 (“2006 Convertible Senior Notes”). These securities are convertible, at the option of the holder, into shares of Calpine common stock at a price of $18.07. Holders had the right to require the Company to repurchase all or a portion of the 2006 Convertible Senior Notes on December 26, 2004, at 100% of their principal amount plus any accrued and unpaid interest. The Company can repurchase the 2006 Convertible Senior Notes with cash, shares of Calpine common stock, or a combination of cash and stock. During 2004 and 2003 the Company repurchased approximately $658.7 million and $474.9 million in aggregate outstanding principal amount of the 2006 Convertible Senior Notes at a repurchase price of $657.7 million and $458.8 million plus accrued interest, respectively. Additionally, during 2003 approximately $65.0 million in aggregate outstanding principal amount of the 2006 Convertible Senior Notes were exchanged for 12.0 million shares of Calpine common stock in privately negotiated transactions. During 2004 and 2003 the Company recorded a pre-tax loss of $5.3 million and a pre-tax gain of $13.6 million, respectively, on these transactions, net of write-offs of the associated unamortized deferred financing costs and unamortized premiums or discounts. The effective interest rate on these notes at December 31, 2004 and 2003, after amortization of deferred financing costs, was 4.6% and 4.9% per annum, respectively. At December 31, 2004, approximately $1.3 million of the 2006 Convertible Senior Notes remain outstanding.

| 43/4% Contingent Convertible Senior Notes Due 2023

On November 17, 2003, the Company completed the issuance of $650 million of 2023 Convertible Senior Notes. These 2023 Convertible Senior Notes are convertible, at the option of holder, into cash and into shares of Calpine common stock at a price of $6.50 per share, which represents a 38% premium over the New York Stock Exchange closing price of $4.71 per Calpine common share on November 6, 2003. Holders have the right to require the Company to repurchase all or a portion of these securities on November 15, 2009, November 15, 2013, and November 15, 2018, at 100% of their principal amount plus any accrued and unpaid interest and liquidated damages, if any, up to the date of repurchase. Otherwise, conversion is subject to a common stock price condition where the Company’s common stock is trading for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the calendar quarter preceding the quarter in which the conversion occurs is more than 120% of the conversion price per share of the common stock in effect on that 30th trading day. Conversion is also subject to a trading price condition where during the five trading day period after any five consecutive trading day period in which the trading price of $1,000 principal amount of the notes for each day of such five-day period was less than 95% of the product of the closing sale price of our common stock price on that day multiplied by the Conversion Rate. Note holders have a limited amount of time to convert their notes once a conversion condition has been achieved. Generally, upon conversion of the notes the Company is required to deliver the par value of the notes in cash and any additional conversion value in Calpine common stock. However, if the notes are put back to the Company on November 15, 2009, November 15, 2013 or November 15, 2018, the Company has the right to pay the repurchase price in cash, shares of Calpine common stock, or a combination of cash and stock.
On January 9, 2004, one of the initial purchasers of the 2023 Convertible Senior Notes exercised in full its option to purchase an additional $250.0 million of these notes. The notes are convertible into cash and into shares of Calpine common stock upon the occurrence of certain contingencies at an initial conversion price of $6.50 per share, which represents a 38% premium over the New York Stock Exchange closing price of $4.71 per share on November 6, 2003, the date the notes were originally priced.
During 2004, the Company repurchased approximately $266.2 million in aggregate outstanding principal amount of 2023 Convertible Senior Notes at a repurchase price of $177.0 million plus accrued interest. At December 31, 2004, there was $633.8 million in outstanding borrowings under these notes. The effective

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
interest rate on these notes, after amortization of deferred financing costs, was approximately 5.3% and 4.9% per annum at December 31, 2004 and 2003.

| 6% Contingent Convertible Notes Due 2014

On September 30, 2004, the Company closed on $736 million aggregate principal amount at maturity of 2014 Convertible Notes, offered at 83.9% of par. Net proceeds were used to repurchase certain outstanding Senior Notes, 2023 Convertible Senior Notes, and HIGH TIDES securities. The Company recorded a pre-tax gain on these transactions in the amount of $167.2 million, net of write-offs of unamortized deferred financing costs and the unamortized premiums or discounts.
The 2014 Convertible Notes are convertible into cash and into a variable number of shares of Calpine common stock based on a conversion value derived from the conversion price of $3.85 per share. The number of shares to be delivered upon conversion will be determined by the market price of Calpine common shares at the time of conversion. However, conversion is subject to a common stock price condition where the Company’s common stock is trading for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the calendar quarter preceding the quarter in which the conversion occurs is more than 120% of the conversion price per share of the common stock in effect on the 30th trading day. Conversion is also subject to a trading price condition where during the five trading day period after any five consecutive trading day period in which the trading price of $1,000 principal amount at maturity of the notes for each day of such five-day period was less than 95% of the product of the closing sale price of our common stock price on that day multiplied by the Conversion Rate. Note holders have a limited amount of time to convert their notes once a conversion condition has been achieved.
The conversion price of $3.85 per share represents a premium of approximately 23% over The New York Stock Exchange closing price of $3.14 per Calpine common share on September 27, 2004. The 2014 Convertible Notes will pay Contractual cash interest at a rate of 6%, except that in years three, four and five, in lieu of interest, the original principal amount of $839 per note will accrete daily beginning September 30, 2006, to the full principal amount of $1,000 per note at September 30, 2009. For accounting purposes, the Company has calculated the effective interest rate of the 2014 Convertible Notes capturing the 6% stated rate and the 16.1% discount and is recording interest expense over the 10-year term of the instrument using the effective interest method in accordance with paragraph 13-15 of APB Opinion No. 21, “Interest on Receivables and Payables.” Upon conversion of the 2014 Convertible Notes, the Company is required to deliver the accreted principal amount of the notes in cash and any additional conversion value in Calpine common stock. However, in certain events of default the Company is required to deliver the par value of the notes in Calpine common stock.
At December 31, 2004, there was $620.2 million in outstanding borrowings under these notes. The effective interest rate on these notes, after amortization of deferred financing costs, was approximately 6.3% per annum at December 31, 2004.
In conjunction with the 2014 Convertible Notes offering, the Company entered into a ten-year Share Lending Agreement with Deutsche Bank AG London (“DB London”), under which the Company loaned DB London 89 million shares of newly issued Calpine common stock (the “loaned shares”) in exchange for a loan fee of $.001 per share. DB London sold the entire 89 million shares on September 30, 2004, at a price of $2.75 per share in a registered public offering. The Company did not receive any of the proceeds of the public offering. DB London is required to return the loaned shares to the Company no later than the end of the ten-year term of the Share Lending Agreement, or earlier under certain circumstances. Once loaned shares are returned, they may not be re-borrowed under the Share Lending Agreement. Under the Share Lending Agreement, DB London is required to post and maintain collateral in the form of cash, government securities, certificates of deposit, high-grade commercial paper of U.S. issuers or money market shares at least equal to 100% of the market value of the loaned shares as security for the obligation of DB London to return the loaned

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
shares to the Company. This collateral is held in an account at a DB London affiliate. The Company has no access to the collateral unless DB London defaults under its obligations.
The Share Lending Agreement is similar to an accelerated share repurchase transaction which is addressed by EITF Issue No. 99-07, “Accounting for an Accelerated Share Repurchase Program.” This EITF issue requires an accelerated share repurchase transaction to be accounted for as two transactions: a treasury stock purchase and a forward sales contract. The Share Lending Agreement involved the issuance of 89 million shares of the Company’s common stock in exchange for a physically settling forward contract for the reacquisition of the shares at a future date. We recorded the issuance of shares in equity at the fair value of the Calpine common stock on the date of issuance in the amount of $258.1 million. As there was minimal cash consideration in the transaction, the requirement to the return of these shares is considered to be a prepaid forward purchase contract. We have evaluated the prepaid forward contract under the guidance of SFAS No. 133, and determined that the instrument was not a derivative in its entirety and that the embedded derivative would not require separate accounting. The hybrid contract was classified similar to a shareholder loan which was recorded in equity at the fair value of the Calpine common stock on the date of issuance in the amount of $258.1 million.
Under SFAS No. 150, entities that have entered into a forward contract that requires physical settlement by repurchase of a fixed number of the issuer’s equity shares of common stock in exchange for cash shall exclude the common shares to be redeemed or repurchased when calculating basic and diluted EPS. The Share Lending Agreement does not provide for cash settlement, but rather physical settlement is required (i.e. the shares must be returned by the end of the arrangement). The Company analogizes to the guidance in SFAS No. 150 such that the prepaid forward contract results in a reduction in the number of outstanding shares used to calculate basic and diluted EPS. Consequently, the 89 million shares of common stock subject to the Share Lending Agreement are excluded from the earnings per share EPS calculation.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

18. | Senior Notes

Senior Notes payable consist of the following as of December 31, 2004 and 2003, (in thousands):

|  |  |  |  |  |  |  | Fair Value as of |
|  |  |  |  |  | December 31, |  |  | December 31, (3) |
|  | Interest |  |  | First Call |  |  |  |  |  |  |
|  | Rates |  |  | Date |  |  | 2004 |  |  | 2003 |  |  | 2004 |  |  | 2003 |
First Priority Senior Secured Notes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| First Priority Senior Secured Notes Due 2014 |  |  | 95/8 | % |  |  |  | (12) |  | $ | 778,971 |  |  | $ | — |  |  | $ | 801,367 |  |  | $ | — |
| First Priority Senior Secured Term Loan B Notes Due 2007 |  |  |  | (4) |  |  |  | (2) |  |  | — |  |  |  | 199,500 |  |  |  | — |  |  |  | 202,243 |
|  | Total First Priority Senior Secured Notes |  |  |  |  |  |  |  |  |  |  | 778,971 |  |  |  | 199,500 |  |  |  | 801,367 |  |  |  | 202,243 |
| Second Priority Senior Secured Notes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Second Priority Senior Secured Term Loan B Notes Due 2007 |  |  |  | (5) |  |  |  | (8) |  |  | 740,625 |  |  |  | 748,125 |  |  |  | 677,672 |  |  |  | 727,552 |
| Second Priority Senior Secured Floating Rate Notes Due 2007 |  |  |  | (6) |  |  |  | (7) |  |  | 493,750 |  |  |  | 498,750 |  |  |  | 449,313 |  |  |  | 488,775 |
| Second Priority Senior Secured Notes Due 2010 |  |  | 81/2 | % |  |  |  | (7) |  |  | 1,150,000 |  |  |  | 1,150,000 |  |  |  | 987,563 |  |  |  | 1,127,000 |
| Second Priority Senior Secured Notes Due 2013 |  |  | 83/4 | % |  |  |  | (7) |  |  | 900,000 |  |  |  | 900,000 |  |  |  | 740,250 |  |  |  | 877,500 |
| Second Priority Senior Secured Notes Due 2011 |  |  | 97/8 | % |  |  |  | (1) |  |  | 393,150 |  |  |  | 392,159 |  |  |  | 344,006 |  |  |  | 401,963 |
|  | Total Second Priority Senior Secured Notes |  |  |  |  |  |  |  |  |  |  | 3,677,525 |  |  |  | 3,689,034 |  |  |  | 3,198,804 |  |  |  | 3,622,790 |
Unsecured Senior Notes |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Senior Notes Due 2005 |  |  | 81/4 | % |  |  |  | (2) |  |  | 185,949 |  |  |  | 224,679 |  |  |  | 188,424 |  |  |  | 215,692 |
| Senior Notes Due 2006 |  |  | 101/2 | % |  |  | 2001 |  |  |  | 152,695 |  |  |  | 166,575 |  |  |  | 151,359 |  |  |  | 163,243 |
| Senior Notes Due 2006 |  |  | 75/8 | % |  |  |  | (1) |  |  | 111,563 |  |  |  | 214,613 |  |  |  | 109,332 |  |  |  | 191,006 |
| Senior Notes Due 2007 |  |  | 83/4 | % |  |  | 2002 |  |  |  | 195,305 |  |  |  | 226,120 |  |  |  | 177,728 |  |  |  | 187,679 |
| Senior Notes Due 2007(9) |  |  | 83/4 | % |  |  |  | (2) |  |  | 165,572 |  |  |  | 154,120 |  |  |  | 150,671 |  |  |  | 114,049 |
| Senior Notes Due 2008 |  |  | 77/8 | % |  |  |  | (1) |  |  | 227,071 |  |  |  | 305,323 |  |  |  | 191,875 |  |  |  | 236,624 |
| Senior Notes Due 2008 |  |  | 81/2 | % |  |  |  | (2) |  |  | 1,581,539 |  |  |  | 1,925,067 |  |  |  | 1,347,472 |  |  |  | 1,540,053 |
| Senior Notes Due 2008(10) |  |  | 83/8 | % |  |  |  | (2) |  |  | 160,050 |  |  |  | 154,140 |  |  |  | 121,638 |  |  |  | 114,064 |
| Senior Notes Due 2009 |  |  | 73/4 | % |  |  |  | (1) |  |  | 221,539 |  |  |  | 232,520 |  |  |  | 177,231 |  |  |  | 179,041 |
| Senior Notes Due 2010 |  |  | 85/8 | % |  |  |  | (2) |  |  | 496,973 |  |  |  | 496,909 |  |  |  | 402,548 |  |  |  | 390,074 |
| Senior Notes Due 2011 |  |  | 81/2 | % |  |  |  | (2) |  |  | 1,063,850 |  |  |  | 1,179,911 |  |  |  | 792,568 |  |  |  | 932,130 |
| Senior Notes Due 2011(11) |  |  | 87/8 | % |  |  |  | (2) |  |  | 232,511 |  |  |  | 215,242 |  |  |  | 167,989 |  |  |  | 157,127 |
|  | Total Unsecured Senior Notes |  |  |  |  |  |  |  |  |  |  | 4,794,617 |  |  |  | 5,495,219 |  |  |  | 3,978,835 |  |  |  | 4,420,782 |
|  |  | Total Senior Notes |  |  |  |  |  |  |  |  |  |  | 9,251,113 |  |  |  | 9,383,753 |  |  |  | 7,979,006 |  |  |  | 8,245,815 |
|  |  | Less: Senior Notes, current portion |  |  |  |  |  |  |  |  |  |  | 718,449 |  |  |  | 14,500 |  |  |  | 198,449 |  |  |  | 14,500 |
|  |  |  | Senior Notes, net of current portion |  |  |  |  |  |  |  |  |  | $ | 8,532,664 |  |  | $ | 9,369,253 |  |  | $ | 7,780,557 |  |  | $ | 8,231,315 |

| (1) | Not redeemable prior to maturity.
| (2) | Redeemable by the Company at any time prior to maturity.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| (3) | Represents the market values of the Senior Notes at the respective dates.
| (4) | 3-month US$ LIBOR, plus a spread.
| (5) | U.S. Prime Rate in combination with the Federal Funds Effective Rate, plus a spread.
| (6) | British Bankers Association LIBOR Rate for deposit in U.S. dollars for a period of three months, plus a spread.
| (7) | At any time before July 15, 2005, with respect to the Second Priority Senior Secured Floating Rate Notes Due 2007 (the “2007 notes”) and before July 15, 2006, with respect to the Second Priority Senior Secured Notes Due 2010 (the “2010 notes”) and the Second Priority Senior Secured Notes Due 2013 (the “2013 notes”), on one or more occasions, the Company can choose to redeem up to 35% of the outstanding principal amount of the applicable series of notes, including any additional notes issued in such series, with the net cash proceeds of any one or more public equity offerings so long as (1) the Company pays holders of the notes a redemption price equal to par plus the applicable Eurodollar rate then in effect with respect to the 2007 notes, 108.500% with respect to the 2010 notes, and 108.750% with respect to the 2013 notes, at the face amount of the notes the Company redeems, plus accrued interest; (2) the Company must redeem the notes within 45 days of such public equity offering; and (3) at least 65% of the aggregate principal amount of the applicable series of notes originally issued under the applicable indenture, including the principal amount of any additional notes, remains outstanding immediately after each such redemption.
| (8) | The Company may not voluntarily prepay these notes prior to July 15, 2005, except that the Company may on any one or more occasions make such prepayment with the proceeds of one or more public equity offerings.
| (9) | Issued in Canadian dollars.

(10) | Issued in Euros.
(11) | Issued in Sterling.
(12) | The Company may redeem some or all of the notes at any time on or after October 1, 2009 at specified redemption prices. At any time prior to October 1, 2009, the Company may redeem some or all of the notes at a price equal to 100% of their principal amount and the applicable premium plus accrued and unpaid interest. In addition, at any time prior to October 1, 2007, the Company may redeem up to 35% of the aggregate principal amount of the notes with the net proceeds from one or more public equity offerings at a stated redemption price.

The Company has completed a series of public debt offerings since 1994. Interest is payable quarterly or semiannually at specified rates. Deferred financing costs are amortized using the effective interest method, over the respective lives of the notes. There are no sinking fund or mandatory redemptions of principal before the maturity dates of each offering. Certain of the Senior Note indentures limit the Company’s ability to incur additional debt, pay dividends, sell assets and enter into certain transactions. As of December 31, 2004, the Company was in compliance with all debt covenants relating to the Senior Notes. The effective interest rates for each of the Company’s Senior Notes outstanding at December 31, 2004, are consistent with the respective notes outstanding during 2003, unless otherwise noted.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Senior notes repurchased by the Company during 2004 and 2003 totaled $743.4 million and $1,378.5 million, respectively, in aggregate outstanding principal amount at a repurchase price of $559.3 million and $1,116.5 million, respectively, plus accrued interest. The Company recorded a pre-tax gain on these transactions in the amount of $177.6 million and $245.5 million, respectively, net of write-offs of unamortized deferred financing costs and the unamortized premiums or discounts. The following table summarizes the total senior notes repurchased by the Company in the year ended December 31, 2004 and 2003, respectively (in millions):

|  | 2004 |  |  | 2003 |
|  | Principal |  |  | Amount |  |  | Principal |  |  | Amount |
Debt Security |  | Amount |  |  | Paid |  |  | Amount |  |  | Paid |
81/4% Senior Notes Due 2005 |  | $ | 38.9 |  |  | $ | 34.9 |  |  | $ | 25.0 |  |  | $ | 24.5 |
101/2% Senior Notes Due 2006 |  |  | 13.9 |  |  |  | 12.4 |  |  |  | 5.2 |  |  |  | 5.1 |
75/8% Senior Notes Due 2006 |  |  | 103.1 |  |  |  | 96.5 |  |  |  | 35.3 |  |  |  | 32.5 |
83/4% Senior Notes Due 2007 |  |  | 30.8 |  |  |  | 24.4 |  |  |  | 48.9 |  |  |  | 45.0 |
77/8% Senior Notes Due 2008 |  |  | 78.4 |  |  |  | 56.5 |  |  |  | 74.8 |  |  |  | 58.3 |
81/2% Senior Notes Due 2008(1) |  |  | 344.3 |  |  |  | 249.4 |  |  |  | 48.3 |  |  |  | 42.3 |
83/8% Senior Notes Due 2008(1) |  |  | 6.1 |  |  |  | 4.0 |  |  |  | 59.2 |  |  |  | 46.6 |
73/4% Senior Notes Due 2009 |  |  | 11.0 |  |  |  | 8.1 |  |  |  | 97.2 |  |  |  | 75.9 |
85/8% Senior Notes Due 2010 |  |  | — |  |  |  | — |  |  |  | 210.4 |  |  |  | 170.7 |
81/2% Senior Notes Due 2011 |  |  | 116.9 |  |  |  | 73.1 |  |  |  | 648.4 |  |  |  | 521.3 |
87/8% Senior Notes Due 2011(1) |  |  | — |  |  |  | — |  |  |  | 125.8 |  |  |  | 94.3 |
|  | $ | 743.4 |  |  | $ | 559.3 |  |  | $ | 1,378.5 |  |  | $ | 1,116.5 |

(1) | $395.5 million of such repurchased notes have been pledged as security as part of the transactions relating to the issuance by Calpine (Jersey) Limited of Redeemable Preferred Shares. See Note 12 for additional information on such issuance of Redeemable Preferred Shares.

Additionally, senior notes totaling $80.0 million in principal amount were exchanged for 11.5 million shares of Calpine common stock in privately negotiated transactions during 2003. The Company recorded a $17.9 million pre-tax gain on these transactions, net of write-offs of unamortized deferred financing costs and the unamortized premiums or discounts. The following table summarizes the total senior notes exchanged for common stock by the Company in the year ended December 31, 2003 (in millions):

|  | Principal |  |  | Common Stock |
Debt Security |  | Amount |  |  | Issued |
81/2% Senior Notes Due 2008 |  | $ | 55.0 |  |  |  | 8.1 |
81/2% Senior Notes Due 2011 |  |  | 25.0 |  |  |  | 3.4 |
|  | $ | 80.0 |  |  |  | 11.5 |

| First Priority Senior Secured Notes Due 2014

On September 30, 2004, the Company closed on $785 million of 95/8% First-Priority Senior Secured Notes Due 2014 (“95/8% Senior Notes”), offered at 99.212% of par. The 95/8% Senior Notes are secured, by substantially all of the assets owned directly by Calpine Corporation, and by the stock of substantially all of its first-tier subsidiaries. Net proceeds from the 95/8% Senior Notes offering were used to make open-market purchases of the Company’s existing indebtedness and any remaining proceeds will be applied toward further open-market purchases (or redemption) of existing indebtedness and as otherwise permitted by the

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Company’s indentures. The Company may redeem some or all of the notes at any time on or after October 1, 2009 at specified redemption prices. At any time prior to October 1, 2009, the Company may redeem some or all of the notes at a price equal to 100% of their principal amount and the applicable premium plus accrued and unpaid interest. In addition, at any time prior to October 1, 2007, the Company may redeem up to 35% of the aggregate principal amount of the notes with the net proceeds from one or more public equity offerings at a stated redemption price. Interest is payable on these notes on April 1 and October 1 of each year, beginning on April 1, 2005. The notes will mature on September 30, 2014. At December 31, 2004, both the book and face value of these notes were $779.0 million and $785.0 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 10.0% per annum at December 31, 2004.

| First Priority Senior Secured Term Loan B Notes Due 2007

The Company was to repay these notes in 16 consecutive quarterly installments, commencing on October 15, 2003, and ending on July 15, 2007, the first fifteen of which were to be for 0.25% of the original principal amount of the notes thru April 15, 2007. These notes were redeemable at any time prior to maturity with certain provisions. These notes were repaid prior to their maturity with the proceeds from the sale of certain oil and gas properties during 2004. The effective interest rate, after amortization of deferred financing costs, was 5.2% and 5.0% per annum at December 31, 2004 and 2003, respectively.

| Second Priority Senior Secured Term Loan B Notes Due 2007

The Company must repay these notes in 16 consecutive quarterly installments, commencing on October 15, 2003, and ending on July 15, 2007, the first fifteen of which will be 0.25% of the original principal amount of the notes thru April 15, 2007. The final installment, on July 15, 2007, will be 96.25% of the original principal amount. Interest is payable on each quarterly payment date occurring after the closing date of July 16, 2003. The Company may not voluntarily prepay these notes prior to July 15, 2005, except that the Company may on any one or more occasions make such prepayment with the proceeds of one or more public equity offerings. At December 31, 2004, both the book and face value of these notes was $740.6 million. The effective interest rate, after amortization of deferred financing costs, was 7.8% and 7.5% per annum at December 31, 2004 and 2003, respectively.

| Second Priority Senior Secured Floating Rate Notes Due 2007

The Company must repay these notes in 16 consecutive quarterly installments, commencing on October 15, 2003, and ending on July 15, 2007, the first fifteen of which will be 0.25% of the original principal amount of the notes thru April 15, 2007. The final installment, on July 15, 2007, will be 96.25% of the original principal amount. On or before July 15, 2005, on one or more occasions, the Company may use the proceeds from one or more public equity offerings to redeem up to 35% of the aggregate principal amount of the notes at the stated redemption price of par plus the applicable Eurodollar rate in effect at the time of redemption. Interest is payable on each quarterly payment date occurring after the closing date of July 16, 2003. At December 31, 2004, both the book and face value of these notes was $493.8 million. The effective interest rate, after amortization of deferred financing costs, was 7.8% and 7.4% per annum at December 31, 2004 and 2003, respectively.

| Second Priority Senior Secured Notes Due 2010

Interest is payable on these notes on January 15 and July 15 of each year. The notes will mature on July 15, 2010. On or before July 15, 2006, on one or more occasions, the Company may use the proceeds from one or more public equity offerings to redeem up to 35% of the aggregate principal amount of the notes at the stated redemption price of 108.5%. At December 31, 2003, both the book and face value of these notes were

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$1,150.0 million. The effective interest rate, after amortization of deferred financing costs, was 8.9% and 8.8% per annum at December 31, 2004 and 2003, respectively.

| Second Priority Senior Secured Notes Due 2011

Interest is payable on these notes on June 1 and December 1 of each year, commencing on June 1, 2004. The notes will mature on December 1, 2011, and are not redeemable prior to maturity. At December 31, 2004, the book and face value of these notes were $393.2 million and $400.0 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 10.7% and 10.5% per annum at December 31, 2004 and 2003, respectively.

| Second Priority Senior Secured Notes Due 2013

Interest is payable on these notes on January 15 and July 15 of each year. The notes will mature on July 15, 2013. On or before July 15, 2006, on one or more occasions, the Company may use the proceeds from one or more public equity offerings to redeem up to 35% of the aggregate principal amount of the notes at the stated redemption price of 108.75%. At December 31, 2004, both the book and face value of these notes were $900.0 million. The effective interest rate, after amortization of deferred financing costs, was 9.0% per annum at December 31, 2004 and 2003.

| Senior Notes Due 2005

Interest on the 81/4% notes is payable semi-annually on February 15 and August 15. The notes mature on August 15, 2005, or may be redeemed at any time prior to maturity at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2004, the book value and face value of these notes were $185.9 million and $186.1 million, respectively. The effective interest rate, after amortization of deferred financing costs, is 8.7% per annum.

| Senior Notes Due 2006

Interest on the 101/2% notes is payable semi-annually on May 15 and November 15 each year. The notes mature on May 15, 2006, or are redeemable, at the option of the Company, at any time on or after May 15, 2001, at various redemption prices. In addition, the Company may redeem up to $63.0 million of the Senior Notes Due 2006 from the proceeds of any public equity offering. At December 31, 2004, both the book value and face value of these notes were $152.7 million. The effective interest rate, after amortization of deferred financing costs, was 11.0% per annum at December 31, 2004, and 10.6% per annum at December 31, 2003.
Interest on the 75/8% notes is payable semi-annually on April 15 and October 15 each year. The notes mature on April 15, 2006, and are not redeemable prior to maturity. At December 31, 2004, the book value and face value of these notes were $111.6 million. The effective interest rate, after amortization of deferred financing costs, was 8.0% and 7.9% per annum at December 31, 2004 and 2003, respectively.

| Senior Notes Due 2007

Interest on the 83/4% notes maturing on July 15, 2007, is payable semi-annually on January 15 and July 15 each year. These notes are redeemable, at the option of the Company, at any time on or after July 15, 2002, at various redemption prices. In addition, the Company may redeem up to $96.3 million of the Senior Notes Due 2007 from the proceeds of any public equity offering. At December 31, 2004, both the book value and face value of these notes were $195.3 million. The effective interest rate, after amortization of deferred financing costs, was 9.2% and 9.1% per annum at December 31, 2004 and 2003, respectively.
Interest on the 83/4% notes maturing on October 15, 2007, is payable semi-annually on April 15 and October 15 each year. The notes may be redeemed prior to maturity, at any time in whole or from time to time

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
in part, at a redemption price equal to the greater of (a) the “Discounted Value” of the senior notes, which equals the sum of the present values of all remaining scheduled payments of principal and interest, or (b) 100% of the principal amount plus accrued and unpaid interest to the redemption date. The notes are fully and unconditionally guaranteed by the Company. At December 31, 2004, the book value and face value of these notes were $165.6 million and $166.0 million, respectively. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 9.4% at December 31, 2004, and 8.9% at December 31, 2003.

| Senior Notes Due 2008

Interest on the 77/8% notes is payable semi-annually on April 1 and October 1 each year. These notes mature on April 1, 2008, and are not redeemable prior to maturity. At December 31, 2004, the book value and face value of these notes were $227.1 million and $227.3 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 8.1% per annum at December 31, 2004 and 2003. The notes are fully and unconditionally guaranteed by the Company.
Interest on the 81/2% notes is payable semi-annually on May 1 and November 1 each year. The notes mature on May 1, 2008, or may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2004, the book value and face value of these notes were $1,581.5 million and $1,582.4 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 8.8% per annum at December 31, 2004, and 8.7% per annum at December 31, 2003.
Interest on the 83/8% notes is payable semi- annually on April 15 and October 15 each year. The notes mature on October 15, 2008, or may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2004, both the book value and face value of these notes were $160.0 million. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 8.6% per annum at December 31, 2004, and 8.7% per annum at December 31, 2003.

| Senior Notes Due 2009

Interest on these 73/4% notes is payable semi-annually on April 15 and October 15 each year. The notes mature on April 15, 2009, and are not redeemable prior to maturity. At December 31, 2003, the book value and face value of these notes were $221.5 million and $221.6 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 8.0% per annum at December 31, 2004 and 2003.

| Senior Notes Due 2010

Interest on these 85/8% notes is payable semi-annually on August 15 and February 15 each year. The notes mature on August 15, 2010, and may be redeemed at any time prior to maturity at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2004, the book value and face value of these notes were $497.0 million and $497.3 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 8.8% per annum.

| Senior Notes Due 2011

Interest on the 81/2% notes is payable semi-annually on February 15 and August 15 each year. The notes mature on February 15, 2011, and may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2004, the book value and face value of these notes were $1,063.9 million and $1,088.6 million, respectively. The

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
effective interest rate, after amortization of deferred financing costs, was 8.4% and 8.7% per annum at December 31, 2004 and 2003, respectively.
Interest on the 87/8% notes is payable semi-annually on April 15 and October 15 each year. The notes mature on October 15, 2011, and may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2004, the book value and face value of these notes were $232.5 million and $233.9 million, respectively. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 9.3% per annum at December 31, 2004, and 9.4% per annum at December 31, 2003.

19. | Provision for Income Taxes

The jurisdictional components of income (loss) from continuing operations and before provision for income taxes at December 31, 2004, 2003, and 2002, are as follows (in thousands):

|  | 2004 |  |  | 2003 |  |  | 2002 |
U.S. |  | $ | (552,849 | ) |  | $ | 35,207 |  |  | $ | 25,225 |
International |  |  | (164,526 | ) |  |  | 59,398 |  |  |  | 12,332 |
| Income (loss) before provision for income taxes |  | $ | (717,375 | ) |  | $ | 94,605 |  |  | $ | 37,557 |

The components of the provision (benefit) for income taxes for the years ended December 31, 2004, 2003, and 2002, consists of the following (in thousands):

|  | 2004 |  |  | 2003 |  |  | 2002 |
Current: |  |  |  |  |  |  |  |  |  |  |  |
| Federal |  | $ | — |  |  | $ | 350 |  |  | $ | (72,835 | )
| State |  |  | 1,198 |  |  |  | (21,305 | ) |  |  | 3,837 |
| Foreign |  |  | 9,975 |  |  |  | — |  |  |  | — |
|  | Total Current |  |  | 11,173 |  |  |  | (20,955 | ) |  |  | (68,998 | )
Deferred: |  |  |  |  |  |  |  |  |  |  |  |
| Federal |  |  | (161,542 | ) |  |  | 413 |  |  |  | 75,377 |
| State |  |  | (6,194 | ) |  |  | 23,089 |  |  |  | 13,964 |
| Foreign |  |  | (119,986 | ) |  |  | 5,948 |  |  |  | (9,508 | )
|  | Total Deferred |  |  | (287,722 | ) |  |  | 29,450 |  |  |  | 79,833 |
|  |  | Total provision (benefit) |  | $ | (276,549 | ) |  | $ | 8,495 |  |  | $ | 10,835 |

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
A reconciliation of the Company’s overall actual effective tax rate (benefit) to the statutory U.S. Federal income tax rate of 35% to pretax income from continuing operations is as follows for the years ended December 31:

|  | 2004 |  |  | 2003 |  |  | 2002 |
Expected tax (benefit) rate at United States statutory tax rate |  |  | (35.00 | )% |  |  | 35.00 | % |  |  | 35.00 | %
State income tax (benefit), net of federal benefit |  |  | (0.45 | )% |  |  | 1.23 | % |  |  | 30.81 | %
Depletion and other permanent items |  |  | 1.38 | % |  |  | 0.90 | % |  |  | (0.20 | )%
Valuation allowances |  |  | (4.84 | )% |  |  | — |  |  |  | — |
Tax credits |  |  | (0.21 | )% |  |  | (2.62 | )% |  |  | — |
Foreign tax at rates other than U.S. statutory rate |  |  | 0.57 | % |  |  | (34.44 | )% |  |  | (36.76 | )%
Other, net (including U.S. tax on Foreign Income) |  |  | — |  |  |  | 8.91 | % |  |  | — |
Effective income tax (benefit) rate |  |  | (38.55 | )% |  |  | 8.98 | % |  |  | 28.85 | %

The components of the deferred income taxes, net as of December 31, 2004 and 2003, are as follows (in thousands):

|  | 2004 |  |  | 2003 |
Deferred tax assets: |  |  |  |  |  |  |  |
Net operating loss and credit carryforwards |  | $ | 1,098,446 |  |  | $ | 478,118 |
Taxes related to risk management activities and SFAS No. 133 |  |  | 77,017 |  |  |  | 77,905 |
Other differences |  |  | 324,040 |  |  |  | 105,280 |
Deferred tax assets before valuation allowance |  |  | 1,499,503 |  |  |  | 661,303 |
Valuation allowance |  |  | (62,822 | ) |  |  | (19,335 | )
| Total Deferred tax assets |  |  | 1,436,681 |  |  |  | 641,968 |
Deferred tax liabilities: |  |  |  |  |  |  |  |
Property differences |  |  | (2,382,813 | ) |  |  | (1,968,012 | )
| Total Deferred tax liabilities |  |  | (2,382,813 | ) |  |  | (1,968,012 | )
|  | Net deferred tax liability |  |  | (946,132 | ) |  |  | (1,326,044 | )
|  | Less: Current portion: asset/(liability)(1) |  |  | (75,608 | ) |  |  | 15,709 |
|  | Deferred income taxes, net of current portion |  | $ | (1,021,740 | ) |  | $ | (1,310,335 | )

(1) | Current portion of net deferred income taxes are classified within other current assets in 2004 and other current liabilities in 2003 on the Consolidated Balance Sheet.

The net operating loss carryforward consists of federal and state carryforwards of approximately $2.3 billion which expire between 2017 and 2019. The federal and state net operating loss carryforwards available are subject to limitations on their annual usage. The Company also has loss carryforwards in certain foreign subsidiaries, resulting in tax benefits of approximately $152 million, the majority of which expire by 2008. The Company provided a valuation allowance on certain state and foreign tax jurisdiction deferred tax assets to reduce the gross amount of these assets to the extent necessary to result in an amount that is more likely than not of being realized. Realization of the deferred tax assets and net operating loss carryforwards is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. The Company is under an Internal

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Revenue Service review for the years 1999 through 2002 and is periodically under audit for various state and foreign jurisdictions for income and sales and use taxes. The Company believes that the ultimate resolution of these examinations will not have a material effect on its consolidated financial position.
The Company’s foreign subsidiaries had no cumulative undistributed earnings at December 31, 2004.
For the years ended December 31, 2004, 2003 and 2002, the net change in the valuation allowance was an increase (decrease) of $43.5 million, $(7.3) million and $26.7 million, respectively, and is primarily related to loss carryforwards that are not currently realizable.
On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law. This legislation contains a number of changes to the Internal Revenue Code. The Company has analyzed the law in order to determine its effects. The two most notable provisions are those dealing with the reduced tax rate on the repatriation of money from foreign operations and the deduction for domestic-based manufacturing activity. The Company determined that it qualifies for both of these provisions. See Note 10 for further information. Since the Company is projecting that it will continue to generate net operating losses for at least the next twelve months it cannot take advantage of the domestic-based manufacturing deduction at this time.

20. | Employee Benefit Plans

| Retirement Savings Plan

The Company has a defined contribution savings plan under Section 401(a) and 501(a) of the Internal Revenue Code. The plan provides for tax deferred salary deductions and after-tax employee contributions. Employees are immediately eligible upon hire. Contributions include employee salary deferral contributions and employer profit-sharing contributions made entirely in cash of 4% of employees’ salaries, with employer contributions capped at $8,200 per year for 2004 and $8,400 per year for 2005. Employer profit-sharing contributions in 2004, 2003, and 2002 totaled $12.8 million, $10.7 million, and $11.6 million, respectively.

| 2000 Employee Stock Purchase Plan

The Company adopted the 2000 Employee Stock Purchase Plan (“ESPP”) in May 2000. Eligible employees may in the aggregate purchase up to 28,000,000 shares of common stock at semi-annual intervals through periodic payroll deductions. Purchases are limited to a maximum value of $25,000 per calendar year based on the IRS code Section 423 limitation. Shares are purchased on May 31 and November 30 of each year until termination of the plan on May 31, 2010 and limited to 2,400 shares per purchase interval. Under the ESPP, 4,545,858 and 3,636,139 shares were issued at a weighted average fair value of $3.26 and $3.69 per share in 2004 and 2003, respectively. The purchase price is 85% of the lower of (i) the fair market value of the common stock on the participant’s entry date into the offering period, or (ii) the fair market value on the semi-annual purchase date. The purchase price discount is significant enough to cause the ESPP to be considered compensatory under SFAS No. 123. As a result, the ESPP is accounted for as stock-based compensation in accordance with SFAS No. 123. See Note 21 for information related to the Company’s stock-based compensation expense.

| 1996 Stock Incentive Plan

The Company adopted the 1996 Stock Incentive Plan (“SIP”) in September 1996. The SIP succeeded the Company’s previously adopted stock option program. Prior to the adoption of SFAS No. 123 prospectively on January 1, 2003, (see Note 21), the Company accounted for the SIP under APB Opinion No. 25, under which no compensation cost was recognized through December 31, 2002. See Note 21 for the effects the SIP would have on the Company’s financial statements if stock-based compensation had been accounted for under SFAS No. 123 prior to January 1, 2003.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the year ended December 31, 2004, the Company granted options to purchase 5,660,262 shares of common stock. Over the life of the SIP, options exercised have equaled 5,088,290, leaving 32,937,993 granted and not yet exercised. Under the SIP, the option exercise price generally equals the stock’s fair market value on date of grant. The SIP options generally vest ratably over four years and expire after 10 years.
In connection with the merger with Encal in 2001, the Company adopted Encal’s existing stock option plan. All outstanding options under the Encal stock option plan were converted at the time of the merger into options to purchase Calpine stock. No new options may be granted under the Encal stock option plan. As of December 31, 2004, there were 87,274 and 1,752,590 options granted and not yet exercised under the Encal and Calpine’s 1992 stock option plans, respectively.
Changes in options outstanding, granted, exercisable and canceled during the years 2004, 2003, and 2002, under the option plans of Calpine and Encal were as follows:

|  |  |  |  |  | Weighted |
|  | Available for |  |  | Outstanding |  |  | Average |
|  | Option or |  |  | Number of |  |  | Exercise |
|  | Award |  |  | Options |  |  | Price |
Outstanding January 1, 2002 |  |  | 2,855,949 |  |  |  | 27,690,564 |  |  | $ | 9.32 |
| Additional shares reserved |  |  | 15,070,588 |  |  |  |  |  |  |  |  |
|  | Granted |  |  | (8,997,720 | ) |  |  | 8,997,720 |  |  |  | 7.20 |
|  | Exercised |  |  | — |  |  |  | (5,112,535 | ) |  |  | 0.77 |
|  | Canceled |  |  | 1,470,802 |  |  |  | (1,470,802 | ) |  |  | 26.53 |
|  | Canceled options(1) |  |  | (237,705 | ) |  |  | — |  |  |  | — |
Outstanding December 31, 2002 |  |  | 10,161,914 |  |  |  | 30,104,947 |  |  | $ | 9.30 |
| Granted |  |  | (5,998,585 | ) |  |  | 5,998,585 |  |  |  | 3.93 |
| Exercised |  |  | — |  |  |  | (536,730 | ) |  |  | 2.01 |
| Canceled |  |  | 1,725,221 |  |  |  | (1,725,221 | ) |  |  | 13.59 |
| Canceled options(1) |  |  | (72,470 | ) |  |  |  |  |  |  |  |
| Awards issued |  |  | — |  |  |  | (3,150 | ) |  |  | 4.03 |
Outstanding December 31, 2003 |  |  | 5,816,080 |  |  |  | 33,838,431 |  |  | $ | 8.25 |
| Additional shares reserved |  |  | 21,000,000 |  |  |  | — |  |  |  | — |
|  | Granted |  |  | (5,660,262 | ) |  |  | 5,660,262 |  |  |  | 5.47 |
|  | Exercised |  |  | — |  |  |  | (3,629,824 | ) |  |  | 0.83 |
|  | Canceled |  |  | 1,089,032 |  |  |  | (1,089,032 | ) |  |  | 18.21 |
|  | Canceled options(1) |  |  | (38,945 | ) |  |  | — |  |  |  | — |
|  | Awards issued |  |  | — |  |  |  | (1,980 | ) |  |  | 4.33 |
Outstanding December 31, 2004 |  |  | 22,205,905 |  |  |  | 34,777,857 |  |  |  | 8.42 |
Options exercisable: |  |  |  |  |  |  |  |  |  |  |  |
| December 31, 2002 |  |  |  |  |  |  | 19,418,239 |  |  |  | 7.14 |
| December 31, 2003 |  |  |  |  |  |  | 22,953,781 |  |  |  | 8.02 |
| December 31, 2004 |  |  |  |  |  |  | 22,949,497 |  |  |  | 9.30 |

(1) | Represents cessation of options awarded under the Encal stock option plan

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following tables summarizes information concerning outstanding and exercisable options at December 31, 2004:

|  |  |  | Weighted |  |  |  |  |  |  |
|  |  |  | Average |  |  | Weighted |  |  |  |  | Weighted |
|  | Number of |  |  | Remaining |  |  | Average |  |  | Number of |  |  | Average |
|  | Options |  |  | Contractual |  |  | Exercise |  |  | Options |  |  | Exercise |
Range of Exercise Prices |  | Outstanding |  |  | Life in Years |  |  | Price |  |  | Exercisable |  |  | Price |
$ 0.645-$ 2.150 |  |  | 4,073,196 |  |  |  | 2.55 |  |  | $ | 1.606 |  |  |  | 4,072,693 |  |  | $ | 1.606 |
$ 2.240-$ 3.860 |  |  | 5,220,014 |  |  |  | 3.58 |  |  |  | 3.321 |  |  |  | 5,166,889 |  |  |  | 3.321 |
$ 3.910-$ 3.980 |  |  | 5,254,837 |  |  |  | 8.02 |  |  |  | 3.980 |  |  |  | 1,720,183 |  |  |  | 3.980 |
$ 4.010-$ 5.240 |  |  | 3,036,785 |  |  |  | 7.36 |  |  |  | 5.157 |  |  |  | 1,691,122 |  |  |  | 5.094 |
$ 5.250-$ 5.560 |  |  | 5,397,275 |  |  |  | 9.15 |  |  |  | 5.560 |  |  |  | 152,350 |  |  |  | 5.549 |
$ 5.565-$ 7.640 |  |  | 3,854,747 |  |  |  | 5.97 |  |  |  | 7.561 |  |  |  | 2,847,889 |  |  |  | 7.538 |
$ 7.750-$13.850 |  |  | 3,735,013 |  |  |  | 4.86 |  |  |  | 10.595 |  |  |  | 3,465,918 |  |  |  | 10.343 |
$13.917-$48.150 |  |  | 4,063,810 |  |  |  | 5.00 |  |  |  | 31.054 |  |  |  | 3,705,184 |  |  |  | 29.569 |
$48.188-$56.920 |  |  | 140,330 |  |  |  | 6.23 |  |  |  | 51.292 |  |  |  | 125,419 |  |  |  | 51.271 |
$56.990-$56.990 |  |  | 1,850 |  |  |  | 6.33 |  |  |  | 56.990 |  |  |  | 1,850 |  |  |  | 56.990 |
$ 0.645-$56.990 |  |  | 34,777,857 |  |  |  | 5.90 |  |  | $ | 8.416 |  |  |  | 22,949,497 |  |  | $ | 9.299 |

21. | Stockholders’ Equity

| Common Stock

Increase in Authorized Shares — On June 2, 2004, the Company filed amended certificates with the Delaware Secretary of State to increase the number of authorized shares of common stock to 2,000,000,000 from 1,000,000,000.
Equity Offerings — On April 30, 2002, Calpine completed a registered offering of 66,000,000 shares of common stock at $11.50 per share. The proceeds from this offering, after underwriting fees, were $734.3 million.
On September 30, 2004, in conjunction with the 2014 Convertible Notes offering (see Note 17 for more information regarding this offering), the Company entered into a ten-year Share Lending Agreement with Deutsche Bank AG London (“DB London”), under which the Company loaned DB London 89 million shares of newly issued Calpine common stock in exchange for a loan fee of $0.001 per share. DB London sold the 89 million shares on September 30, 2004 at a price of $2.75 per share in a registered public offering. The Company did not receive any of the proceeds of the public offering. As discussed in Note 17, the requirement to return these shares is considered to be a prepaid forward purchase contract and the Company analogizes to the guidance in SFAS No. 150 so that the 89 million shares of common stock subject to the Share Lending Agreement are excluded from the EPS calculation.

| Preferred Stock and Preferred Share Purchase Rights

On June 5, 1997, Calpine adopted a stockholders’ rights plan to strengthen Calpine’s ability to protect Calpine’s stockholders. The plan was amended on September 19, 2001, and further amended on September 28, 2004 and March 18, 2005. The rights plan was designed to protect against abusive or coercive takeover tactics that are not in the best interests of Calpine or its stockholders. To implement the rights plan, Calpine declared a dividend of one preferred share purchase right for each outstanding share of Calpine’s common stock held on record as of June 18, 1997, and directed the issuance of one preferred share purchase right with respect to each share of Calpine’s common stock that shall become outstanding thereafter until the rights

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
become exercisable or they expire as described below. On December 31, 2004, there were 536,509,231 rights outstanding. Each right initially represents a contingent right to purchase, under certain circumstances, one one-thousandth of a share, called a “unit,” of Calpine’s Series A Participating Preferred Stock, par value $.001 per share, at a price of $140.00 per unit, subject to adjustment. The rights become exercisable and trade independently from Calpine’s common stock upon the public announcement of the acquisition by a person or group of 15% or more of Calpine’s common stock, or ten days after commencement of a tender or exchange offer that would result in the acquisition of 15% or more of Calpine’s common stock. Each unit purchased upon exercise of the rights will be entitled to a dividend equal to any dividend declared per share of common stock and will have one vote, voting together with the common stock. In the event of Calpine’s liquidation, each share of the participating preferred stock will be entitled to any payment made per share of common stock.
If Calpine is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of Calpine’s common stock, each right will entitle its holder to purchase at the right’s exercise price a number of the acquiring company’s shares of common stock having a market value of twice the right’s exercise price. In addition, if a person or group acquires 15% or more of Calpine’s common stock, each right will entitle its holder (other than the acquiring person or group) to purchase, at the right’s exercise price, a number of fractional shares of Calpine’s participating preferred stock or shares of Calpine’s common stock having a market value of twice the right’s exercise price.
The rights remain exercisable for up to 90 days following a triggering event (such as a person acquiring 15% or more of the Company’s common Stock). The rights expire on May 1, 2005, unless redeemed earlier by Calpine. Calpine can redeem the rights at a price of $.01 per right at any time before the rights become exercisable, and thereafter only in limited circumstances.

| Stock-Based Compensation

On January 1, 2003, the Company prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123 as amended by SFAS No. 148. SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for companies that voluntarily change their accounting for stock-based compensation from the less preferred intrinsic value based method to the more preferred fair value based method. Prior to its amendment, SFAS No. 123 required that companies enacting a voluntary change in accounting principle from the intrinsic value methodology provided by APB Opinion No. 25 could only do so on a prospective basis; no adoption or transition provisions were established to allow for a restatement of prior period financial statements. SFAS No. 148 provides two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company elected to adopt the provisions of SFAS No. 123 on a prospective basis; consequently, the Company is required to provide a pro-forma disclosure of net income and EPS as if SFAS No. 123 accounting had been applied to all prior periods presented within its financial statements. As shown below, the adoption of SFAS No. 123 has had a material impact on the Company’s financial statements. The table below reflects the pro forma impact of stock-based compensation on the Company’s net income (loss) and earnings (loss) per share for the years ended December 31, 2004, 2003 and 2002, had the Company applied the accounting

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
provisions of SFAS No. 123 to its financial statements in years prior to adoption of SFAS No. 123 on January 1, 2003 (in thousands, except per share amounts):

|  | 2004 |  |  | 2003 |  |  | 2002 |
Net income (loss) |  |  |  |  |  |  |  |  |  |  |  |
|  | As reported |  | $ | (242,461 | ) |  | $ | 282,022 |  |  | $ | 118,618 |
|  | Pro Forma |  |  | (247,316 | ) |  |  | 270,418 |  |  |  | 83,025 |
Earnings (loss) per share data: |  |  |  |  |  |  |  |  |  |  |  |
| Basic earnings (loss) per share |  |  |  |  |  |  |  |  |  |  |  |
|  | As reported |  | $ | (0.56 | ) |  | $ | 0.72 |  |  | $ | 0.33 |
|  | Pro Forma |  |  | (0.57 | ) |  |  | 0.69 |  |  |  | 0.23 |
| Diluted earnings per share |  |  |  |  |  |  |  |  |  |  |  |
|  | As reported |  | $ | (0.56 | ) |  | $ | 0.71 |  |  | $ | 0.33 |
|  | Pro Forma |  |  | (0.57 | ) |  |  | 0.68 |  |  |  | 0.23 |
Stock-based compensation cost included in net income (loss), as reported |  | $ | 12,734 |  |  | $ | 9,724 |  |  | $ | — |
Stock-based compensation cost included in net income (loss), pro forma |  |  | 17,589 |  |  |  | 21,328 |  |  |  | 35,593 |

The range of fair values of the Company’s stock options granted in 2004, 2003, and 2002 were as follows, based on varying historical stock option exercise patterns by different levels of Calpine employees: $1.83-$4.45 in 2004, $1.50-$4.38 in 2003 and $3.73-$6.62 in 2002 on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: expected dividend yields of 0%, expected volatility of 69%-98% for 2004, 70%-113% for 2003 and 70%-83% for 2002, risk-free interest rates of 2.35%-4.54% for 2004, 1.39%-4.04% for 2003 and 2.39%-3.83% for 2002, and expected option terms of 3-9.5 years for 2004, 1.5-9.5 years for 2003 and 4-9 years for 2002.
In December 2004, FASB issued SFAS No. 123-R. This Statement revises SFAS No. 123 and supersedes APB Opinion No. 25, and its related implementation guidance. See Note 2 for further information.

| Comprehensive Income (Loss)

Comprehensive income is the total of net income and all other non-owner changes in equity. Comprehensive income includes the Company’s net income, unrealized gains and losses from derivative instruments that qualify as cash flow hedges, unrealized gains and losses from available-for-sale securities which are marked to market, the Company’s share of its equity method investee’s OCI, and the effects of foreign currency translation adjustments. The Company reports Accumulated Other Comprehensive Income (“AOCI”) in its

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Consolidated Balance Sheet. The tables below detail the changes during 2004, 2003 and 2002 in the Company’s AOCI balance and the components of the Company’s comprehensive income (in thousands):

|  |  |  |  |  |  |  | Total |  |  |
|  |  |  |  |  |  |  | Accumulated |  |  |
|  |  |  |  |  | Foreign |  |  | Other |  |  |
|  | Cash Flow |  |  | Available-For- |  |  | Currency |  |  | Comprehensive |  |  | Comprehensive |
|  | Hedges(1) |  |  | Sale Investments |  |  | Translation |  |  | Income (Loss) |  |  | Income (Loss) |
Accumulated other comprehensive loss at January 1, 2002 |  | $ | (180,819 | ) |  | $ | — |  |  | $ | (60,061 | ) |  | $ | (240,880 | ) |  |  |  |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 118,618 |
| Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment |  |  | 96,905 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Reclassification adjustment for gain included in net income |  |  | (169,205 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Income tax benefit |  |  | 28,705 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  | (43,595 | ) |  |  |  |  |  |  |  |  |  |  | (43,595 | ) |  |  | (43,595 | )
| Foreign currency translation gain |  |  |  |  |  |  |  |  |  |  | 47,018 |  |  |  | 47,018 |  |  |  | 47,018 |
Total comprehensive income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 122,041 |
Accumulated other comprehensive loss at December 31, 2002 |  | $ | (224,414 | ) |  |  |  |  |  | $ | (13,043 | ) |  | $ | (237,457 | ) |  |  |  |
Net income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 282,022 |
| Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment |  |  | 112,481 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Reclassification adjustment for loss included in net income |  |  | 55,620 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Income tax provision |  |  | (74,106 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  | 93,995 |  |  |  |  |  |  |  |  |  |  |  | 93,995 |  |  |  | 93,995 |
| Foreign currency translation gain |  |  |  |  |  |  |  |  |  |  | 200,056 |  |  |  | 200,056 |  |  |  | 200,056 |
Total comprehensive income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 576,073 |
Accumulated other comprehensive gain (loss) at December 31, 2003 |  | $ | (130,419 | ) |  |  |  |  |  | $ | 187,013 |  |  | $ | 56,594 |  |  |  |  |
Net loss |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (242,461 | )
| Cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment |  |  | (106,071 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Reclassification adjustment for loss included in net loss |  |  | 89,888 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Income tax provision |  |  | 6,451 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  |  | (9,732 | ) |  |  |  |  |  |  |  |  |  |  | (9,732 | ) |  |  | (9,732 | )
Available-for-sale investments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Comprehensive pre-tax gain on available-for-sale investments before reclassification adjustment |  |  |  |  |  |  | 19,239 |  |  |  |  |  |  |  |  |  |  |  |  |
| Reclassification adjustment for gain included in net loss |  |  |  |  |  |  | (18,281 | ) |  |  |  |  |  |  |  |  |  |  |  |
| Income tax provision |  |  |  |  |  |  | (376 | ) |  |  |  |  |  |  |  |  |  |  |  |
|  |  |  |  |  |  | 582 |  |  |  |  |  |  |  | 582 |  |  |  | 582 |
Foreign currency translation gain |  |  |  |  |  |  |  |  |  |  | 62,067 |  |  |  | 62,067 |  |  |  | 62,067 |
Total comprehensive loss |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (189,544 | )
Accumulated other comprehensive gain (loss) at December 31, 2004 |  | $ | (140,151 | ) |  | $ | 582 |  |  | $ | 249,080 |  |  | $ | 109,511 |  |  |  |  |

(1) | Includes AOCI from cash flow hedges held by unconsolidated investees. At December 31, 2004, 2003 and 2002, these amounts were $1,698, $6,911 and $12,018, respectively.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

22. | Customers

| Significant Customer

In 2004, 2003 and 2002, Calpine had one significant customer that accounted for more than 10% of the Company’s annual consolidated revenues: the CDWR. See below for a discussion of the Company’s contracts with CDWR.
For the years ended December 31, 2004, 2003, and 2002, CDWR revenues were $1,148.0 million, $1,219.7 million and $754.2 million, respectively.
Calpine’s receivables from CDWR at December 31, 2004, 2003 and 2002, were $98.5 million, $97.8 million and $78.8 million, respectively.

| Counterparty Exposure

The Company’s customer and supplier base is concentrated within the energy industry. Additionally, the Company has exposure to trends within the energy industry, including declines in the creditworthiness of its marketing counterparties. Currently, certain companies within the energy industry are in bankruptcy or have below investment grade credit ratings. However, we do not currently have any significant exposure to counterparties that are not paying on a current basis.

| California Department of Water Resources

In 2001, California adopted legislation permitting it to issue long-term revenue bonds to fund wholesale purchases of power by the CDWR. The bonds will be repaid with the proceeds of payments by retail power customers over time. CES and CDWR entered into four long-term supply contracts during 2001. The Company has recorded deferred revenue in connection with one of the long-term power supply contracts (“Contract 3”). All of the Company’s accounts receivables from CDWR are current, with the exception of approximately $1.0 million which the Company is working to resolve with the customer.
In early 2002, the CPUC and the California Electricity Oversight Board (“EOB”) filed complaints under Section 206 of the Federal Power Act with the Federal Energy Regulatory Commission (“FERC”) alleging that the prices and terms of the long-term contracts with CDWR were unjust and unreasonable and contrary to the public interest (the “206 Complaint”). The contracts entered into by CES and CDWR were subject to the 206 Complaint.
On April 22, 2002, the Company announced that it had renegotiated CES’s long-term power contracts with CDWR and settled the 206 Complaint. The Office of the Governor, the CPUC, the EOB and the Attorney General for the State of California all endorsed the renegotiated contracts and dropped all pending claims against the Company and its affiliates, including any efforts by the CPUC and the EOB to seek refunds from the Company and its affiliates through the FERC California Refund Proceedings. In connection with the renegotiation, the Company agreed to pay $6 million over three years to the Attorney General to resolve any and all possible claims.

| Lease Income

The Company records income under power purchase agreements that are accounted for as operating leases under SFAS No. 13 and EITF Issue No. 01-08. For income statement presentation purposes, this income is classified within electricity and steam revenue in the Consolidated Statements of Operations.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The total contractual future minimum lease payments for these power purchase agreements are as follows (in thousands):

2005 |  | $ | 123,435 |
2006 |  |  | 175,349 |
2007 |  |  | 213,431 |
2008 |  |  | 285,386 |
2009 |  |  | 288,516 |
Thereafter |  |  | 2,844,717 |
| Total |  | $ | 3,930,834 |

The contingent income for these agreements related to our Canadian power generation asset was $20.1 million, $25.3 million and $28.7 million for the respective periods, while contingent income under the other power purchase agreements were collectively immaterial. Property leased to customers under operating leases is recorded at cost and is depreciated on the straight line basis to its estimated residual value. Estimated useful lives are 35 years. As of December 31, 2004, the cost of the leased property was $1,409.6 million and the accumulated depreciation was $55.6 million. These power purchase agreements expire over the next 27 years.

| Credit Evaluations

The Company’s treasury department includes a credit group focused on monitoring and managing counterparty risk. The credit group monitors the net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using the forward curves analyzed by the Company’s Risk Controls group. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of the financial statements. The credit department monitors these thresholds to determine the need for additional collateral or restriction of activity with the counterparty.

23. | Derivative Instruments

| Commodity Derivative Instruments

As an independent power producer primarily focused on generation of electricity using gas-fired turbines, the Company’s natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, the Company enters into derivative commodity instruments. The Company enters into commodity instruments to convert floating or indexed electricity and gas (and to a lesser extent oil and refined product) prices to fixed prices in order to lessen its vulnerability to reductions in electric prices for the electricity it generates, to reductions in gas prices for the gas it produces, and to increases in gas prices for the fuel it consumes in its power plants. The Company seeks to “self-hedge” its gas consumption exposure to an extent with its own gas production position. The hedging, balancing, or optimization activities that the Company engages in are directly related to the Company’s asset-based business model of owning and operating gas-fired electric power plants and are designed to protect the Company’s “spark spread” (the difference between the Company’s fuel cost and the revenue it receives for its electric generation). The Company hedges exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas. The Company also utilizes derivatives to optimize the returns it is able to achieve from these assets. From time to time the Company has entered into contracts considered energy trading contracts under EITF Issue No. 02-03. However, the Company’s traders have low capital at risk and value at risk limits for energy trading, and its risk management policy limits, at any given time, its net sales of

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
power to its generation capacity and limits its net purchases of gas to its 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 Company also routinely enters into physical commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives but are generally eligible for the normal purchases and sales exception. Some of those contracts that are not deemed normal purchases and sales can be designated as hedges of the underlying consumption of gas or production of electricity.

| Interest Rate and Currency Derivative Instruments

The Company also enters into various interest rate swap agreements to hedge against changes in floating interest rates on certain of its project financing facilities and to adjust the mix between fixed and floating rate debt in its capital structure to desired levels. Certain of the interest rate swap agreements effectively convert floating rates into fixed rates so that the Company can predict with greater assurance what its future interest costs will be and protect itself against increases in floating rates.
In conjunction with its capital markets activities, the Company enters into various forward interest rate agreements to hedge against interest rate fluctuations that may occur after the Company has decided to issue long-term fixed rate debt but before the debt is actually issued. The forward interest rate agreements effectively prevent the interest rates on anticipated future long-term debt from increasing beyond a certain level, allowing the Company to predict with greater assurance what its future interest costs on fixed rate long-term debt will be.
Also, in conjunction with its capital market activities, the Company enters into various interest rate swap agreements to hedge against the change in fair value on certain of its fixed rate Senior Notes. These interest rate swap agreements effectively convert fixed rates into floating rates so that the Company can predict with greater assurance what the fair value of its fixed rate Senior Notes will be and protect itself against unfavorable future fair value movements.
The Company enters into various foreign currency swap agreements to hedge against changes in exchange rates on certain of its senior notes denominated in currencies other than the U.S. dollar. The foreign currency swaps effectively convert floating exchange rates into fixed exchange rates so that the Company can predict with greater assurance what its U.S. dollar cost will be for purchasing foreign currencies to satisfy the interest and principal payments on these senior notes.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

| Summary of Derivative Values

The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at December 31, 2004, for the Company’s derivative instruments:

|  |  |  | Commodity |  |  |
|  | Interest Rate |  |  | Derivative |  |  | Total |
|  | Derivative |  |  | Instruments |  |  | Derivative |
|  | Instruments |  |  | Net |  |  | Instruments |
Current derivative assets |  | $ | 620 |  |  | $ | 323,586 |  |  | $ | 324,206 |
Long-term derivative assets |  |  | — |  |  |  | 506,050 |  |  |  | 506,050 |
| Total assets |  | $ | 620 |  |  | $ | 829,636 |  |  | $ | 830,256 |
Current derivative liabilities |  | $ | 21,578 |  |  | $ | 343,387 |  |  | $ | 364,965 |
Long-term derivative liabilities |  |  | 58,909 |  |  |  | 467,689 |  |  |  | 526,598 |
| Total liabilities |  | $ | 80,487 |  |  | $ | 811,076 |  |  | $ | 891,563 |
|  | Net derivative assets (liabilities) |  | $ | (79,867 | ) |  | $ | 18,560 |  |  | $ | (61,307 | )

Of the Company’s net derivative assets, $289.9 million and $55.4 million are net derivative assets of PCF and CNEM, respectively, each of which is an entity with its existence separate from the Company and other subsidiaries of the Company. The Company fully consolidates CNEM and, as discussed more fully in Note 2, the Company records the derivative assets of PCF in its balance sheet.
At any point in time, it is highly unlikely that total net derivative assets and liabilities will equal AOCI, net of tax from derivatives, for three primary reasons:

| • | Tax effect of OCI — When the values and subsequent changes in values of derivatives that qualify as effective hedges are recorded into OCI, they are initially offset by a derivative asset or liability. Once in OCI, however, these values are tax effected against a deferred tax liability or asset account, thereby creating an imbalance between net OCI and net derivative assets and liabilities.
| • | Derivatives not designated as cash flow hedges and hedge ineffectiveness — Only derivatives that qualify as effective cash flow hedges will have an offsetting amount recorded in OCI. Derivatives not designated as cash flow hedges and the ineffective portion of derivatives designated as cash flow hedges will be recorded into earnings instead of OCI, creating a difference between net derivative assets and liabilities and pre-tax OCI from derivatives.
| • | Termination of effective cash flow hedges prior to maturity — Following the termination of a cash flow hedge, changes in the derivative asset or liability are no longer recorded to OCI. At this point, an AOCI balance remains that is not recognized in earnings until the forecasted initially hedged transactions occur. As a result, there will be a temporary difference between OCI and derivative assets and liabilities on the books until the remaining OCI balance is recognized in earnings.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Below is a reconciliation of the Company’s net derivative liabilities to its accumulated other comprehensive loss, net of tax from derivative instruments at December 31, 2004 (in thousands):

Net derivative liabilities |  | $ | (61,307 | )
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness |  |  | (86,496 | )
Cash flow hedges terminated prior to maturity |  |  | (75,725 | )
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges |  |  | 77,640 |
AOCI from unconsolidated investees |  |  | 5,737 |
Accumulated other comprehensive loss from derivative instruments, net of tax(1) |  | $ | (140,151 | )

(1) | Amount represents one portion of the Company’s total AOCI balance. See Note 21 for further information.

The asset and liability balances for the Company’s commodity derivative instruments represent the net totals after offsetting certain assets against certain liabilities under the criteria of FIN 39. For a given contract, FIN 39 will allow the offsetting of assets against liabilities so long as four criteria are met: (1) each of the two parties under contract owes the other determinable amounts; (2) the party reporting under the offset method has the right to set off the amount it owes against the amount owed to it by the other party; (3) the party reporting under the offset method intends to exercise its right to set off; and; (4) the right of set-off is enforceable by law. The table below reflects both the amounts (in thousands) recorded as assets and liabilities by the Company and the amounts that would have been recorded had the Company’s commodity derivative instrument contracts not qualified for offsetting as of December 31, 2004.

|  | December 31, 2004 |
|  | Gross |  |  | Net |
Current derivative assets |  | $ | 844,050 |  |  | $ | 323,586 |
Long-term derivative assets |  |  | 967,089 |  |  |  | 506,050 |
| Total derivative assets |  | $ | 1,811,139 |  |  | $ | 829,636 |
Current derivative liabilities |  | $ | 863,850 |  |  | $ | 343,387 |
Long-term derivative liabilities |  |  | 928,729 |  |  |  | 467,689 |
| Total derivative liabilities |  | $ | 1,792,579 |  |  | $ | 811,076 |
|  | Net commodity derivative assets |  | $ | 18,560 |  |  | $ | 18,560 |

The table above excludes the value of interest rate and currency derivative instruments.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The tables below reflect the impact of unrealized mark-to-market gains (losses) on the Company’s pre-tax earnings, both from cash flow hedge ineffectiveness and from the changes in market value of derivatives not designated as hedges of cash flows, for the years ended December 31, 2004, 2003 and 2002, respectively (in thousands):

|  | 2004 |  |  | 2003 |  |  | 2002 |
|  | Hedge |  |  | Undesignated |  |  |  |  | Hedge |  |  | Undesignated |  |  |  |  | Hedge |  |  | Undesignated |  |  |
|  | Ineffectiveness |  |  | Derivatives |  |  | Total |  |  | Ineffectiveness |  |  | Derivatives |  |  | Total |  |  | Ineffectiveness |  |  | Derivatives |  |  | Total |
Natural gas derivatives(1) |  | $ | 5,827 |  |  | $ | (10,700 | ) |  | $ | (4,873 | ) |  | $ | 3,153 |  |  | $ | 7,768 |  |  | $ | 10,921 |  |  | $ | 2,147 |  |  | $ | (14,792 | ) |  | $ | (12,645 | )
Power derivatives(1) |  |  | 1,814 |  |  |  | (31,666 | ) |  |  | (29,852 | ) |  |  | (5,001 | ) |  |  | (56,693 | ) |  |  | (61,694 | ) |  |  | (4,934 | ) |  |  | 12,974 |  |  |  | 8,040 |
Interest rate derivatives(2) |  |  | 1,492 |  |  |  | 6,035 |  |  |  | 7,527 |  |  |  | (974 | ) |  |  | — |  |  |  | (974 | ) |  |  | (810 | ) |  |  | — |  |  |  | (810 | )
Currency derivatives |  |  | — |  |  |  | (12,897 | ) |  |  | (12,897 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
| Total |  | $ | 9,133 |  |  | $ | (49,228 | ) |  | $ | (40,095 | ) |  | $ | (2,822 | ) |  | $ | (48,925 | ) |  | $ | (51,747 | ) |  | $ | (3,597 | ) |  | $ | (1,818 | ) |  | $ | (5,415 | )

(1) | Represents the unrealized portion of mark-to-market activity on gas and power transactions. The unrealized portion of mark-to-market activity is combined with the realized portions of mark-to-market activity and presented in the Consolidated Statements of Operations as mark-to-market activities, net.
(2) | Recorded within Other Income

The table below reflects the contribution of the Company’s cash flow hedge activity to pre-tax earnings based on the reclassification adjustment from OCI to earnings for the years ended December 31, 2004, 2003 and 2002, respectively (in thousands):

|  | 2004 |  |  | 2003 |  |  | 2002 |
Natural gas and crude oil derivatives |  | $ | 58,308 |  |  | $ | 40,752 |  |  | $ | (119,419 | )
Power derivatives |  |  | (128,556 | ) |  |  | (79,233 | ) |  |  | 304,073 |
Interest rate derivatives |  |  | (17,625 | ) |  |  | (27,727 | ) |  |  | (10,993 | )
Foreign currency derivatives |  |  | (2,015 | ) |  |  | 10,588 |  |  |  | (4,456 | )
| Total derivatives |  | $ | (89,888 | ) |  | $ | (55,620 | ) |  | $ | 169,205 |

As of December 31, 2004, the maximum length of time over which the Company was hedging its exposure to the variability in future cash flows for forecasted transactions was 7 and 12 years, for commodity and interest rate derivative instruments, respectively. The Company estimates that pre-tax losses of $137.6 million would be reclassified from AOCI into earnings during the twelve months ended December 31, 2005, as the hedged transactions affect earnings assuming constant gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified will likely vary based on the probability that gas and power prices as well as interest rates and exchange rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next twelve months.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The table below presents (in thousands) the pre-tax gains (losses) currently held in OCI that will be recognized annually into earnings, assuming constant gas and power prices, interest rates, and exchange rates over time.

|  |  |  |  |  |  |  |  |  |  |  | 2010 & |  |  |
|  | 2005 |  |  | 2006 |  |  | 2007 |  |  | 2008 |  |  | 2009 |  |  | After |  |  | Total |
Gas OCI |  | $ | (29,476 | ) |  | $ | 55,612 |  |  | $ | 1,111 |  |  | $ | 702 |  |  | $ | 343 |  |  | $ | 250 |  |  | $ | 28,542 |
Power OCI |  |  | (88,357 | ) |  |  | (80,619 | ) |  |  | (3,854 | ) |  |  | (589 | ) |  |  | (343 | ) |  |  | (94 | ) |  |  | (173,856 | )
Interest rate OCI |  |  | (17,745 | ) |  |  | (10,960 | ) |  |  | (7,941 | ) |  |  | (5,170 | ) |  |  | (4,126 | ) |  |  | (20,855 | ) |  |  | (66,797 | )
Foreign currency OCI |  |  | (2,014 | ) |  |  | (2,014 | ) |  |  | (1,624 | ) |  |  | (28 | ) |  |  | — |  |  |  | — |  |  |  | (5,680 | )
| Total pre-tax OCI |  | $ | (137,592 | ) |  | $ | (37,981 | ) |  | $ | (12,308 | ) |  | $ | (5,085 | ) |  | $ | (4,126 | ) |  | $ | (20,699 | ) |  | $ | (217,791 | )

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

24. | Earnings per Share

Basic earnings (loss) per common share were computed by dividing net income (loss) by the weighted average number of common shares outstanding for the respective periods. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain convertible securities into the Company’s common stock is based on the dilutive common share equivalents and the after tax distribution expense avoided upon conversion. The calculation of basic and diluted earnings (loss) per common share is shown in the following table (in thousands, except per share data).

|  | For the Years Ended December 31, |
|  |  |  | 2003 |  |  | 2002 |
|  | 2004 |  |  |  |  |  |  |
|  |  |  |  | Net |  |  |  |  | Net |  |  |
|  | Net Income |  |  | Shares |  |  | EPS |  |  | Income |  |  | Shares |  |  | EPS |  |  | Income |  |  | Shares |  |  | EPS |
Basic earnings (loss) per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations and cumulative effect of a change in accounting principle |  | $ | (440,826 | ) |  |  | 430,775 |  |  | $ | (1.02 | ) |  | $ | 86,110 |  |  |  | 390,772 |  |  | $ | 0.22 |  |  | $ | 26,722 |  |  |  | 354,822 |  |  | $ | 0.07 |
| Discontinued operations, net of tax |  |  | 198,365 |  |  |  | — |  |  |  | 0.46 |  |  |  | 14,969 |  |  |  | — |  |  |  | 0.04 |  |  |  | 91,896 |  |  |  | — |  |  |  | 0.26 |
| Cumulative effect of a change in accounting principle, net of tax |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 180,943 |  |  |  | — |  |  |  | 0.46 |  |  |  | — |  |  |  | — |  |  |  | — |
| Net income |  | $ | (242,461 | ) |  |  | 430,775 |  |  | $ | (0.56 | ) |  | $ | 282,022 |  |  |  | 390,772 |  |  | $ | 0.72 |  |  | $ | 118,618 |  |  |  | 354,822 |  |  | $ | 0.33 |
Diluted earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Common shares issuable upon exercise of stock options using treasury stock method |  |  |  |  |  |  | — |  |  |  |  |  |  |  |  |  |  |  | 5,447 |  |  |  |  |  |  |  |  |  |  |  | 7,711 |  |  |  |  |
| Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle |  | $ | (440,826 | ) |  |  | 430,775 |  |  | $ | (1.02 | ) |  | $ | 86,110 |  |  |  | 396,219 |  |  | $ | 0.22 |  |  | $ | 26,722 |  |  |  | 362,533 |  |  | $ | 0.07 |
| Dilutive effect of certain convertible securities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
| Income before discontinued operations and cumulative effect of a change in accounting principle |  |  | (440,826 | ) |  |  | 430,775 |  |  |  | (1.02 | ) |  |  | 86,110 |  |  |  | 396,219 |  |  |  | 0.22 |  |  |  | 26,722 |  |  |  | 362,533 |  |  |  | 0.07 |
| Discontinued operations, net of tax |  |  | 198,365 |  |  |  | — |  |  |  | 0.46 |  |  |  | 14,969 |  |  |  | — |  |  |  | 0.04 |  |  |  | 91,896 |  |  |  | — |  |  |  | 0.26 |
| Cumulative effect of a change in accounting principle, net of tax |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 180,943 |  |  |  | — |  |  |  | 0.45 |  |  |  | — |  |  |  | — |  |  |  | — |
| Net income |  | $ | (242,461 | ) |  |  | 430,775 |  |  | $ | (0.56 | ) |  | $ | 282,022 |  |  |  | 396,219 |  |  | $ | 0.71 |  |  | $ | 118,618 |  |  |  | 362,533 |  |  | $ | 0.33 |

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company incurred losses before discontinued operations and cumulative effect of a change in accounting principle for the year ended December 31, 2004. As a result, basic shares were used in the calculations of fully diluted loss per share for these periods, under the guidelines of SFAS No. 128 as using the basic shares produced the more dilutive effect on the loss per share. Potentially convertible securities, shares to be purchased under the Company’s ESPP and unexercised employee stock options to purchase a weighted average of 47.2 million, 127.1 million and 136.7 million shares of the Company’s common stock were not included in the computation of diluted shares outstanding during the years ended December 31, 2004, 2003 and 2002, respectively, because such inclusion would be antidilutive.
For the years ended December 31, 2004, 2003 and 2002, approximately 8.9 million, 61.0 million and 66.4 million, respectively, weighted common shares of the Company’s outstanding 2006 Convertible Senior Notes were excluded from the diluted EPS calculations as the inclusion of such shares would have been antidilutive. See Note 17 for a further discussion of these convertible securities.
In connection with the convertible notes payable to Trust I, Trust II and Trust III, net of repurchases, there were 34.4 million, 44.1 million and 44.9 million weighted average common shares potentially issuable, respectively, that were excluded from the diluted EPS calculation for the years ended December 31, 2004, 2003 and 2002 as their inclusion would be antidilutive. See Note 12 for a further discussion of these securities.
For the years ended December 31, 2004 and 2003, under the new guidance of EITF 04-08 there were no shares potentially issuable and thus potentially included in the diluted EPS calculation under the Company’s 2023 Convertible Senior Notes issued in November 2003, because the Company’s closing stock price at each period end was below the conversion price. However, in future reporting periods where the Company’s closing stock price is above $6.50, and depending on the closing stock price at conversion, the maximum potential shares issuable under the conversion provisions of the 2023 Convertible Senior Notes and included (if dilutive) in the diluted EPS calculation is approximately 97.5 million shares. See Note 17 for a further discussion of these convertible securities.
For the year ended December 31, 2004, under the new guidance of EITF 04-08 approximately 8.6 million weighted common shares potentially issuable under the Company’s outstanding 2014 Convertible Notes were excluded from the diluted earnings per share calculations as the inclusion of such shares would have been antidilutive because of the Company’s net loss. However, in future reporting periods where the Company’s has net income and closing stock price is above $3.85, and depending on the closing stock price at conversion, the maximum potential shares issuable under the conversion provisions of the 2014 Convertible Notes and included in the diluted EPS calculation is approximately 191.2 million shares. See Note 17 for a further discussion of these convertible securities.
As discussed in Note 17, the Company has excluded the 89 million shares of common stock subject to the Share Lending Agreement from the EPS calculation.
See Note 2 for a discussion of the potential impact of SFAS No. 128-R on the calculation of diluted EPS.

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

25. | Commitments and Contingencies

Turbines — On February 11, 2003, the Company announced a significant restructuring of its turbine agreements, which enabled the Company to cancel up to 131 steam and gas turbines. The Company recorded a pre-tax charge of $207.4 million in the quarter ending December 31, 2002, in connection with fees paid to vendors to restructure these contracts. This charge was recorded in the Equipment cancellation and impairment costs line item on the Consolidated Statements of Operations in the year ended December 31, 2002. As of December 31, 2004, 91 of these turbines had been cancelled and 2 had been applied to Calpine projects, leaving the disposition of 38 turbines still to be determined. The following table sets forth an analysis of the components of the turbine restructuring charges recorded in the fourth quarter of fiscal 2002 (in thousands):

|  | Three Months Ended |  |  |
|  | December 31, 2002 |  |  |
|  |  |  |  | Total |
|  |  |  | Turbine |  |  | Turbine |
|  | Turbine CIP |  |  | Restructuring |  |  | Restructuring |
Description |  | Write-Off |  |  | Accrual |  |  | Charge |
Turbine write-offs and contract restructuring charges |  | $ | 182,534 |  |  | $ | 24,824 |  |  | $ | 207,358 |

The following table sets forth in the Company’s turbine restructuring reserves as of December 31, 2003 (in thousands):

|  | As of |  |  |  |  |  |  | As of |
|  | December 31, |  |  |  |  | Adjustments to |  |  | December 31, |
|  | 2002 |  |  | Payments |  |  | Accrual(1) |  |  | 2003 |
Turbine restructuring accrual |  | $ | 24,824 |  |  | $ | (15,805 | ) |  | $ | (473 | ) |  | $ | 8,546 |

(1) | In March 2003, it was determined that the actual invoices for the steam turbine equipment cancellations were less than the amount which had been accrued as of December 31, 2002.

The following table sets forth in the Company’s restructuring reserves as of December 31, 2004 (in thousands):

|  | As of |  |  |  |  |  |  | As of |
|  | December 31, |  |  |  |  | Adjustments to |  | December 31, |
|  | 2003 |  |  | Payments |  |  | Accrual(1) |  | 2004 |
Turbine restructuring accrual |  | $ | 8,546 |  |  | $ | (4,498 | ) |  | $ | — |  |  | $ | 4,048 |

In July 2003, the Company completed a restructuring of its existing agreements with Siemens Westinghouse Power Corporation for 20 gas and 2 steam turbines. The new agreement provides for later payment dates, which are in line with the Company’s construction program. The table below sets forth future turbine payments for construction and development projects, as well as for unassigned turbines. It includes previously delivered turbines, payments and delivery year for the last turbine to be delivered as well as payment required for the potential cancellation costs of the remaining 38 gas and steam turbines. The table does not include payments that would result if the Company were to release for manufacturing any of these remaining 38 turbines.

|  |  |  | Units to be |
Year |  | Total |  |  | Delivered |
|  | (In thousands) |  |  |
2005 |  | $ | 27,463 |  |  |  | 1 |
2006 |  |  | 4,862 |  |  |  | — |
2007 |  |  | 977 |  |  |  | — |
| Total |  | $ | 33,302 |  |  |  | 1 |

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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other Restructuring Charges — In fiscal years 2002, 2003 and 2004, in connection with management’s plan to reduce costs and improve operating efficiencies, the Company recorded restructuring charges primarily comprised of severance and benefits related to the involuntary termination of employees and charges related to the vacancy of a number of facilities.
The following table sets forth the Company’s restructuring reserves relating to its vacancy of various facilities as of December 31, 2003 (in thousands):

|  | As of |  |  |  |  | Reclass |  |  |  |  |  |  | As of |
|  | December 31, |  |  |  |  | from |  |  |  |  | Adjustments |  |  | December 31, |
|  | 2002 |  |  | Additions |  |  | Long-term |  |  | Amortization |  |  | to Accrual |  |  | 2003 |
Accrued rent — Short-term |  | $ | 4,009 |  |  | $ | 2,062 |  |  | $ | 825 |  |  | $ | (3,718 | ) |  | $ | (166 | ) |  | $ | 3,012 |
Accrued rent — Long-term |  |  | 2,370 |  |  |  | 8,341 |  |  |  | (825 | ) |  |  | (162 | ) |  |  | 195 |  |  |  | 9,919 |
Total accrued rent liability |  | $ | 6,379 |  |  | $ | 10,403 |  |  | $ | — |  |  | $ | (3,880 | ) |  | $ | 29 |  |  | $ | 12,931 |

The following table sets forth the Company’s restructuring reserves relating to its vacancy of various facilities as of December 31, 2004 (in thousands):

|  | As of |  |  |  |  | Reclass |  |  |  |  |  |  |  |  | As of |
|  | December 31, |  |  |  |  | from |  |  |  |  |  |  | Adjustments |  |  | December 31, |
|  | 2003 |  |  | Additions |  |  | Long-term |  |  | Amortization |  |  | Accretion |  |  | to Accrual |  |  | 2004 |
Accrued rent — Short-term |  | $ | 3,012 |  |  | $ | 1,313 |  |  | $ | 2,512 |  |  | $ | (2,585 | ) |  | $ | — |  |  | $ | 12 |  |  | $ | 4,264 |
Accrued rent — Long-term |  |  | 9,919 |  |  |  | 354 |  |  |  | (2,512 | ) |  |  | — |  |  |  | 1,325 |  |  |  | 54 |  |  |  | 9,140 |
Total accrued rent liability |  | $ | 12,931 |  |  | $ | 1,667 |  |  | $ | — |  |  | $ | (2,585 | ) |  | $ | 1,325 |  |  | $ | 66 |  |  | $ | 13,404 |

The 2003 charge of $10.4 million was recorded in the “Sales, general and administrative expense” line item on the Consolidated Statements of Operations for the year ended December 31, 2003. In 2004 $1.5 million of the vacancy related charges were recorded in the “Discontinued operations, net” line and $0.1 million in the “Sales, general and administrative expense” line of the Consolidated Statement of Operations as of December 31, 2004.
The following table sets forth the Company’s restructuring reserves relating to its involuntary termination of employees as of December 31, 2003 (in thousands):

|  | As of |  |  |  |  |  |  |  |  | As of |
|  | December 31, |  |  |  |  |  |  |  |  | December 31, |
|  | 2002 |  |  | Additions |  |  | Payments |  |  | Adjustments |  |  | 2003 |
Severance liability |  | $ | 1,556 |  |  | $ | 3,914 |  |  | $ | (5,191 | ) |  | $ | 414 |  |  | $ | 693 |

The following table sets forth the Company’s restructuring reserves relating to its involuntary termination of employees as of December 31, 2004 (in thousands):

|  | As of |  |  |  |  |  |  |  |  | As of
|  | December 31, |  |  |  |  |  |  |  |  | December 31,
|  | 2003 |  |  | Additions |  |  | Payments |  |  | Adjustments |  |  | 2004
Severance liability |  | $ | 693 |  |  | $ | 6,154 |  |  | $ | (5,292 | ) |  | $ | (1,555 | ) |  | $ | — |

Severance-related charges of $1.1 million were recorded in the “Plant operating expense” line with the remaining $2.8 million in the “Selling, general and administrative expense” line of the Consolidated Statements of Operations for the year ended December 31, 2003. Severance-related charges of $6.2 million were recorded in the “Discontinued operations, net” line of the Consolidated Statement of Operations for the year ended December 31, 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Power Plant Operating Leases — The Company has entered into long-term operating leases for power generating facilities, expiring through 2049, including renewal options. Many of the lease agreements provide for renewal options at fair value, and some of the agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance agreements. In accordance with SFAS No. 13 and SFAS No. 98 the Company’s operating leases are not reflected on our balance sheet. Lease payments on the Company’s operating leases which contain escalation clauses or step rent provisions are recognized on a straight-line basis. Certain capital improvements associated with leased facilities may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Future minimum lease payments under these leases are as follows (in thousands):

|  | Initial |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Year |  |  | 2005 |  |  | 2006 |  |  | 2007 |  |  | 2008 |  |  | 2009 |  |  | Thereafter |  |  | Total |
Watsonville |  |  | 1995 |  |  | $ | 2,905 |  |  | $ | 2,905 |  |  | $ | 2,905 |  |  | $ | 2,905 |  |  | $ | 4,065 |  |  | $ | — |  |  | $ | 15,685 |
Greenleaf |  |  | 1998 |  |  |  | 8,723 |  |  |  | 8,650 |  |  |  | 8,650 |  |  |  | 7,495 |  |  |  | 8,490 |  |  |  | 29,643 |  |  |  | 71,651 |
Geysers |  |  | 1999 |  |  |  | 55,890 |  |  |  | 47,991 |  |  |  | 47,150 |  |  |  | 42,886 |  |  |  | 34,566 |  |  |  | 106,017 |  |  |  | 334,500 |
KIAC |  |  | 2000 |  |  |  | 24,077 |  |  |  | 23,875 |  |  |  | 23,845 |  |  |  | 24,473 |  |  |  | 24,537 |  |  |  | 240,082 |  |  |  | 360,889 |
Rumford/ Tiverton |  |  | 2000 |  |  |  | 44,942 |  |  |  | 45,000 |  |  |  | 45,000 |  |  |  | 45,000 |  |  |  | 45,000 |  |  |  | 563,292 |  |  |  | 788,234 |
South Point |  |  | 2001 |  |  |  | 9,620 |  |  |  | 9,620 |  |  |  | 9,620 |  |  |  | 9,620 |  |  |  | 9,620 |  |  |  | 307,190 |  |  |  | 355,290 |
RockGen |  |  | 2001 |  |  |  | 27,031 |  |  |  | 26,088 |  |  |  | 27,478 |  |  |  | 28,732 |  |  |  | 29,360 |  |  |  | 169,252 |  |  |  | 307,941 |
| Total |  |  |  |  |  | $ | 173,188 |  |  | $ | 164,129 |  |  | $ | 164,648 |  |  | $ | 161,111 |  |  | $ | 155,638 |  |  | $ | 1,415,476 |  |  | $ | 2,234,190 |

In 2004, 2003, and 2002, rent expense for power plant operating leases amounted to $105.9 million, $112.1 million and $111.0 million, respectively. Calpine guarantees $1.6 billion of the total future minimum lease payments of its consolidated subsidiaries.
On May 19, 2004, the Company restructured the King City power plant operating lease. Due to the lease extension and other modifications to the original lease, the lease classification was reevaluated under SFAS No. 13 and determined to be a capital lease. See Notes 3 and 13 for more information on the restructuring.
Production Royalties and Leases — The Company is committed under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on CPI changes and are not material. Under the terms of most geothermal leases, prior to May 1999, when the Company consolidated the steam field and power plant operations in Lake and Sonoma Counties in northern California (“The Geysers”), royalties were based on steam and effluent revenue. Following the consolidation of operations, the royalties began to accrue as a percentage of electrical revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level.
Production royalties for gas-fired and geothermal facilities for the years ended December 31, 2004, 2003, and 2002, were $28.7 million, $24.9 million and $17.6 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Office and Equipment Leases — The Company leases its corporate, regional and satellite offices as well as some of its office equipment under noncancellable operating leases expiring through 2014. Future minimum lease payments under these leases are as follows (in thousands):

2005 |  | $ | 29,244 |
2006 |  |  | 24,415 |
2007 |  |  | 22,299 |
2008 |  |  | 21,291 |
2009 |  |  | 21,127 |
Thereafter |  |  | 58,172 |
| Total |  | $ | 176,548 |

Lease payments are subject to adjustments for the Company’s pro rata portion of annual increases or decreases in building operating costs. In 2004, 2003, and 2002, rent expense for noncancellable operating leases amounted to $29.7 million, $21.6 million and $25.8 million, respectively.
Natural Gas Purchases — The Company enters into gas purchase contracts of various terms with third parties to supply gas to its gas-fired cogeneration projects.
Gas Pipeline Transportation in Canada — To support production and marketing operations, Calpine, through CES, has firm commitments in the ordinary course of business for gathering, processing and transmission services that require the Company to deliver certain minimum quantities of natural gas to third parties or pay the corresponding tariffs. The agreements expire at various times through 2017. Estimated payments to be made under these arrangements are $39.9 million, $33.4 million, $31.8 million, $31.1 million, $27.8 million and $115.0 million for each of the next five years and thereafter, respectively.
Guarantees — As part of normal business, Calpine enters into various agreements providing, or otherwise arranges, financial or performance assurance to third parties on behalf of its subsidiaries. Such arrangements include guarantees, standby letters of credit and surety bonds. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes.
Calpine routinely issues guarantees to third parties in connection with contractual arrangements entered into by Calpine’s direct and indirect wholly owned subsidiaries in the ordinary course of such subsidiaries’ respective business, including power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of Calpine’s fleet of power generating facilities and natural gas facilities. Under these guarantees, if the subsidiary in question were to fail to perform its obligations under the guaranteed contract, giving rise to a default and/or an amount owing by the subsidiary to the third party under the contract, Calpine could be called upon to pay such amount to the third party or, in some instances, to perform the subsidiary’s obligations under the contract. It is Calpine’s policy to attempt to negotiate specific limits or caps on Calpine’s overall liability under these types of guarantees; however, in some instances, Calpine’s liability is not limited by way of such a contractual liability cap.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
At December 31, 2004, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in thousands):

Commitments Expiring |  | 2005 |  |  | 2006 |  |  | 2007 |  |  | 2008 |  |  | 2009 |  |  | Thereafter |  |  | Total |
Guarantee of subsidiary debt |  | $ | 18,333 |  |  | $ | 16,284 |  |  | $ | 18,798 |  |  | $ | 1,930,657 |  |  | $ | 19,848 |  |  | $ | 1,133,896 |  |  | $ | 3,137,817 |
Standby letters of credit(1)(3) |  |  | 579,607 |  |  |  | 3,641 |  |  |  | 2,802 |  |  |  | 400 |  |  |  | — |  |  |  | — |  |  |  | 586,450 |
Surety bonds(2)(3) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 12,531 |  |  |  | 12,531 |
Guarantee of subsidiary operating lease payments(3) |  |  | 83,169 |  |  |  | 81,772 |  |  |  | 82,487 |  |  |  | 115,604 |  |  |  | 113,977 |  |  |  | 1,163,783 |  |  |  | 1,640,792 |
| Total |  | $ | 681,109 |  |  | $ | 101,697 |  |  | $ | 104,087 |  |  | $ | 2,046,661 |  |  | $ | 133,825 |  |  | $ | 2,310,210 |  |  | $ | 5,377,589 |

(1) | The standby letters of credit disclosed above include those disclosed in Notes 12, 15 and 16.
(2) | The surety bonds do not have expiration or cancellation dates.
(3) | These are off balance sheet obligations.

The balance of the guarantees of subsidiary debt, standby letters of credit and surety bonds were as follows (in thousands):

|  | Balance at December 31, |
|  | 2004 |  |  | 2003 |
Guarantee of subsidiary debt |  | $ | 3,137,817 |  |  | $ | 4,102,829 |
Standby letters of credit |  |  | 586,450 |  |  |  | 410,803 |
Surety bonds |  |  | 12,531 |  |  |  | 70,480 |
|  | $ | 3,736,798 |  |  | $ | 4,584,112 |

The Company has guaranteed the principal payment of $2,139.7 million and $2,448.6 million, as of December 31, 2004 and 2003, respectively, of Senior Notes for two wholly owned finance subsidiaries of Calpine, Calpine Canada Energy Finance ULC and Calpine Canada Energy Finance II ULC. As of December 31, 2004, the Company has guaranteed $275.1 million and $72.4 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant and $291.6 million and $71.8 million, respectively, as of December 31, 2003, for these power plants. In 2004 and 2003 the Company has debenture obligations in the amount of $517.5 million and $1,153.5 million, respectively, the payment of which will fund the obligations of the Trusts (see Note 12 for more information). The Company agreed to indemnify Duke Capital Corporation $101.4 million and $101.7 million as of December 31, 2004 and 2003, respectively, in the event Duke Capital Corporation is required to make any payments under its guarantee of the lease of the Hidalgo Energy Center. As of December 31, 2004 and 2003, the Company has also guaranteed $31.7 million and $35.6 million, respectively, of other miscellaneous debt. All of the guaranteed debt is recorded on the Company’s Consolidated Balance Sheet.
Calpine has guaranteed the payment of a portion of the rents due under the lease of the Greenleaf generating facilities in California, which lease is between an owner trustee acting on behalf of Union Bank of California, as lessor, and a Calpine subsidiary, Calpine Greenleaf, Inc., as lessee. Calpine does not currently meet the requirements of a financial covenant contained in the guarantee agreement. The lessor has waived this non-compliance through April 30, 2005, and Calpine is currently in discussions with the lessor concerning the possibility of modifying the lease and/or Calpine’s guarantee thereof so as to eliminate or modify the covenant in question. In the event the lessor’s waiver were to expire prior to completion of this amendment, the lessor could at that time elect to accelerate the payment of certain amounts owing under the lease, totaling approximately $15.9 million. In the event the lessor were to elect to require Calpine to make this payment, the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
lessor’s remedy under the guarantee and the lease would be limited to taking steps to collect damages from Calpine; the lessor would not be entitled to terminate or exercise other remedies under the Greenleaf lease.
In connection with several of the Company’s subsidiaries’ lease financing transactions (Greenleaf, Pasadena, Broad River, RockGen and South Point) the insurance policies the Company has in place do not comply in every respect with the insurance requirements set forth in the financing documents. The Company has requested from the relevant financing parties, and is expecting to receive, waivers of this noncompliance. While failure to have the required insurance in place is listed in the financing documents as an event of default, the financing parties may not unreasonably withhold their approval of the Company’s waiver request so long as the required insurance coverage is not reasonably available or commercially feasible and the Company delivers a report from its insurance consultant to that effect.
The Company has delivered the required insurance consultant reports to the relevant financing parties and therefore anticipates that the necessary waivers will be executed shortly.
Calpine routinely arranges for the issuance of letters of credit and various forms of surety bonds to third parties in support of its subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of its partially owned subsidiaries up to the Company’s ownership percentage. The letters of credit outstanding under various credit facilities support CES risk management, and other operational and construction activities. Of the total letters of credit outstanding, $2.5 million and $14.5 million were issued to support CES risk management at December 31, 2004 and 2003, respectively. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, Calpine would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of 1 to 10 days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included in the Consolidated Balance Sheets.
At December 31, 2004, investee debt was $126.3 million. Based on the Company’s ownership share of each of the investments, the Company’s share would be approximately $43.3 million. However, all such debt is non-recourse to the Company.
In the course of its business, Calpine and its subsidiaries have entered into various purchase and sale agreements relating to stock and asset acquisitions or dispositions. These purchase and sale agreements customarily provide for indemnification by each of the purchaser and the seller, and/or their respective parent, to the counter-party for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction. The Company has no reason to believe that it currently has any material liability relating to such routine indemnification obligations.
Additionally, Calpine and its subsidiaries from time to time assume other indemnification obligations in conjunction with transactions other than purchase or sale transactions. These indemnification obligations generally have a discrete term and are intended to protect our counterparties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction, such as the costs associated with litigation that may result from the transaction. The Company has no reason to believe that it currently has any material liability relating to such routine indemnification obligations.
Calpine has in a few limited circumstances directly or indirectly guaranteed the performance of obligations by unrelated third parties. These circumstances have arisen in situations in which a third party has contractual obligations with respect to the construction, operation or maintenance of a power generating facility or related equipment owned in whole or in part by Calpine. Generally, the third party’s obligations with respect to related equipment are guaranteed for the direct or indirect benefit of Calpine by the third party’s parent or other party. A financing party or investor in such facility or equipment may negotiate for Calpine also

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
to guarantee the performance of such third party’s obligations as additional support for the third party’s obligations. For example, in conjunction with the financing of California peaker program, Calpine guaranteed for the benefit of the lenders certain warranty obligations of third party suppliers and contractors. Calpine has entered into few guarantees of unrelated third party’s obligations. Calpine has no reason to believe that it currently has any liability with respect to these guarantees.
The Company believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.

| Litigation

The Company is party to various litigation matters arising out of the normal course of business, the more significant of which are summarized below. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability the Company 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 of these matters, may potentially be material to the Company’s Consolidated Financial Statements.
Securities Class Action Lawsuits. Beginning on March 11, 2002, fifteen securities class action complaints were filed in the U.S. District Court for the Northern District of California against Calpine and certain of its employees, officers, and directors. All of these actions were ultimately assigned to Judge Saundra Brown Armstrong, and Judge Armstrong ordered the actions consolidated for all purposes on August 16, 2002, as In re Calpine Corp. Securities Litigation, Master File No. C 02-1200 SBA. There is currently only one claim remaining from the consolidated actions: a claim for violation of Section 11 of the Securities Act of 1933 (“Securities Act”). The Court has dismissed all of the claims brought under Section 10(b) of the Securities Exchange Act of 1934 with prejudice.
On October 17, 2003, plaintiffs filed their third amended complaint (“TAC”), which alleges violations of Section 11 of the Securities Act by Calpine, Peter Cartwright, Ann B. Curtis and Charles B. Clark, Jr. The TAC alleges that the registration statement and prospectuses for Calpine’s 2011 Notes contained materially false or misleading statements about the factors that caused the power shortages in California in 2000-2001 and the resulting increase in wholesale energy prices. The TAC alleges that the true but undisclosed cause of the energy crisis is that Calpine and other power producers were engaging in physical withholding of electricity. In discovery, plaintiff has argued that the TAC is not based solely on allegedly concealed physical withholding, but instead is based on alleged undisclosed market manipulation in the form of physical withholding, economic withholding, and trading strategies. The TAC defines the potential class to include all purchasers of the Notes pursuant to the registration statement and prospectuses on or before January 27, 2003. The Court has not yet certified the class. The class certification hearing will be set for May 3, 2005.
On April 15, 2004, The Policemen and Firemen Retirement System of the City of Detroit (the “Detroit Fund”) filed a request to be appointed as lead plaintiff in the case. The Court granted the Detroit Fund’s request for appointment as lead plaintiff on May 7, 2004. The Court also approved the Detroit Fund’s choice of Kohn, Swift & Graf, P.C. (Philadelphia) as lead counsel for the class.
At the Court’s invitation, defendants subsequently moved for summary judgment on grounds that the Section 11 claim was barred by the statute of limitations. On November 2, 2004, the Court denied the motion on grounds that defendants had not established as a matter of law that plaintiff was on notice of the alleged misstatement prior to January 27, 2002, one year before plaintiff first alleged that Calpine had misrepresented the causes of the energy crisis. The Court has set a November 7, 2005 trial date. Fact discovery will close on July 1, 2005. We consider the lawsuit to be without merit and intend to continue to defend vigorously against the allegations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. This case is a Section 11 case brought as a class action on behalf of purchasers in Calpine’s April, 2002 stock offering. This case was filed in San Diego County Superior Court on March 11, 2003, but defendants won a motion to transfer the case to Santa Clara County. Defendants in this case are Calpine, Cartwright, Curtis, John Wilson, Kenneth Derr, George Stathakis, CSFB, Banc of America Securities, Deutsche Bank Securities, and Goldman, Sachs & Co. Plaintiff is the Hawaii Structural Ironworkers Pension Trust Fund.
The Hawaii Fund alleges that the prospectus and registration statement for the April 2002 offering had false or misleading statements regarding: Calpine’s actual financial results for 2000 and 2001; Calpine’s projected financial results for 2002; Cartwright’s agreement not to sell or purchase shares within 90 days of the offering; and Calpine’s alleged involvement in “wash trades.” The core allegation of the complaint is that a March 2003 restatement (concerning two sales-leaseback transactions) revealed that Calpine had misrepresented its financial results in the prospectus/registration statement for the April 2002 offering.
There is no discovery cut off date or trial date in this action. The next scheduled court hearing will be a case management conference on July 5, 2005, at which time the court should set a discovery deadline and trial date. We consider this lawsuit to be without merit and intend to continue to defend vigorously against the allegations.
Phelps v. Calpine Corporation, et al. On April 17, 2003, James Phelps filed a class action complaint in the Northern District of California, alleging claims under the Employee Retirement Income Security Act (“ERISA”). On May 19, 2003, a nearly identical class action complaint was filed in the Northern District by Lenette Poor-Herena. The parties agreed to have both of the ERISA actions assigned to Judge Armstrong, who oversees the above-described federal securities class action and the Gordon derivative action (see below). On August 20, 2003, pursuant to an agreement between the parties, Judge Armstrong ordered that the two ERISA actions be consolidated under the caption, In re Calpine Corp. ERISA Litig., Master File No. C 03-1685 SBA (the “ERISA Class Action”). Plaintiff James Phelps filed a consolidated ERISA complaint on January 20, 2004 (“Consolidated Complaint”). Ms. Poor-Herena is not identified as a plaintiff in the Consolidated Complaint.
The Consolidated Complaint defines the class as all participants in, and beneficiaries of, the Calpine Corporation Retirement Savings Plan (the “Plan”) for whose accounts investments were made in Calpine stock during the period from January 5, 2001 to the present. The Consolidated Complaint names as defendants Calpine, the members of its Board of Directors, the Plan’s Advisory Committee and its members (Kati Miller, Lisa Bodensteiner, Rick Barraza, Tom Glymph, Patrick Price, Trevor Thor, Bob McCaffrey, and Bryan Bertacchi), signatories of the Plan’s Annual Return/ Report of Employee Benefit Plan Forms 5500 for 2001 and 2002 (Pamela J. Norley and Marybeth Kramer-Johnson, respectively), an employee of a consulting firm hired by the Plan (Scott Farris), and unidentified fiduciary defendants.
The Consolidated Complaint alleges that defendants breached their fiduciary duties involving the Plan, in violation of ERISA, by misrepresenting Calpine’s actual financial results and earnings projections, failing to disclose certain transactions between Calpine and Enron that allegedly inflated Calpine’s revenues, failing to disclose that the shortage of power in California during 2000-2001 was due to withholding of capacity by certain power companies, failing to investigate whether Calpine common stock was an appropriate investment for the Plan, and failing to take appropriate actions to prevent losses to the Plan. In addition, the consolidated ERISA complaint alleges that certain of the individual defendants suffered from conflicts of interest due to their sales of Calpine stock during the class period.
Defendants moved to dismiss the consolidated complaint. At a February 11, 2005 hearing, Judge Armstrong granted the motion and dismissed three of the four claims with prejudice. The fourth claim was dismissed with leave to amend. This claim was based, in part, on the same statements that are at issue in the Section 11 bond class action. Plan participants did not receive the prospectus supplements that are at issue in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
the Section 11 bond class action, but plaintiffs’ counsel told Judge Armstrong that these statements appeared in documents that were given to Plan participants. Relying on assurances by plaintiffs’ counsel that misstatements about the California energy crisis appeared in documents that were given to Plan participants (or that were incorporated by reference into documents given to participants), the Court granted leave to re-plead this claim. We expect the second amended consolidated complaint to be due in the near future. We consider this lawsuit to be without merit and intend to continue to defend vigorously against the allegations.
Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of Calpine against its directors and one of its senior officers. This lawsuit is styled Johnson vs. Cartwright, et al. (No. CV803872) and is pending in state superior court of Santa Clara County, California. Calpine is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about Calpine and stock sales by certain of the director defendants and the officer defendant. In December 2002, the court dismissed the complaint with respect to certain of the director defendants for lack of personal jurisdiction, though plaintiff may appeal this ruling. In early February 2003, plaintiff filed an amended complaint, naming a few additional officer defendants. Calpine and the individual defendants filed demurrers (motions to dismiss) and a motion to stay the case in March 2003. On July 1, 2003, the Court granted Calpine’s motion to stay this proceeding until the above-described Section 11 action is resolved, or until further order of the Court. We consider the lawsuit to be without merit.
Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a derivative suit in the United States District Court for the Northern District of California on behalf of Calpine against its directors, captioned Gordon v. Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to dismiss the action against certain of the director defendants on the grounds of lack of personal jurisdiction, as well as to dismiss the complaint in total on other grounds. In February 2003, plaintiff agreed to stay these proceedings until the above-described federal Section 11 action is resolved, and to dismiss without prejudice certain director defendants. On March 4, 2003, plaintiff filed papers with the court voluntarily agreeing to dismiss without prejudice his claims against three of the outside directors. We consider this lawsuit to be without merit.
International Paper Company v. Androscoggin Energy LLC. In October 2000, International Paper Company filed a complaint against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties arising out of an Amended Energy Services Agreement (“ESA”) by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. The steam price paid by IP under the ESA is derived from AELLC’s cost of gas under its gas supply agreements. We had acquired a 32.3% economic interest and a 49.5% voting interest in AELLC as part of the Skygen transaction, which closed in October 2000. AELLC filed a counterclaim against International Paper Company that has been referred to arbitration that AELLC may commence at its discretion upon further evaluation. On November 7, 2002, the court issued an opinion on the parties’ cross motions for summary judgment finding in AELLC’s favor on certain matters though granting summary judgment to International Paper Company on the liability aspect of a particular claim against AELLC. The court also denied a motion submitted by IP for preliminary injunction to permit IP to make payment of funds into escrow (not directly to AELLC) and require AELLC to post a significant bond.
In mid-April of 2003, IP unilaterally availed itself to self-help in withholding amounts in excess of $2 million as a setoff for litigation expenses and fees incurred to date as well as an estimated portion of a rate fund to AELLC. AELLC has submitted an amended complaint and request for immediate injunctive relief against such actions. The court heard the motion on April 24, 2003 and ordered that IP must pay the approximate $1.2 million withheld as attorneys’ fees related to the litigation as any such perceived entitlement was premature, but declined to order injunctive relief on the incomplete record concerning the offset of $799,000 as an estimated pass-through of the rate fund. IP complied with the order on April 29, 2003 and tendered payment to AELLC of the approximate $1.2 million. On June 26, 2003, the court entered an order

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
dismissing AELLC’s amended counterclaim without prejudice to AELLC re-filing the claims as breach of contract claims in a separate lawsuit. On December 11, 2003, the court denied in part IP’s summary judgment motion pertaining to damages. In short, the court: (i) determined that, as a matter of law, IP is entitled to pursue an action for damages as a result of AELLC’s breach, and (ii) ruled that sufficient questions of fact remain to deny IP summary judgment on the measure of damages as IP did not sufficiently establish causation resulting from AELLC’s breach of contract (the liability aspect of which IP obtained a summary judgment in December 2002). On February 2, 2004, the parties filed a Final Pretrial Order with the court. The case recently proceeded to trial, and on November 3, 2004, a jury verdict in the amount of $41 million was rendered in favor of IP. AELLC was held liable on the misrepresentation claim, but not on the breach of contract claim. The verdict amount was based on calculations proffered by IP’s damages experts. AELLC has made an additional accrual to recognize the jury verdict and the Company has recognized its 32.3% share.
AELLC filed a post-trial motion challenging both the determination of its liability and the damages award and, on November 16, 2004, the court entered an order staying the execution of the judgment. The order staying execution of the judgment has not expired. If the judgment is not vacated as a result of the post-trial motions, AELLC intends to appeal the judgment.
Additionally, on November 26, 2004, AELLC filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. As noted above, we had acquired a 32.3% economic interest and a 49.5% voting interest in AELLC as part of the Skygen transaction, which closed in October 2000. AELLC is continuing in possession of its property and is operating and maintaining its business as a debtor in possession, pursuant to Section 1107(a) and 1108 of the Bankruptcy Code. No request has been made for the appointment of a trustee or examiner in the proceeding, and no official committee of unsecured creditors has yet been appointed by the Office of the United States Trustee.
Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On November 5, 2003, Panda Energy International, Inc. and certain related parties, including PLC II, LLC, (collectively “Panda”) filed suit against Calpine and certain of its affiliates in the United States District Court for the Northern District of Texas, alleging, among other things, that the Company breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta Energy Center (“Oneta”), which the Company acquired from Panda, in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits from Oneta and that Calpine’s actions have reduced the profits from Oneta thereby undermining Panda’s ability to repay monies owed to Calpine on December 1, 2003, under a promissory note on which approximately $38.6 million (including interest through December 1, 2003) is currently outstanding and past due. The note is collateralized by Panda’s carried interest in the income generated from Oneta, which achieved full commercial operations in June 2003. Calpine filed a counterclaim against Panda Energy International, Inc. (and PLC II, LLC) based on a guaranty and a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The court recently granted Calpine’s motion to dismiss, but allowed Panda an opportunity to re-plead. The Company considers Panda’s lawsuit to be without merit and intends to vigorously defend it. Discovery is currently in progress. The Company stopped accruing interest income on the promissory note due December 1, 2003, as of the due date because of Panda’s default in repayment of the note.
California Business & Professions Code Section 17200 Cases, of which the lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al. This purported class action complaint filed in May 2002 against 20 energy traders and energy companies, including CES, alleges that defendants exercised market power and manipulated prices in violation of California Business & Professions Code Section 17200 et seq., and seeks injunctive relief, restitution, and attorneys’ fees. The Company also has been named in eight other similar complaints for violations of Section 17200. All eight cases were removed from the various state courts in which they were originally filed to federal court for pretrial proceedings with other cases in which the Company is not named as a defendant. However, at the present time, the Company cannot estimate the

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potential loss, if any, that might arise from this matter. The Company considers the allegations to be without merit, and filed a motion to dismiss on August 28, 2003. The court granted the motion, and plaintiffs have appealed.
Prior to the motion to dismiss being granted, one of the actions, captioned Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to state superior court of Alameda County, California. On January 12, 2004, CES was added as a defendant in Millar. This action includes similar allegations to the other Section 17200 cases, but also seeks rescission of the long-term power contracts with the California Department of Water Resources. Millar was removed to federal court and transferred to the same judge that is presiding over the other Section 17200 cases described above, where it was to be consolidated. However, that judge recently remanded the case back to state superior court for handling.
Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy Services, L.P. before the FERC, filed on December 4, 2001, Nevada Section 206 Complaint. On December 4, 2001, Nevada Power Company (“NPC”) and Sierra Pacific Power Company (“SPPC”) filed a complaint with FERC under Section 206 of the Federal Power Act against a number of parties to their power sales agreements, including Calpine. NPC and SPPC allege in their complaint, that the prices they agreed to pay in certain of the power sales agreements, including those signed with Calpine, were negotiated during a time when the spot power market was dysfunctional and that they are unjust and unreasonable. The complaint therefore sought modification of the contract prices. The administrative law judge issued an Initial Decision on December 19, 2002, that found for Calpine and the other respondents in the case and denied NPC and SPPC the relief that they were seeking. In a June 26, 2003 order, FERC affirmed the judge’s findings and dismissed the complaint, and subsequently denied rehearing of that order. The matter is pending on appeal before the United States Court of Appeals for the Ninth Circuit. The Company has participated in briefing and arguments before the Ninth Circuit defending the FERC orders, but the Company is not able to predict at this time the outcome of the Ninth Circuit appeal.
Transmission Service Agreement with Nevada Power Company. On March 16, 2004, NPC filed a petition for declaratory order at FERC (Docket No. EL04-90-000) asking that an order be issued requiring Calpine and Reliant Energy Services, Inc. (“Reliant”) to pay for transmission service under their Transmission Service Agreements (“TSAs”) with NPC or, if the TSAs are terminated, to pay the lesser of the transmission charges or a pro rata share of the total cost of NPC’s Centennial Project (approximately $33 million for Calpine). The Centennial Project involves construction of various transmission facilities in two phases; Calpine’s Moapa Energy Center (“MEC”) was scheduled to receive service under its TSA from facilities yet to be constructed in the second phase of the Centennial Project. Calpine filed a protest to the petition asserting that (a) Calpine would take service under the TSA if NPC proceeds to execute a purchase power agreement (“PPA”) with MEC based on MEC’s winning bid in the Request for Proposals that NPC conducted in 2003; (b) if NPC did not execute a PPA with MEC, Calpine would terminate the TSA and any payment by Calpine would be limited to a pro rata allocation of certain costs incurred by NPC in connection with the second phase of the project (approximately $4.5 million in total to date) among the three customers to be served.
On November 18, 2004, FERC issued a decision in Docket No. EL04-90-000 which found that neither Calpine nor Reliant had the right to unilaterally terminate their respective TSAs, and that upon commencement of service both Calpine and Reliant would be obligated to pay either the associated demand charges for service or their respective share of the capital cost associated with the transmission upgrades that have been made in order to provide such service. The November 18, 2004 order, however, did not indicate the amount or measure of damages that would be owed to NPC in the event that either Calpine or Reliant breached its respective obligations under the TSAs.
On December 10, 2004, NPC filed a request for rehearing of the November 18, 2004 decision, alleging that FERC had erred in holding that a determination of damages for breach of either Calpine or Reliant was

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premature and that both Calpine and Reliant had breached their respective TSAs. Calpine filed an answer on January 4, 2005 requesting that FERC deny NPC’s request for rehearing. NPC’s request for rehearing remains pending before FERC for further consideration. The Company cannot predict how FERC will rule on NPC’s rehearing request.
In light of the November 18, 2004 order, on November 22, 2004 Calpine delivered to NPC a notice (the “November 22, 2004 Letter”) that it did not intend to perform its obligations under the Calpine TSA, that NPC should exercise its duty to mitigate its damages, if any, and that NPC should not incur any additional costs or expenses in reliance upon the TSA for Calpine’s account. Calpine introduced the November 22, 2004 Letter into evidence in proceedings before the Public Utilities Commission of Nevada (“PUCN”) regarding NPC’s third amendment to its integrated resource plan (“Resource Plan”). In the Resource Plan, NPC sought approval to proceed with the construction of the second phase of the Centennial Project (the transmission project intended to serve the Calpine and Reliant TSAs) (the “HAM Line”). On December 28, 2004, the PUCN issued an order granting NPC’s request to proceed with the construction of the HAM Line. On January 11, 2005, Calpine filed a petition for reconsideration of the December 28, 2004 order. On February 9, 2005, the PUCN issued an order denying Calpine’s petitions For reconsideration. At this time Calpine is unable to predict the impact of the December 28, 2004 and the February 9, 2005 PUCN orders, if any on the District Court Complaint (discussed below) or any possible action by NPC before FERC regarding Calpine’s notice that it will not perform its obligations under the Calpine TSA.
Calpine had previously provided security to NPC for Calpine’s share of the HAM Line costs, in the form of a surety bond issued by Fireman’s Fund Insurance Company (“FFIC”). The bond issued by FFIC, by its terms, expired on May 1, 2004. On or about April 27, 2004, NPC asserted to FFIC that Calpine had committed a default under the bond by failing to agree to renew or replace the bond upon its expiration and made demand on FFIC for the full amount of the surety bond, $33,333,333. On April 29, 2004, FFIC filed a complaint for declaratory relief in state superior court of Marin County, California in connection with this demand.
FFIC’s complaint sought an order declaring that (a) FFIC has no obligation to make payment under the bond; and (b) if the court were to determine that FFIC has an obligation to make payment, then (i) Calpine has an obligation to replace it with funds equal to the amount of NPC’s demand against the bond and (ii) Calpine is obligated to indemnify and hold FFIC harmless for all loss, costs and fees incurred as a result of the issuance of the bond. Calpine filed an answer denying the allegations of the complaint and asserting affirmative defenses, including that it has fully performed its obligations under the TSA and surety bond. NPC filed a motion to quash service for lack of personal jurisdiction in California.
On September 3, 2004, the superior court granted NPC’s motion, and NPC was dismissed from the proceeding. Subsequently, FFIC agreed to dismiss the complaint as to Calpine. On September 30, 2004 NPC filed a complaint in state district court of Clark County, Nevada against Calpine, Moapa Energy Center, LLC, FFIC and unnamed parties alleging, among other things, breach by Calpine of its obligations under the TSA and breach by FFIC of its obligations under the surety bond. On November 4, 2004, the case was removed to Federal District Court. At this time, Calpine is unable to predict the outcome of this proceeding.
Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6, 2002, Calpine Canada Natural Gas Partnership (“Calpine Canada”) filed a complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp. (“Enron Canada”) owed it approximately US$1.5 million from the sale of gas in connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron Canada has not sought bankruptcy relief and has counterclaimed in the amount of US$18 million. Discovery is currently in progress, and the Company believes that Enron Canada’s counterclaim is without merit and intends to vigorously defend against it.

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Estate of Jones, et al. v. Calpine Corporation. On June 11, 2003, the Estate of Darrell Jones and the Estate of Cynthia Jones filed a complaint against Calpine in the United States District Court for the Western District of Washington. Calpine purchased Goldendale Energy, Inc., a Washington corporation, from Darrell Jones of National Energy Systems Company (“NESCO”). The agreement provided, among other things, that upon “Substantial Completion” of the Goldendale facility, Calpine would pay Mr. Jones (i) the fixed sum of $6.0 million and (ii) a decreasing sum equal to $18.0 million less $0.2 million per day for each day that elapsed between July 1, 2002, and the date of Substantial Completion. Substantial Completion of the Goldendale facility occurred in September 2004 and the daily reduction in the payment amount reduced the $18.0 million payment to zero. The complaint alleged that by not achieving Substantial Completion by July 1, 2002, Calpine breached its contract with Mr. Jones, violated a duty of good faith and fair dealing, and caused an inequitable forfeiture. On July 28, 2003, Calpine filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. The Court granted Calpine’s motion to dismiss the complaint on March 10, 2004. The Court denied the plaintiffs’ subsequent motions for reconsideration and for leave to amend, granted in part Calpine’s motion for an award of attorneys’ fees, and entered judgment dismissing the action. The plaintiffs appealed the dismissal to the United States Court of Appeals for the Ninth Circuit, where the matter is pending. Briefing is complete. Oral argument has not yet been scheduled. Calpine believes the facility reached Substantial Completion in the second half of 2004. Calpine thereafter paid to or for the benefit of the Jones estate the fixed sum of $6 million, which Calpine agreed it was obligated to pay upon Substantial Completion whenever achieved.
Calpine Energy Services v Acadia Power Partners. Calpine, through its subsidiaries, owns 50% of Acadia Power Partners, LLC (“APP”) which company owns the Acadia Energy Center near Eunice, Louisiana (the “Facility”). A Cleco Corp subsidiary owns the remaining 50% of APP. CES is the purchaser under two power purchase agreements with APP, which agreements entitle CES to all of the Facility’s capacity and energy. In August 2003 certain transmission constraints previously unknown to CES and APP began to severely limit the ability of CES to obtain all of the energy from the Facility. CES has asserted that it is entitled to certain relief under the purchase agreements, to which assertions APP disagrees. Accordingly, the parties are engaging in the initial alternative dispute resolution steps set forth in the power purchase agreements. It is possible that the dispute will result in binding arbitration pursuant to the agreements if a settlement is not reached. In addition, CES and APP are discussing certain billing calculation disputes which relate to efficiency matters. The dispute covers the time period from June 2002 (commercial operation date of the plant) to June 2004. It is expected that the parties will be able to resolve these disputes, and that APP could be liable to CES for an amount up to $3.1 million.
Hulsey, et al. v. Calpine Corporation. On September 20, 2004, Virgil D. Hulsey, Jr. (a current employee) and Ray Wesley (a former employee) filed a class action wage and hour lawsuit against Calpine Corporation and certain of its affiliates. The complaint alleges that the purported class members were entitled to overtime pay and Calpine failed to pay the purported class members at legally required overtime rates. The matter has been transferred to the Santa Clara County Superior Court and Calpine filed an answer on January 7, 2005, denying plaintiffs’ claims. the parties have agreed to discuss possible resolutions alternative to litigation.
Michael Portis v. Calpine Corp. — Department of Labor Claim. On January 25, 2005, Michael Portis (“Portis”), a former employee of Calpine, brought a complaint to the United States Department of Labor (the “DOL”), alleging that his employment with the Company was wrongfully terminated. Portis alleges that Calpine and its subsidiaries evaded sales and use tax in various states and in doing so filed false tax reports and that his employment was terminated in retaliation for having reported these allegations to management. Portis claims that the Company’s alleged actions constitute violations of the employee protection provisions of the Sarbanes Oxley Act of 2002. The Company considers Portis’ claims to be without merit and intends to vigorously defend against the allegations.

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Auburndale Power Partners and Cutrale. Calpine Corporation owns an interest in the Auburndale Power Partners cogeneration facility (the “APP facility”), which provides steam to Cutrale, a juice company. The APP facility currently operates on a “cycling” basis whereby the plant operates only a portion of the day. During the hours that the APP facility is not operating, APP does not provide Cutrale Steam. Cutrale has filed an arbitration claim alleging that they are entitled to damages due to APP’s failure to provide them with steam 24 hours a day. APP believes that Cutrale’s position is not supported by the language of the contract in place between APP and Cutrale and that it will prevail in arbitration. Nevertheless, to preserve its positive relationship with Cutrale, APP will continue to try to resolve the matter through a commercial settlement.
Sargent Electric Company v. Kvaerner-Songer Inc., et al. v. CCFC; McCarls Inc. v. Kvaerner-Songer Inc., CCFC, et al. On June 18, 2003, Kvaerner-Songer Inc. (“KSI”) filed a third-party complaint against CCFC in the Court of Common Pleas of Berks County, Pennsylvania, alleging material breach of contract and seeking unspecified damages in an amount in excess of the jurisdictional amount of $75,000. KSI, along with Kvaerner-Jaddco and Safeco Insurance Company of America were defendants in a claim filed by Sargent Electric Company (“Sargent”) in the Court of Common Pleas of Berks County, Pennsylvania on October 11, 2002, which claim alleged breach of contract stemming from Sargent’s work as an electrical subcontractor for KSI during construction of the Ontelaunee project, claiming, among other things, change in work scope, delays and increased costs. KSI’s third-party claim against CCFC alleged that CCFC was liable to KSI to the extent that Sargent was entitled to any recovery from KSI. In separate submittals to us, as part of our claims evaluation process, KSI informed us that Sargent had submitted claims in the amount of $5.7 million against KSI and KSI had submitted claims to us in the amount of $3.5 million. R.L. Bondy Inc. had submitted claims to KSI in the amount of approximately $1.7 million for miscellaneous work on the Ontelaunee project. On June 1, 2004, CCFC filed an answer, new matter and counterclaim specifically denying KSI’s allegations and requesting that the third party complaint be dismissed. In addition, CCFC submitted that KSI had breached its contract with respect to warranty, commissioning and acceleration matters and requested restitution in the amount of $7,744,586.
On February 3, 2004, McCarls Inc. (“McCarls”) filed suit against KSI and CCFC for unjust enrichment relating to certain piping work. McCarls had also filed claims for promissory estoppel and unjust enrichment against Calpine Corporation. These claims totaled approximately $12 million. In addition, in April 2004, KSI filed a cross claim against Calpine and CCFC alleging breach of contract. On April 12, 2004, the Court overruled preliminary objections filed by CCFC and Calpine in opposition to the complaint. Following the Court’s ruling, CCFC and Calpine filed a motion to extend the time to answer the McCarls complaint. The Court allowed Calpine’s motion to extend and on May 24, 2004 and June 1, 2004, Calpine filed its answer, new matter and counterclaim against McCarls and KSI respectively. Calpine and CCFC denied the allegations of both McCarls and KSI, requested that the actions be dismissed and filed a counterclaim for unjust enrichment, promissory estoppel and misrepresentation. In addition, Calpine filed a request for indemnification against KSI and asserted that KSI breached its contract with respect to warranty, commissioning and acceleration matters and requested restitution in the amount of $7,744,586.
On August 20, 2004, Sargent filed a companion case captioned Sargent Electric v. CCFC for Judgment of Foreclosure of Mechanic’s Lien. The underlying basis for the complaint stems from the same cause of action set forth above. An answer was to be filed by October 15, but the case was dismissed with prejudice on September 22, 2004.
The Sargent/ KSI and McCarls cases were settled on December 31, 2004 and January 28, 2005 respectively. Calpine paid a total sum of $14,250,000 to KSI (the general contractor) as part of the settlement of both cases and KSI paid a portion to Sargent (the electrical subcontractor) and to McCarls (the piping subcontractor). Calpine’s settlement payment was for construction costs of the Ontelaunee project.

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In addition, the Company is involved in various other claims and legal actions arising out of the normal course of its business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on its financial position or results of operations.

26. | Operating Segments

The Company is first and foremost an electric generating company. In pursuing this business strategy, it is the Company’s long-range objective to produce a portion of its fuel consumption requirements from its own natural gas reserves (“equity gas”). The Company’s oil and gas production and marketing activity has reached the quantitative criteria to be considered a reportable segment under SFAS No. 131. The Company’s segments are therefore electric generation and marketing; oil and gas production and marketing; and corporate and other activities. Electric generation and marketing includes the development, acquisition, ownership and operation of power production facilities, hedging, balancing, optimization, and trading activity transacted on behalf of the Company’s power generation facilities. Oil and gas production includes the ownership and operation of gas fields, gathering systems and gas pipelines for internal gas consumption, third party sales and hedging, balancing, optimization, and trading activity transacted on behalf of the Company’s oil and gas operations. Corporate activities and other consists primarily of financing transactions, activities of the Company’s parts and services businesses, including the Company’s specialty data center engineering business, which was divested in the third quarter of 2003, and general and administrative costs. Certain costs related to company-wide functions are allocated to each segment, such as interest expense, distributions on HIGH TIDES prior to October 1, 2003, and interest income, which are allocated based on a ratio of segment assets to total assets.
The Company evaluates performance based upon several criteria including profits before tax. The accounting policies of the operating segments are the same as those described in Note 2. The financial results for the Company’s operating segments have been prepared on a basis consistent with the manner in which the Company’s management internally disaggregates financial information for the purposes of assisting in making internal operating decisions.

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Due to the integrated nature of the business segments, estimates and judgments have been made in allocating certain revenue and expense items, and reclassifications have been made to prior periods to present the allocation consistently.

|  | Electric |  |  | Oil and Gas |  |  |  |  |
|  | Generation |  |  | Production |  |  | Corporate |  |  |
|  | and Marketing |  |  | and Marketing |  |  | and Other |  |  | Total |
|  | (In thousands) |
2004 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenue from external customers |  | $ | 9,102,959 |  |  | $ | 63,153 |  |  | $ | 63,776 |  |  | $ | 9,229,888 |
Intersegment revenues |  |  | — |  |  |  | 208,170 |  |  |  | — |  |  |  | 208,170 |
Depreciation and amortization |  |  | 486,927 |  |  |  | 85,225 |  |  |  | 2,048 |  |  |  | 574,200 |
Oil and gas impairment |  |  | — |  |  |  | 202,120 |  |  |  | — |  |  |  | 202,120 |
(Income) from unconsolidated investments in power projects and oil and gas properties |  |  | 13,525 |  |  |  | — |  |  |  | — |  |  |  | 13,525 |
Equipment cancellation and impairment costs |  |  | 42,374 |  |  |  | — |  |  |  | — |  |  |  | 42,374 |
Interest expense |  |  | 1,055,767 |  |  |  | 41,867 |  |  |  | 43,168 |  |  |  | 1,140,802 |
Interest (income) |  |  | (52,207 | ) |  |  | (2,070 | ) |  |  | (2,135 | ) |  |  | (56,412 | )
(Income) from repurchase of various issuances of debt |  |  | — |  |  |  | — |  |  |  | (246,949 | ) |  |  | (246,949 | )
Other (income) expense |  |  | (222,515 | ) |  |  | 5,221 |  |  |  | 68,201 |  |  |  | (149,093 | )
Income before taxes |  |  | (818,865 | ) |  |  | (207,602 | ) |  |  | 309,092 |  |  |  | (717,375 | )
Provision (benefit) for income taxes |  |  | (112,150 | ) |  |  | (167,654 | ) |  |  | 3,255 |  |  |  | (276,549 | )
Discontinued operations, net of tax |  |  | 22,956 |  |  |  | 175,409 |  |  |  | — |  |  |  | 198,365 |
Total assets |  |  | 25,187,414 |  |  |  | 998,810 |  |  |  | 1,029,864 |  |  |  | 27,216,088 |
Investments in power projects and oil and gas properties |  |  | 374,032 |  |  |  | — |  |  |  | — |  |  |  | 374,032 |
Property additions |  |  | 1,465,400 |  |  |  | 60,197 |  |  |  | 23,760 |  |  |  | 1,549,357 |
2003 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenue from external customers |  | $ | 8,773,574 |  |  | $ | 59,156 |  |  | $ | 38,303 |  |  | $ | 8,871,033 |
Intersegment revenues |  |  | — |  |  |  | 284,951 |  |  |  | — |  |  |  | 284,951 |
Depreciation and amortization |  |  | 407,547 |  |  |  | 93,733 |  |  |  | 3,103 |  |  |  | 504,383 |
Oil and gas impairment |  |  | — |  |  |  | 2,931 |  |  |  | — |  |  |  | 2,931 |
(Income) from unconsolidated investments in power projects and oil and gas properties |  |  | (75,804 | ) |  |  | — |  |  |  | — |  |  |  | (75,804 | )
Equipment cancellation and impairment cost |  |  | 64,384 |  |  |  | — |  |  |  | — |  |  |  | 64,384 |
Interest expense |  |  | 621,912 |  |  |  | 47,177 |  |  |  | 37,218 |  |  |  | 706,307 |
Interest (income) |  |  | (34,971 | ) |  |  | (2,652 | ) |  |  | (2,093 | ) |  |  | (39,716 | )
(Income) from repurchase of various issuances of debt |  |  | — |  |  |  | — |  |  |  | (278,612 | ) |  |  | (278,612 | )
Other (income) expense |  |  | (44,961 | ) |  |  | (47,941 | ) |  |  | 46,776 |  |  |  | (46,126 | )
Income before taxes |  |  | 124,627 |  |  |  | 135,459 |  |  |  | (165,481 | ) |  |  | 94,605 |
Provision (benefit) for income taxes |  |  | (23,497 | ) |  |  | (45,243 | ) |  |  | 77,235 |  |  |  | 8,495 |
Discontinued operations, net of tax |  |  | 2,694 |  |  |  | 23,546 |  |  |  | (11,271 | ) |  |  | 14,969 |
Cumulative effect of a change in accounting principle, net of tax |  |  | 183,270 |  |  |  | (1,443 | ) |  |  | (884 | ) |  |  | 180,943 |
Total assets |  |  | 24,041,450 |  |  |  | 1,823,751 |  |  |  | 1,438,731 |  |  |  | 27,303,932 |
Investments in power plants and oil and gas properties |  |  | 444,150 |  |  |  | — |  |  |  | — |  |  |  | 444,150 |
Property Additions |  |  | 1,737,159 |  |  |  | 107,644 |  |  |  | 15,822 |  |  |  | 1,860,625 |

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|  | Electric |  |  | Oil and Gas |  |  |  |  |
|  | Generation |  |  | Production |  |  | Corporate |  |  |
|  | and Marketing |  |  | and Marketing |  |  | and Other |  |  | Total |
|  | (In thousands) |
2002 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenue from external customers |  | $ | 7,103,972 |  |  | $ | 243,889 |  |  | $ | 1,892 |  |  | $ | 7,349,753 |
Intersegment revenues |  |  | — |  |  |  | 141,263 |  |  |  | — |  |  |  | 141,263 |
Depreciation and amortization |  |  | 298,928 |  |  |  | 91,926 |  |  |  | 8,035 |  |  |  | 398,889 |
Oil and gas impairment |  |  | — |  |  |  | 3,399 |  |  |  | — |  |  |  | 3,399 |
(Income) from unconsolidated investments in power projects and oil and gas properties |  |  | (16,552 | ) |  |  | — |  |  |  | — |  |  |  | (16,552 | )
Equipment cancellation and impairment costs |  |  | 404,737 |  |  |  | — |  |  |  | — |  |  |  | 404,737 |
Interest expense |  |  | 331,066 |  |  |  | 19,501 |  |  |  | 52,110 |  |  |  | 402,677 |
Interest (income) |  |  | (34,500 | ) |  |  | (3,182 | ) |  |  | (5,404 | ) |  |  | (43,086 | )
(Income) from repurchase of various issuances of debt |  |  | — |  |  |  | — |  |  |  | (118,020 | ) |  |  | (118,020 | )
Other (income) expense |  |  | (41,043 | ) |  |  | (7,674 | ) |  |  | 14,517 |  |  |  | (34,200 | )
Income before taxes |  |  | 175,960 |  |  |  | (6,127 | ) |  |  | (132,276 | ) |  |  | 37,557 |
Provision (benefit) for income taxes |  |  | 95,590 |  |  |  | (107,882 | ) |  |  | 23,126 |  |  |  | 10,835 |
Discontinued operations, net of tax |  |  | 32,077 |  |  |  | 69,872 |  |  |  | (10,053 | ) |  |  | 91,896 |

Intersegment revenues primarily relate to the use of internally procured gas for the Company’s power plants. These intersegment revenues have been included in Total Revenue and Income before taxes in the oil and gas production and marketing reporting segment and eliminated in the corporate and other reporting segment.

| Geographic Area Information

During the year ended December 31, 2004, the Company owned interests in 88 operating power plants in the United States, three operating power plants in Canada and one operating power plant in the United Kingdom. In addition, the Company had oil and gas interests in the United States. Geographic revenue and property, plant and equipment information is based on physical location of the assets at the end of each period.

|  | United States |  |  | Canada |  |  | Europe |  |  | Total |
|  |  |  | (In thousands) |  |  |
2004 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total Revenue |  | $ | 8,704,249 |  |  | $ | 93,071 |  |  | $ | 432,568 |  |  | $ | 9,229,888 |
Property, plant and equipment, net |  |  | 19,041,875 |  |  |  | 498,136 |  |  |  | 1,096,383 |  |  |  | 20,636,394 |
2003 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total Revenue |  | $ | 8,436,176 |  |  | $ | 121,219 |  |  | $ | 313,638 |  |  | $ | 8,871,033 |
Property, plant and equipment, net |  |  | 17,959,466 |  |  |  | 474,280 |  |  |  | 1,044,904 |  |  |  | 19,478,650 |
2002 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total Revenue |  | $ | 7,073,283 |  |  | $ | 70,586 |  |  | $ | 205,884 |  |  | $ | 7,349,753 |

27. | California Power Market

California Refund Proceeding. On August 2, 2000, the California Refund Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric Company under Section 206 of the Federal Power Act alleging, among other things, that the markets operated by the California Independent System Operator (“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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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. The Company believes, based on information that the Company has analyzed to date, that any refund liability that may be attributable to it 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. The Company believes it has appropriately reserved for the refund liability that by its 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, the Company is unable to predict the timing of the completion of these proceedings or the final refund liability. Thus, the impact on the Company’s business is uncertain.
On April 26, 2004, Dynegy Inc. entered into a settlement of the California Refund Proceeding and other proceedings with California governmental entities and the three California investor-owned utilities. The California governmental entities include the Attorney General, the CPUC, the CDWR, and the EOB. Also, on April 27, 2004, The Williams Companies, Inc. (“Williams”) entered into a settlement of the California Refund Proceeding and other proceedings with the three California investor-owned utilities; previously, Williams had entered into a settlement of the same matters with the California governmental entities. The Williams settlement with the California governmental entities was similar to the settlement that Calpine entered into with the California governmental entities on April 22, 2002. Calpine’s settlement resulted in a FERC order issued on March 26, 2004, which partially dismissed Calpine from the California Refund Proceeding to the extent that any refunds are owed for power sold by Calpine to CDWR or any other agency of the State of California. On June 30, 2004, a settlement conference was convened at the FERC to explore settlements among additional parties. On December 7, 2004, FERC approved the settlement of the California Refund Proceeding and other proceedings among Duke Energy Corporation and its affiliates, the three California investor-owned utilities, and the California governmental entities.
FERC Investigation into Western Markets. 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 megawatt 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. The Company believes that it did not violate the CAISO and CalPX tariff prohibitions referred to by FERC in this order; however, the Company is unable to predict at this time the final outcome of this proceeding or its impact on Calpine.
CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our Qualifying Facilities (“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, the Company’s 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. The Company believes that the CalPX Price was the appropriate price for energy payments for its QFs during this period, but there can be no assurance that this will be the outcome of the CPUC proceedings.
City of Lodi Agreement. On February 9, 2001, the Company entered into an agreement with the City of Lodi (the Northern California Power Agency acted as agent on behalf of the City of Lodi) whereby CES would sell 25 MW of ATC fixed price power plus a 1.7 MW day-ahead call option to the City of Lodi for delivery from January 1, 2002, through December 31, 2011. In September 2002 the City of Lodi and Calpine agreed to terminate this agreement resulting in a $41.5 million gain to the Company. The gain is included in Other income in the accompanying consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Geysers Reliability Must Run Section 206 Proceeding. CAISO, EOB, CPUC, PG&E, San Diego Gas & Electric Company, 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 Federal Power Act 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 the Company’s business cannot be determined at the present time.

28. | Subsequent Events

On January 28, 2005, the Company’s indirect subsidiary Metcalf Energy Center, LLC obtained a $100.0 million, non-recourse credit facility for the Metcalf Energy Center in San Jose, CA. Loans extended to Metcalf under the facility will fund the balance of construction activities for the 602-megawatt, natural gas-fired power plant. The project finance facility will mature in July 2008.
On January 31, 2005, the Company received funding on a $260.0 million offering of Redeemable Preferred Shares, due on July 30, 2005. The Company offered the shares 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 the Company’s existing bond indentures.
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, Deer Park Energy Center, Limited Partnership (“Deer Park”), an indirect, wholly-owned subsidiary of Calpine, entered into an agreement to sell power to and buy gas from Merrill Lynch Commodities, Inc. (“MLCI”). The agreement covers 650 MW of Deer Park’s capacity and deliveries under the agreement will begin on April 1, 2005 and continue through December 31, 2010. Under the terms of the agreement, Deer Park will sell power to MLCI at a discount to prevailing market prices at the time the agreement was executed. In exchange for the discounted pricing, Deer Park received a cash payment of approximately $195 million and expects to receive additional cash payments as additional power transactions are executed with discounts to prevailing market prices. The agreements are derivatives under SFAS No. 133 and because of their discounted pricing will result in the recognition of a derivative liability. The upfront payments received by Deer Park from the transaction will be recorded as cash flow from financing activity in accordance with guidance contained in SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.”
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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.

29. | Quarterly Consolidated Financial Data (unaudited)

The Company’s 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, but not limited to, the timing and size of acquisitions, the completion of development projects, the timing and amount of curtailment of operations under the terms of certain power sales agreements, the degree of risk management and trading activity, and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of the Company’s power sales agreements are received during the months of May through October.
The Company’s common stock has been traded on the New York Stock Exchange since September 19, 1996. There were 2,366 common stockholders of record at December 31, 2004. No dividends were paid for the years ended December 31, 2004 and 2003. All share data has been adjusted to reflect the two-for-one stock split effective June 8, 2000, and the two-for-one stock split effective November 14, 2000.

|  | Quarter Ended |
|  | December 31, |  |  | September 30, |  |  | June 30, |  |  | March 31, |
|  | (In thousands, except per share amounts) |
2004 Common stock price per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| High |  | $ | 4.08 |  |  | $ | 4.46 |  |  | $ | 4.98 |  |  | $ | 6.42 |
| Low |  |  | 2.24 |  |  |  | 2.87 |  |  |  | 3.04 |  |  |  | 4.35 |
2004, Restated (for periods through September 30, 2004) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total revenue |  | $ | 2,336,181 |  |  | $ | 2,557,200 |  |  | $ | 2,304,215 |  |  | $ | 2,032,292 |
Oil and gas impairment |  |  | 201,475 |  |  |  | — |  |  |  | 645 |  |  |  | — |
(Income) from repurchase of various issuances of debt |  |  | (76,401 | ) |  |  | (167,154 | ) |  |  | (2,559 | ) |  |  | (835 | )
Gross profit (loss) |  |  | (68,314 | ) |  |  | 254,403 |  |  |  | 56,851 |  |  |  | 112,152 |
Income (loss) from operations |  |  | (189,242 | ) |  |  | 162,419 |  |  |  | (12,586 | ) |  |  | 45,117 |
Income (loss) before discontinued operations |  |  | (290,113 | ) |  |  | 14,587 |  |  |  | (58,069 | ) |  |  | (107,231 | )
Discontinued operations, net of tax |  |  | 6,416 |  |  |  | 126,538 |  |  |  | 29,371 |  |  |  | 36,040 |
Net income (loss) |  | $ | (283,696 | ) |  | $ | 141,125 |  |  | $ | (28,698 | ) |  | $ | (71,192 | )
Basic earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations |  | $ | (0.65 | ) |  | $ | 0.03 |  |  | $ | (0.14 | ) |  | $ | (0.26 | )
| Discontinued operations, net of tax |  |  | 0.01 |  |  |  | 0.29 |  |  |  | 0.07 |  |  |  | 0.09 |
| Net income (loss) |  |  | (0.64 | ) |  |  | 0.32 |  |  |  | (0.07 | ) |  |  | (0.17 | )
Diluted earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities |  | $ | (0.65 | ) |  | $ | 0.03 |  |  | $ | (0.14 | ) |  | $ | (0.26 | )
| Dilutive effect of certain trust preferred securities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
| Income (loss) before discontinued operations |  |  | (0.65 | ) |  |  | 0.03 |  |  |  | (0.14 | ) |  |  | (0.26 | )
| Discontinued operations, net of tax |  |  | 0.01 |  |  |  | 0.29 |  |  |  | 0.07 |  |  |  | 0.09 |
| Net income (loss) |  |  | (0.64 | ) |  |  | 0.32 |  |  |  | (0.07 | ) |  |  | (0.17 | )
2004, As Reported(i) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total revenue |  | $ | 2,336,181 |  |  | $ | 2,557,200 |  |  | $ | 2,314,634 |  |  | $ | 2,042,738 |
Oil and gas impairment |  |  | 201,475 |  |  |  | — |  |  |  | 645 |  |  |  | — |
(Income) from repurchase of various issuances of debt |  |  | (76,401 | ) |  |  | (167,154 | ) |  |  | (2,559 | ) |  |  | (835 | )
Gross profit (loss) |  |  | (68,314 | ) |  |  | 254,403 |  |  |  | 67,690 |  |  |  | 120,544 |
Income (loss) from operations |  |  | (189,242 | ) |  |  | 162,418 |  |  |  | (3,167 | ) |  |  | 51,911 |
Income (loss) before discontinued operations |  |  | (258,807 | ) |  |  | (47,532 | ) |  |  | (28,896 | ) |  |  | (94,049 | )

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

|  | Quarter Ended |
|  | December 31, |  |  | September 30, |  |  | June 30, |  |  | March 31, |
|  | (In thousands, except per share amounts) |
Discontinued operations, net of tax |  |  | 31,507 |  |  |  | 62,551 |  |  |  | 198 |  |  |  | 22,857 |
Net income (loss) |  | $ | (227,301 | ) |  | $ | 15,019 |  |  | $ | (28,698 | ) |  | $ | (71,192 | )
Basic earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations |  | $ | (0.58 | ) |  | $ | (0.11 | ) |  | $ | (0.07 | ) |  | $ | (0.23 | )
| Discontinued operations, net of tax |  |  | 0.07 |  |  |  | 0.14 |  |  |  | — |  |  |  | 0.06 |
| Net income (loss) |  |  | (0.51 | ) |  |  | 0.03 |  |  |  | (0.07 | ) |  |  | (0.17 | )
Diluted earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities |  | $ | (0.58 | ) |  | $ | (0.11 | ) |  | $ | (0.07 | ) |  | $ | (0.23 | )
| Dilutive effect of certain trust preferred securities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
| Income (loss) before discontinued operations |  |  | (0.58 | ) |  |  | (0.11 | ) |  |  | (0.07 | ) |  |  | (0.23 | )
| Discontinued operations, net of tax |  |  | 0.07 |  |  |  | 0.14 |  |  |  | — |  |  |  | 0.06 |
| Net income (loss) |  |  | (0.51 | ) |  |  | 0.03 |  |  |  | (0.07 | ) |  |  | (0.17 | )
2003 Common stock price per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| High |  | $ | 5.25 |  |  | $ | 8.03 |  |  | $ | 7.25 |  |  | $ | 4.42 |
| Low |  |  | 3.28 |  |  |  | 4.76 |  |  |  | 3.33 |  |  |  | 2.51 |
2003, Restated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total revenue |  | $ | 1,909,598 |  |  | $ | 2,656,588 |  |  | $ | 2,152,478 |  |  | $ | 2,152,368 |
Oil and gas impairment |  |  | 2,931 |  |  |  | — |  |  |  | — |  |  |  | — |
(Income) from repurchase of various issuances of debt |  |  | (64,611 | ) |  |  | (207,238 | ) |  |  | (6,763 | ) |  |  | — |
Gross profit |  |  | 117,979 |  |  |  | 338,872 |  |  |  | 162,900 |  |  |  | 144,486 |
Income (loss) from operations |  |  | (19,818 | ) |  |  | 287,096 |  |  |  | 142,760 |  |  |  | 100,360 |
Income (loss) before discontinued operations |  |  | (21,476 | ) |  |  | 176,530 |  |  |  | (14,729 | ) |  |  | (54,215 | )
Discontinued operations, net of tax |  |  | (39,316 | ) |  |  | 61,252 |  |  |  | (8,637 | ) |  |  | 1,670 |
Cumulative effect of a change in accounting principle |  |  | 180,414 |  |  |  | — |  |  |  | — |  |  |  | 529 |
Net income (loss) |  | $ | 119,622 |  |  | $ | 237,782 |  |  | $ | (23,366 | ) |  | $ | (52,016 | )
Basic earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations and cumulative effect of a change in accounting principle |  | $ | (0.05 | ) |  | $ | 0.45 |  |  | $ | (0.04 | ) |  | $ | (0.14 | )
| Discontinued operations, net of tax |  |  | (0.10 | ) |  |  | 0.16 |  |  |  | (0.02 | ) |  |  | — |
| Cumulative effect of a change in accounting principle |  |  | 0.44 |  |  |  | — |  |  |  | — |  |  |  | — |
| Net income (loss) |  |  | 0.29 |  |  |  | 0.61 |  |  |  | (0.06 | ) |  |  | (0.14 | )
Diluted earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities |  | $ | (0.05 | ) |  | $ | 0.45 |  |  | $ | (0.04 | ) |  | $ | (0.14 | )
| Dilutive effect of certain trust preferred securities |  |  | — |  |  |  | (0.09 | ) |  |  | — |  |  |  | — |
| Income (loss) before discontinued operations and cumulative effect of a change in accounting principle |  |  | (0.05 | ) |  |  | 0.36 |  |  |  | (0.04 | ) |  |  | (0.14 | )
| Discontinued operations, net of tax |  |  | (0.10 | ) |  |  | 0.15 |  |  |  | (0.02 | ) |  |  | — |
| Cumulative effect of a change in accounting principle |  |  | 0.44 |  |  |  | — |  |  |  | — |  |  |  | — |
| Net income (loss) |  |  | 0.29 |  |  |  | 0.51 |  |  |  | (0.06 | ) |  |  | (0.14 | )
2003, As Reported(i) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total revenue |  | $ | 1,920,575 |  |  | $ | 2,656,588 |  |  | $ | 2,165,308 |  |  | $ | 2,165,933 |
Oil and gas impairment(ii) |  |  | 2,931 |  |  |  | — |  |  |  | — |  |  |  | — |
(Income) from repurchase of various issuances of debt |  |  | (64,611 | ) |  |  | (207,238 | ) |  |  | (6,763 | ) |  |  | — |

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

|  | Quarter Ended |
|  | December 31, |  |  | September 30, |  |  | June 30, |  |  | March 31, |
|  | (In thousands, except per share amounts) |
Gross profit |  |  | 126,691 |  |  |  | 338,872 |  |  |  | 175,593 |  |  |  | 165,137 |
Income (loss) from operations |  |  | (20,032 | ) |  |  | 287,096 |  |  |  | 153,471 |  |  |  | 119,040 |
Income (loss) before discontinued operations |  |  | (59,827 | ) |  |  | 237,701 |  |  |  | (16,375 | ) |  |  | (51,538 | )
Discontinued operations, net of tax |  |  | (967 | ) |  |  | 81 |  |  |  | (6,991 | ) |  |  | (1,007 | )
Cumulative effect of a change in accounting principle |  |  | 180,414 |  |  |  | — |  |  |  | — |  |  |  | 529 |
Net income (loss) |  | $ | 119,622 |  |  | $ | 237,782 |  |  | $ | (23,366 | ) |  | $ | (52,016 | )
Basic earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations and cumulative effect of a change in accounting principle |  | $ | (0.15 | ) |  | $ | 0.61 |  |  | $ | (0.04 | ) |  | $ | (0.14 | )
| Discontinued operations, net of tax |  |  | — |  |  |  | — |  |  |  | (0.02 | ) |  |  | — |
| Cumulative effect of a change in accounting principle |  |  | 0.44 |  |  |  | — |  |  |  | — |  |  |  | — |
| Net income (loss) |  |  | 0.29 |  |  |  | 0.61 |  |  |  | (0.06 | ) |  |  | (0.14 | )
Diluted earnings per common share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities |  | $ | (0.15 | ) |  | $ | 0.60 |  |  | $ | (0.04 | ) |  | $ | (0.14 | )
| Dilutive effect of certain trust preferred securities |  |  | — |  |  |  | (0.09 | ) |  |  | — |  |  |  | — |
| Income (loss) before discontinued operations and cumulative effect of a change in accounting principle |  |  | (0.15 | ) |  |  | 0.51 |  |  |  | (0.04 | ) |  |  | (0.14 | )
| Discontinued operations, net of tax |  |  | — |  |  |  | — |  |  |  | (0.02 | ) |  |  | — |
| Cumulative effect of a change in accounting principle |  |  | 0.44 |  |  |  | — |  |  |  | — |  |  |  | — |
| Net income (loss) |  |  | 0.29 |  |  |  | 0.51 |  |  |  | (0.06 | ) |  |  | (0.14 | )

(i) | As reported in 2004 Form 10-Q filings for quarters ended March 31, 2004, June 30, 2004 and September 30, 2004. The consolidated financial statements for the three and nine months ended September 30, 2004 and as of September 30, 2004 were restated to correct the tax provision.
(ii) | Oil and gas impairment for quarter ended December 31, 2003, was previously a component of Depreciation Expense.

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SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

|  |  |  |  |  | Charged to |  |  |  |  |  |  |
|  |  |  |  |  | Accumulated |  |  |  |  |  |  |
|  | Balance at |  |  |  |  | Other |  |  |  |  |  |  |
|  | Beginning |  |  | Charged to |  |  | Comprehensive |  |  |  |  |  |  | Balance at |
Description |  | of Year |  |  | Expense |  |  | Loss |  |  | Reductions(1) |  |  | Other(2) |  |  | End of Year |
|  | (In thousands) |
Year ended December 31, 2004 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Allowance for doubtful accounts |  | $ | 7,614 |  |  | $ | 8,412 |  |  | $ | — |  |  | $ | (7,828 | ) |  | $ | 481 |  |  | $ | 8,679 |
| Reserve for notes receivable |  |  | 273 |  |  |  | 2,637 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,910 |
| Gross reserve for California Refund Liability |  |  | 12,905 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 12,905 |
| Reserve for impairment of investment in Androscoggin Energy Center |  |  | — |  |  | $ | 5,000 |  |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 5,000 |
| Reserve for derivative assets |  |  | 7,454 |  |  |  | 2,825 |  |  |  | 173 |  |  |  | (7,184 | ) |  |  | — |  |  |  | 3,268 |
| Repayment reserve for third-party default on emission reduction credits’ settlement |  |  | 3,000 |  |  |  | 2,850 |  |  |  | — |  |  |  | (5,850 | ) |  |  | — |  |  |  | — |
| Deferred tax asset valuation allowance |  |  | 19,335 |  |  |  | 43,487 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 62,822 |
Year ended December 31, 2003 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Allowance for doubtful accounts |  | $ | 5,955 |  |  | $ | 3,278 |  |  | $ | — |  |  | $ | (2,099 | ) |  | $ | 480 |  |  | $ | 7,614 |
| Reserve for notes receivable |  |  | — |  |  |  | 273 |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  | 273 |
| Gross reserve for California Refund Liability |  |  | 10,700 |  |  |  | 2,205 |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  | 12,905 |
| Reserve for derivative assets |  |  | 16,452 |  |  |  | 19,459 |  |  |  | 3,640 |  |  |  | (32,097 | ) |  |  |  |  |  |  | 7,454 |
| Gain reserved on certain Enron transactions |  |  | 17,862 |  |  |  | — |  |  |  | — |  |  |  | (17,862 | ) |  |  |  |  |  |  | — |
| Repayment reserve for third-party default on emission reduction credits’ settlement |  |  | — |  |  |  | 3,000 |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  | 3,000 |
| Deferred tax asset valuation allowance |  |  | 26,665 |  |  |  | — |  |  |  | — |  |  |  | (7,330 | ) |  |  | — |  |  |  | 19,335 |
Year Ended December 31, 2002 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Allowance for doubtful accounts |  | $ | 15,422 |  |  | $ | 1,636 |  |  | $ | — |  |  | $ | (11,246 | ) |  | $ | 143 |  |  | $ | 5,955 |
| Gross reserve for California Refund Liability |  |  | — |  |  |  | 10,700 |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  | 10,700 |
| Reserve for derivative assets |  |  | 1,583 |  |  |  | 17,253 |  |  |  | 8,444 |  |  |  | (10,828 | ) |  |  |  |  |  |  | 16,452 |
| Gain reserved on certain Enron transactions |  |  | 17,862 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  |  |  |  |  | 17,862 |
| Reserve for third-party default on emission reduction credits |  |  | 17,677 |  |  |  | — |  |  |  | — |  |  |  | (17,677 | ) |  |  |  |  |  |  | — |
| Deferred tax asset valuation allowance |  |  | 26,665 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 26,665 |

(1) | Represents write-offs of accounts considered to be uncollectible and recoveries of amounts previously written off or reserved.
(2) | Primarily relates to foreign currency translation adjustments.

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SUPPLEMENTAL OIL AND GAS DISCLOSURES
(Unaudited)
Oil and Gas Producing Activities
The following disclosures for Calpine Corporation (the “Company”) are made in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, “Disclosures About Oil and Gas Producing Activities (An Amendment of FASB Statements 19, 25, 33 and 39)” (“SFAS No. 69”). Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.
Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Estimates of proved developed and proved undeveloped reserves as of December 31, 2004, 2003 and 2002, were based on estimates made by Netherland, Sewell & Associates Inc. (“NSA”) for reserves in the United States and by Gilbert Laustsen Jung Associates Ltd. (“GLJ”) for 2003 and 2002 reserves in Canada, both independent petroleum reservoir engineers.
Our independent engineers are engaged by and provide their reports to our senior management team at Calpine Fuels Company (“CFC”), our oil and gas subsidiary, and these reservoir engineers are independent and are engaged to prepare the reserves reports independently rather than to audit reports prepared by CFC management. CFC management represents to the independent engineers that we have provided all relevant operating data and documents, and CFC management reviews the reports to ensure completeness and accuracy. The President of our CFC subsidiary, in consultation with CFC’s Senior Vice President, Exploration and Development, makes the final decision on booked proved reserves by incorporating the proved reserves from the independent engineers’ reports.
Our relevant management controls over proved reserve attribution, estimation and evaluation include:

| • | controls over and processes for the collection and processing of all pertinent operating data and documents needed by our independent reservoir engineers to estimate our proved reserves;
| • | engagement of well qualified and independent reservoir engineers for review of our operating data and documents and preparation of reserve reports annually in accordance with all SEC reserve estimation guidelines; and
| • | review by our senior reservoir engineer and his staff of the independent reservoir engineers’ reserves reports for completion and accuracy.

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Prior to 2003, all CFC management and staff were under the Company’s existing Management Incentive Plan (“MIP”), which did not consider proved reserves in determining bonus amounts. In 2003, a Fuel’s Incentive Plan (“FIP”) was put in place whereby 70% of the CFC bonus compensation was based on oil and gas financial and operational criteria while 30% continued under the existing MIP plan. Of the 70% oil and gas bonus portion, 25% was related to reserve additions, 25% to annual production, 25% to earnings before interest, taxes, depreciation, depletion and amortization, 15% to finding cost, 5% to lifting cost and 5% to general and administrative cost budget targets. Proved reserves are only utilized in the calculation of reserve additions and related finding cost and include proved reserve revisions of prior estimates. The President of CFC is not eligible to participate in the FIP. We believe that our FIP is consistent with industry standards and is structured and monitored in a manner to assure compliance with all existing SEC and industry proved reserve guidelines.
Market prices as of each year-end were used for future sales of natural gas, crude oil and natural gas liquids. Future operating costs, production and ad valorem taxes and capital costs were based on current costs as of each year-end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risk.
In accordance with SFAS No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”), United States and Canadian natural gas reserves and petroleum asset divestments were accounted for as discontinued operations in preparing SFAS No. 69 data. Discontinued operations is discussed in detail under Note 10 of the Notes to Consolidated Financial Statements.

| Capitalized Costs Relating to Oil and Gas Producing Activities

The following table sets forth the capitalized costs relating to the Company’s natural gas and crude oil producing activities (excluding pipeline and related assets) at December 31, 2004, 2003 and 2002, (in thousands):

|  | Continuing Operations |
|  | 2004 |  |  | 2003 |  |  | 2002 |  |  | 2001 |
Proved properties |  | $ | 1,095,022 |  |  | $ | 1,084,499 |  |  | $ | 909,494 |  |  | $ | 853,857 |
Unproved properties |  |  | 10,538 |  |  |  | 11,283 |  |  |  | 268,983 |  |  |  | 260,454 |
| Total |  |  | 1,105,560 |  |  |  | 1,095,782 |  |  |  | 1,178,477 |  |  |  | 1,114,311 |
Less: Accumulated depreciation, depletion and amortization |  |  | (500,722 | ) |  |  | (237,374 | ) |  |  | (220,376 | ) |  |  | (145,467 | )
| Net capitalized costs |  | $ | 604,838 |  |  | $ | 858,408 |  |  | $ | 958,101 |  |  | $ | 968,844 |
| Company’s share of equity method investees’ net capitalized costs |  | $ | 1,160 |  |  | $ | 1,255 |  |  | $ | — |  |  | $ | — |

|  | Discontinued Operations |
|  | 2004 |  | 2003 |  |  | 2002 |  |  | 2001 |
Proved properties |  | $ | — |  |  | $ | 995,372 |  |  | $ | 759,132 |  |  | $ | 1,059,168 |
Unproved properties |  |  | — |  |  |  | 51,860 |  |  |  | 36,656 |  |  |  | 62,281 |
| Total |  |  | — |  |  |  | 1,047,232 |  |  |  | 795,788 |  |  |  | 1,121,449 |
Less: Accumulated depreciation, depletion and amortization |  |  | — |  |  |  | (466,207 | ) |  |  | (305,324 | ) |  |  | (374,280 | )
| Net capitalized costs |  | $ | — |  |  | $ | 581,025 |  |  | $ | 490,464 |  |  | $ | 747,169 |
| Company’s share of equity method investees’ net capitalized costs |  | $ | — |  |  | $ | 53,228 |  |  | $ | — |  |  | $ | — |

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Pursuant to SFAS No. 143 “Accounting for Asset Retirement Obligations”, net capitalized cost includes related asset retirement cost of $6,560 and $13,819 as of December 31, 2004, and December 31, 2003, respectively.

| Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include exploration expenses and additions to exploration wells, including those in progress. Development costs include additions to production facilities and equipment, as well as additions to development wells, including those in progress. The following table sets forth costs incurred related to the Company’s oil and gas activities for the years ended December 31, 2004, 2003, and 2002, (in thousands):

|  | United |  |  |  |  | Continuing |  |  | Discontinued |
|  | States |  |  | Canada |  |  | Operations |  |  | Operations |
December 31, 2004: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Acquisition costs of properties |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Proved |  | $ | 1,425 |  |  | $ | — |  |  | $ | 1,425 |  |  | $ | 3,571 |
|  | Unproved |  |  | 3,060 |  |  |  | — |  |  |  | 3,060 |  |  |  | 105 |
|  |  | Subtotal |  |  | 4,485 |  |  |  | — |  |  |  | 4,485 |  |  |  | 3,676 |
| Exploration costs |  |  | 22,471 |  |  |  | 50 |  |  |  | 22,521 |  |  |  | 1,313 |
| Development costs |  |  | 42,038 |  |  |  | 5,554 |  |  |  | 47,592 |  |  |  | 37,243 |
|  |  | Total |  | $ | 68,994 |  |  | $ | 5,604 |  |  | $ | 74,598 |  |  | $ | 42,232 |
|  |  | Company’s share of equity method investees’ costs of property acquisition, exploration and development |  | $ | 56 |  |  | $ | — |  |  | $ | 56 |  |  | $ | 2,020 |
December 31, 2003: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Acquisition costs of properties |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Proved |  | $ | 8,178 |  |  | $ | — |  |  | $ | 8,178 |  |  | $ | 13,087 |
|  | Unproved |  |  | 13,597 |  |  |  | — |  |  |  | 13,597 |  |  |  | 3,324 |
|  |  | Subtotal |  |  | 21,775 |  |  |  | — |  |  |  | 21,775 |  |  |  | 16,411 |
| Exploration costs |  |  | 33,364 |  |  |  | 603 |  |  |  | 33,967 |  |  |  | 6,235 |
| Development costs |  |  | 41,911 |  |  |  | 13,199 |  |  |  | 55,110 |  |  |  | 55,006 |
|  |  | Total |  | $ | 97,050 |  |  | $ | 13,802 |  |  | $ | 110,852 |  |  | $ | 77,652 |
|  |  | Company’s share of equity method investees’ costs of property acquisition, exploration and development |  | $ | 1,268 |  |  | $ | — |  |  | $ | 1,268 |  |  | $ | 53,039 |
December 31, 2002: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Acquisition costs of properties |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Proved |  | $ | 3,415 |  |  | $ | — |  |  | $ | 3,415 |  |  | $ | 8,998 |
|  | Unproved |  |  | 14,769 |  |  |  | — |  |  |  | 14,769 |  |  |  | (4,615 | )
|  |  | Subtotal |  |  | 18,184 |  |  |  | — |  |  |  | 18,184 |  |  |  | 4,383 |
| Exploration costs |  |  | 10,958 |  |  |  | 1,818 |  |  |  | 12,776 |  |  |  | 5,741 |
| Development costs |  |  | 44,309 |  |  |  | 11,084 |  |  |  | 55,393 |  |  |  | 60,802 |
|  |  | Total |  | $ | 73,451 |  |  | $ | 12,902 |  |  | $ | 86,353 |  |  | $ | 70,926 |

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| Results of Operations for Oil and Gas Producing Activities

The following table sets forth results of operations for oil and gas producing activities (excluding pipeline and related operations) for the years ended December 31, 2004, 2003, and 2002, (in thousands):

|  | United States |  |  | Canada |  |  | Total |
December 31, 2004: |  |  |  |  |  |  |  |  |  |  |  |
| Oil and gas production revenues |  |  |  |  |  |  |  |  |  |  |  |
|  | Third-party |  | $ | 57,644 |  |  | $ | 5,461 |  |  | $ | 63,105 |
|  | Intercompany |  |  | 190,143 |  |  |  | 3,458 |  |  |  | 193,601 |
|  |  | Total revenues |  |  | 247,787 |  |  |  | 8,919 |  |  |  | 256,706 |
| Exploration expenses, including dry hole |  |  | 8,175 |  |  |  | — |  |  |  | 8,175 |
| Production costs |  |  | 43,016 |  |  |  | 3,521 |  |  |  | 46,537 |
| Depreciation, depletion and amortization |  |  | 81,590 |  |  |  | 776 |  |  |  | 82,366 |
| Oil and gas impairment |  |  | 202,120 |  |  |  | — |  |  |  | 202,120 |
| Income (loss) before income taxes |  |  | (87,114 | ) |  |  | 4,622 |  |  |  | (82,492 | )
| Income tax provision (benefit) |  |  | (33,289 | ) |  |  | 1,949 |  |  |  | (31,340 | )
|  |  | Results of continuing operations |  | $ | (53,825 | ) |  | $ | 2,673 |  |  | $ | (51,152 | )
|  |  | Results of discontinued operations |  | $ | 7,162 |  |  | $ | 14,103 |  |  | $ | 21,265 |
| Company’s share of equity method investees’ results of operations for producing activities |  | $ | 324 |  |  | $ | — |  |  | $ | 324 |
December 31, 2003: |  |  |  |  |  |  |  |  |  |  |  |
| Oil and gas production revenues |  |  |  |  |  |  |  |  |  |  |  |
|  | Third-party |  | $ | 56,162 |  |  | $ | 10,030 |  |  | $ | 66,192 |
|  | Intercompany |  |  | 223,532 |  |  |  | 47,379 |  |  |  | 270,911 |
|  |  | Total revenues |  |  | 279,694 |  |  |  | 57,409 |  |  |  | 337,103 |
| Exploration expenses, including dry hole |  |  | 16,753 |  |  |  | 2,443 |  |  |  | 19,196 |
| Production costs |  |  | 40,956 |  |  |  | 12,384 |  |  |  | 53,340 |
| Depreciation, depletion and amortization |  |  | 72,766 |  |  |  | 16,823 |  |  |  | 89,589 |
| Oil and gas impairment |  |  | 2,931 |  |  |  | — |  |  |  | 2,931 |
| Income before income taxes |  |  | 146,288 |  |  |  | 25,759 |  |  |  | 172,047 |
| Income tax provision |  |  | 55,620 |  |  |  | 16,450 |  |  |  | 72,070 |
|  |  | Results of continuing operations |  | $ | 90,668 |  |  | $ | 9,309 |  |  | $ | 99,977 |
|  |  | Results of discontinued operations |  | $ | 6,903 |  |  | $ | 21,764 |  |  | $ | 28,667 |
| Company’s share of equity method investees’ results of operations for producing activities |  | $ | 86 |  |  | $ | 101 |  |  | $ | 187 |
December 31, 2002: |  |  |  |  |  |  |  |  |  |  |  |
| Oil and gas production revenues |  |  |  |  |  |  |  |  |  |  |  |
|  | Third-party |  | $ | 37,716 |  |  | $ | 35,541 |  |  | $ | 73,257 |
|  | Intercompany |  |  | 126,833 |  |  |  | 5,262 |  |  |  | 132,095 |
|  |  | Total revenues |  |  | 164,549 |  |  |  | 40,803 |  |  |  | 205,352 |
| Exploration expenses, including dry hole |  |  | 10,204 |  |  |  | 2,797 |  |  |  | 13,001 |
| Production costs |  |  | 33,249 |  |  |  | 15,214 |  |  |  | 48,463 |
| Depreciation, depletion and amortization |  |  | 67,060 |  |  |  | 23,631 |  |  |  | 90,691 |
| Oil and gas impairment |  |  | 3,399 |  |  |  | — |  |  |  | 3,399 |
| Income (loss) before income taxes |  |  | 50,637 |  |  |  | (839 | ) |  |  | 49,798 |
| Income tax provision |  |  | 19,749 |  |  |  | 5,708 |  |  |  | 25,457 |
|  |  | Results of continuing operations |  | $ | 30,888 |  |  | $ | (6,547 | ) |  | $ | 24,341 |
|  |  | Results of discontinued operations |  | $ | (330 | ) |  | $ | 28,281 |  |  | $ | 27,951 |

The results of operations for oil and gas producing activities exclude interest charges and general corporate expenses.

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| Net Proved and Proved Developed Reserve Summary

The following table sets forth the Company’s net proved and proved developed reserves at December 31 for each of the three years in the period ended December 31, 2004, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the independent petroleum consultants.
During 2004, the Company revised downward its estimate of continuing proved reserves by a total of approximately 58 Bcfe or 12%. Approximately 69% of the total revision was attributable to the downward revision of the Company’s estimate of proved reserves in the Company’s South Texas fields. The downward revisions of the Company’s estimates were due to information received from production results and drilling activity that occurred during 2004. As a result of the decreases in proved undeveloped reserves, a non-cash impairment charge of approximately $202.1 million was recorded for the year ended December 31, 2004, to the “Oil and gas impairment” line of the Consolidated Statement of Operations. For the years ended December 31, 2003 and 2002, the impairment charge recorded to the same line item was $2.9 million and $3.4 million, respectively.

|  | United |  |  |  |  | Continuing |  |  | Discontinued |
|  | States |  |  | Canada |  |  | Operations |  |  | Operations |
Natural gas (Bcf)(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Net proved reserves at December 31, 2001 |  |  | 509 |  |  |  | 72 |  |  |  | 581 |  |  |  | 454 |
|  | Revisions of previous estimates |  |  | (24 | ) |  |  | 20 |  |  |  | (4 | ) |  |  | (20 | )
|  | Purchases in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Extensions, discoveries and other additions |  |  | 41 |  |  |  | 1 |  |  |  | 42 |  |  |  | 44 |
|  | Sales in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (122 | )
|  | Production |  |  | (47 | ) |  |  | (12 | ) |  |  | (59 | ) |  |  | (40 | )
| Net proved reserves at December 31, 2002 |  |  | 479 |  |  |  | 81 |  |  |  | 560 |  |  |  | 316 |
|  | Revisions of previous estimates |  |  | (21 | ) |  |  | (1 | ) |  |  | (22 | ) |  |  | (25 | )
|  | Purchases in place |  |  | 1 |  |  |  | — |  |  |  | 1 |  |  |  | 9 |
|  | Extensions, discoveries and other additions |  |  | 51 |  |  |  | — |  |  |  | 51 |  |  |  | 21 |
|  | Sales in place |  |  | (5 | ) |  |  | (60 | ) |  |  | (65 | ) |  |  | (4 | )
|  | Production |  |  | (50 | ) |  |  | (8 | ) |  |  | (58 | ) |  |  | (28 | )
| Net proved reserves at December 31, 2003 |  |  | 455 |  |  |  | 12 |  |  |  | 467 |  |  |  | 289 |
|  | Revisions of previous estimates |  |  | (60 | ) |  |  | — |  |  |  | (60 | ) |  |  | 17 |
|  | Purchases in place |  |  | 1 |  |  |  | — |  |  |  | 1 |  |  |  | 3 |
|  | Extensions, discoveries and other additions |  |  | 17 |  |  |  | — |  |  |  | 17 |  |  |  | 5 |
|  | Sales in place |  |  | (2 | ) |  |  | (12 | ) |  |  | (14 | ) |  |  | (296 | )
|  | Production |  |  | (37 | ) |  |  | — |  |  |  | (37 | ) |  |  | (18 | )
| Net proved reserves at December 31, 2004 |  |  | 374 |  |  |  | — |  |  |  | 374 |  |  |  | — |
Natural gas liquids and crude oil (MBbl)(2)(3): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Net proved reserves at December 31, 2001 |  |  | 3,640 |  |  |  | 3,986 |  |  |  | 7,626 |  |  |  | 35,564 |
|  | Revisions of previous estimates |  |  | 269 |  |  |  | 1,192 |  |  |  | 1,461 |  |  |  | (414 | )
|  | Purchases in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Extensions, discoveries and other additions |  |  | 165 |  |  |  | 49 |  |  |  | 214 |  |  |  | 796 |
|  | Sales in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (23,967 | )
|  | Production |  |  | (543 | ) |  |  | (655 | ) |  |  | (1,198 | ) |  |  | (3,080 | )
| Net proved reserves at December 31, 2002 |  |  | 3,531 |  |  |  | 4,572 |  |  |  | 8,103 |  |  |  | 8,899 |
|  | Revisions of previous estimates |  |  | (338 | ) |  |  | (254 | ) |  |  | (592 | ) |  |  | (647 | )
|  | Purchases in place |  |  | 18 |  |  |  | — |  |  |  | 18 |  |  |  | 12 |
|  | Extensions, discoveries and other additions |  |  | 133 |  |  |  | — |  |  |  | 133 |  |  |  | 822 |
|  | Sales in place |  |  | (8 | ) |  |  | (3,775 | ) |  |  | (3,783 | ) |  |  | (118 | )
|  | Production |  |  | (434 | ) |  |  | (542 | ) |  |  | (976 | ) |  |  | (960 | )
| Net proved reserves at December 31, 2003 |  |  | 2,902 |  |  |  | 1 |  |  |  | 2,903 |  |  |  | 8,008 |
|  | Revisions of previous estimates |  |  | 260 |  |  |  | — |  |  |  | 260 |  |  |  | (929 | )
|  | Purchases in place |  |  | 3 |  |  |  | — |  |  |  | 3 |  |  |  | — |
|  | Extensions, discoveries and other additions |  |  | 48 |  |  |  | — |  |  |  | 48 |  |  |  | 422 |
|  | Sales in place |  |  | (2 | ) |  |  | (1 | ) |  |  | (3 | ) |  |  | (6,862 | )
|  | Production |  |  | (600 | ) |  |  | — |  |  |  | (600 | ) |  |  | (639 | )
| Net proved reserves at December 31, 2004 |  |  | 2,611 |  |  |  | — |  |  |  | 2,611 |  |  |  | — |

(1) | Billion cubic feet or billion cubic feet equivalent, as applicable.

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|  | United |  |  |  |  | Continuing |  |  | Discontinued |
|  | States |  |  | Canada |  |  | Operations |  |  | Operations |
(Bcfe)(1) equivalents(4): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Net proved reserves at December 31, 2001 |  |  | 530 |  |  |  | 96 |  |  |  | 626 |  |  |  | 668 |
|  | Revisions of previous estimates |  |  | (23 | ) |  |  | 23 |  |  |  | — |  |  |  | (17 | )
|  | Purchases in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
|  | Extensions, discoveries and other additions |  |  | 42 |  |  |  | 2 |  |  |  | 44 |  |  |  | 48 |
|  | Sales in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (266 | )
|  | Production |  |  | (50 | ) |  |  | (12 | ) |  |  | (62 | ) |  |  | (63 | )
| Net proved reserves at December 31, 2002 |  |  | 499 |  |  |  | 109 |  |  |  | 608 |  |  |  | 370 |
|  | Revisions of previous estimates |  |  | (23 | ) |  |  | (1 | ) |  |  | (24 | ) |  |  | (30 | )
|  | Purchases in place |  |  | 1 |  |  |  | — |  |  |  | 1 |  |  |  | 9 |
|  | Extensions, discoveries and other additions |  |  | 52 |  |  |  | — |  |  |  | 52 |  |  |  | 26 |
|  | Sales in place |  |  | (5 | ) |  |  | (83 | ) |  |  | (88 | ) |  |  | (5 | )
|  | Production |  |  | (52 | ) |  |  | (11 | ) |  |  | (63 | ) |  |  | (35 | )
| Net proved reserves at December 31, 2003 |  |  | 472 |  |  |  | 14 |  |  |  | 486 |  |  |  | 335 |
|  | Revisions of previous estimates |  |  | (58 | ) |  |  | — |  |  |  | (58 | ) |  |  | 12 |
|  | Purchases in place |  |  | 1 |  |  |  | — |  |  |  | 1 |  |  |  | 3 |
|  | Extensions, discoveries and other additions |  |  | 17 |  |  |  | — |  |  |  | 17 |  |  |  | 7 |
|  | Sales in place |  |  | (2 | ) |  |  | (14 | ) |  |  | (16 | ) |  |  | (335 | )
|  | Production |  |  | (41 | ) |  |  | — |  |  |  | (41 | ) |  |  | (22 | )
| Net proved reserves at December 31, 2004 |  |  | 389 |  |  |  | — |  |  |  | 389 |  |  |  | — |
|  | Company’s proportional interest in reserves of investees accounted for by the equity method — December 31, 2004 |  |  | 1 |  |  |  | — |  |  |  | 1 |  |  |  | — |
Net proved developed reserves: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Natural gas (Bcf)(1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | December 31, 2002 |  |  | 318 |  |  |  | 75 |  |  |  | 393 |  |  |  | 247 |
|  | December 31, 2003 |  |  | 306 |  |  |  | 12 |  |  |  | 318 |  |  |  | 227 |
|  | December 31, 2004 |  |  | 256 |  |  |  | — |  |  |  | 256 |  |  |  | — |
| Natural gas liquids and crude oil (MBbl)(2)(3) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | December 31, 2002 |  |  | 2,030 |  |  |  | 4,271 |  |  |  | 6,301 |  |  |  | 7,831 |
|  | December 31, 2003 |  |  | 1,508 |  |  |  | 219 |  |  |  | 1,727 |  |  |  | 6,963 |
|  | December 31, 2004 |  |  | 1,402 |  |  |  | — |  |  |  | 1,402 |  |  |  | — |
| Bcf(1) equivalents(4) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | December 31, 2002 |  |  | 330 |  |  |  | 100 |  |  |  | 430 |  |  |  | 295 |
|  | December 31, 2003 |  |  | 315 |  |  |  | 13 |  |  |  | 328 |  |  |  | 268 |
|  | December 31, 2004 |  |  | 264 |  |  |  | — |  |  |  | 264 |  |  |  | — |

(1) | Billion cubic feet or billion cubic feet equivalent, as applicable.
(2) | Thousand barrels.
(3) | Includes crude oil, condensate and natural gas liquids.
(4) | Natural gas liquids and crude oil volumes have been converted to equivalent gas volumes using a conversion factor of six cubic feet of gas to one barrel of natural gas liquids and crude oil.

| Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on natural gas and crude oil reserve and production volumes estimated by the independent petroleum reservoir engineers. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and gas assets.
The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas and crude oil reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense, for both the United States and Canada, has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved

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reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s natural gas and crude oil reserves for the years ended December 31, 2004, 2003, and 2002, (in millions):

|  | United |  |  |  |  | Continuing |  |  | Discontinued
|  | States |  |  | Canada |  | Operations |  |  | Operations
December 31, 2004: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Future cash inflows |  | $ | 2,427 |  |  | $ | — |  |  | $ | 2,427 |  |  | $ | — |
| Future production costs |  |  | (568 | ) |  |  | — |  |  |  | (568 | ) |  |  | — |
| Future development costs |  |  | (190 | ) |  |  | — |  |  |  | (190 | ) |  |  | — |
| Future net cash flows before income taxes |  |  | 1,669 |  |  |  | — |  |  |  | 1,669 |  |  |  | — |
| Future income taxes |  |  | (474 | ) |  |  | — |  |  |  | (474 | ) |  |  | — |
| Future net cash flows |  |  | 1,195 |  |  |  | — |  |  |  | 1,195 |  |  |  | — |
| Discount to present value at 10% annual rate |  |  | (542 | ) |  |  | — |  |  |  | (542 | ) |  |  | — |
| Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves |  | $ | 653 |  |  | $ | — |  |  | $ | 653 |  |  | $ | — |
| Company’s share of equity method investees’ standardized measure of discounted future net cash flows |  | $ | 2 |  |  | $ | — |  |  | $ | 2 |  |  | $ | — |

Pursuant to SFAS No. 143, future development costs in 2004 includes future cash outflows related to the settlement of asset retirement obligations within the United States of $11 million.

|  | United |  |  |  |  | Continuing |  |  | Discontinued |
|  | States |  |  | Canada |  |  | Operations |  |  | Operations |
December 31, 2003: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Future cash inflows |  | $ | 2,752 |  |  | $ | 62 |  |  | $ | 2,814 |  |  | $ | 1,784 |
| Future production costs |  |  | (563 | ) |  |  | (14 | ) |  |  | (577 | ) |  |  | (573 | )
| Future development costs |  |  | (200 | ) |  |  | (10 | ) |  |  | (210 | ) |  |  | (118 | )
| Future net cash flows before income taxes |  |  | 1,989 |  |  |  | 38 |  |  |  | 2,027 |  |  |  | 1,093 |
| Future income taxes |  |  | (553 | ) |  |  | (8 | ) |  |  | (561 | ) |  |  | (240 | )
| Future net cash flows |  |  | 1,436 |  |  |  | 30 |  |  |  | 1,466 |  |  |  | 853 |
| Discount to present value at 10% annual rate |  |  | (661 | ) |  |  | (7 | ) |  |  | (668 | ) |  |  | (310 | )
| Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves |  | $ | 775 |  |  | $ | 23 |  |  | $ | 798 |  |  | $ | 543 |
| Company’s share of equity method investees’ standardized measure of discounted future net cash flows |  | $ | 2 |  |  | $ | — |  |  | $ | 2 |  |  | $ | 18 |

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##### Table of Contents

Pursuant to SFAS No. 143, future development costs in 2003 includes future cash outflows related to the settlement of asset retirement obligations within the United States of $45 million and within Canada of $61 million.

December 31, 2002: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Future cash inflows |  | $ | 2,391 |  |  | $ | 439 |  |  | $ | 2,830 |  |  | $ | 1,537 |
| Future production costs |  |  | (538 | ) |  |  | (95 | ) |  |  | (633 | ) |  |  | (434 | )
| Future development costs |  |  | (156 | ) |  |  | (11 | ) |  |  | (167 | ) |  |  | (53 | )
| Future net cash flows before income taxes |  |  | 1,697 |  |  |  | 333 |  |  |  | 2,030 |  |  |  | 1,050 |
| Future income taxes |  |  | (480 | ) |  |  | (110 | ) |  |  | (590 | ) |  |  | (337 | )
| Future net cash flows |  |  | 1,217 |  |  |  | 223 |  |  |  | 1,440 |  |  |  | 713 |
| Discount to present value at 10% annual rate |  |  | (537 | ) |  |  | (77 | ) |  |  | (614 | ) |  |  | (280 | )
| Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves |  | $ | 680 |  |  | $ | 146 |  |  | $ | 826 |  |  | $ | 433 |

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##### Table of Contents

| Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, 2004, 2003, and 2002 (in millions):

|  | United |  |  |  |  | Continuing |  |  | Discontinued |
|  | States |  |  | Canada |  |  | Operations |  |  | Operations |
Balance, December 31, 2001 |  | $ | 402 |  |  | $ | 63 |  |  | $ | 465 |  |  | $ | 514 |
| Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs |  |  | (131 | ) |  |  | (26 | ) |  |  | (157 | ) |  |  | (126 | )
| Net changes in prices and production costs |  |  | 491 |  |  |  | 63 |  |  |  | 554 |  |  |  | 615 |
| Extensions, discoveries, additions and improved recovery, net of related costs |  |  | 96 |  |  |  | — |  |  |  | 96 |  |  |  | 68 |
| Development costs incurred |  |  | 36 |  |  |  | — |  |  |  | 36 |  |  |  | (11 | )
| Revisions of previous quantity estimates and development costs |  |  | (81 | ) |  |  | 15 |  |  |  | (66 | ) |  |  | (10 | )
| Accretion of discount |  |  | 40 |  |  |  | 3 |  |  |  | 43 |  |  |  | 7 |
| Net change in income taxes |  |  | (173 | ) |  |  | (23 | ) |  |  | (196 | ) |  |  | (50 | )
| Purchases of reserves in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2 |
| Sales of reserves in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (521 | )
| Changes in timing and other |  |  | — |  |  |  | 51 |  |  |  | 51 |  |  |  | (55 | )
Balance, December 31, 2002 |  | $ | 680 |  |  | $ | 146 |  |  | $ | 826 |  |  | $ | 433 |
| Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs |  |  | (239 | ) |  |  | (45 | ) |  |  | (284 | ) |  |  | (119 | )
| Net changes in prices and production costs |  |  | 248 |  |  |  | (27 | ) |  |  | 221 |  |  |  | 17 |
| Extensions, discoveries, additions and improved recovery, net of related costs |  |  | 117 |  |  |  | — |  |  |  | 117 |  |  |  | 60 |
| Development costs incurred |  |  | 48 |  |  |  | — |  |  |  | 48 |  |  |  | 41 |
| Revisions of previous quantity estimates and development costs |  |  | (80 | ) |  |  | (11 | ) |  |  | (91 | ) |  |  | (69 | )
| Accretion of discount |  |  | 68 |  |  |  | 2 |  |  |  | 70 |  |  |  | 44 |
| Net change in income taxes |  |  | (28 | ) |  |  | 74 |  |  |  | 46 |  |  |  | 95 |
| Purchases of reserves in place |  |  | 2 |  |  |  | — |  |  |  | 2 |  |  |  | 19 |
| Sales of reserves in place |  |  | (6 | ) |  |  | (124 | ) |  |  | (130 | ) |  |  | (42 | )
| Changes in timing and other |  |  | (35 | ) |  |  | 8 |  |  |  | (27 | ) |  |  | 64 |
Balance, December 31, 2003 |  | $ | 775 |  |  | $ | 23 |  |  | $ | 798 |  |  | $ | 543 |
| Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs |  |  | (205 | ) |  |  | (5 | ) |  |  | (210 | ) |  |  | (81 | )
| Net changes in prices and production costs |  |  | 39 |  |  |  | 7 |  |  |  | 46 |  |  |  | 128 |
| Extensions, discoveries, additions and improved recovery, net of related costs |  |  | 60 |  |  |  | — |  |  |  | 60 |  |  |  | 15 |
| Development costs incurred |  |  | 25 |  |  |  | — |  |  |  | 25 |  |  |  | 29 |
| Revisions of previous quantity estimates and development costs |  |  | (193 | ) |  |  | — |  |  |  | (193 | ) |  |  | 6 |
| Accretion of discount |  |  | 78 |  |  |  | 2 |  |  |  | 80 |  |  |  | 71 |
| Net change in income taxes |  |  | 39 |  |  |  | — |  |  |  | 39 |  |  |  | 60 |
| Purchases of reserves in place |  |  | 2 |  |  |  | — |  |  |  | 2 |  |  |  | 3 |
| Sales of reserves in place |  |  | (5 | ) |  |  | (23 | ) |  |  | (28 | ) |  |  | (733 | )
| Changes in timing and other |  |  | 38 |  |  |  | (4 | ) |  |  | 34 |  |  |  | (41 | )
Balance, December 31, 2004 |  | $ | 653 |  |  | $ | — |  |  | $ | 653 |  |  | $ | — |

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##### Table of Contents

EXHIBIT INDEX

Exhibit |  |
Number |  | Description
| 2 | .1 |  | Purchase and Sale Agreement, dated July 1, 2004, among Calpine Corporation (the “Company”), Calpine Natural Gas L.P. and Pogo Producing Company.(a)
| 2 | .2 |  | Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Natural Gas L.P. and Bill Barrett Corporation.(a)
| 2 | .3 |  | Asset and Trust Unit Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Canada Natural Gas Partnership, Calpine Energy Holdings Limited, PrimeWest Gas Corp. and PrimeWest Energy Trust.(a)
| 3 | .1 |  | Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004.(b)
| 3 | .2 |  | Amended and Restated By-laws of the Company.(c)
| 4 | .1.1 |  | Indenture dated as of May 16, 1996, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(d)
| 4 | .1.2 |  | First Supplemental Indenture dated as of August 1, 2000, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(e)
| 4 | .1.3 |  | Second Supplemental Indenture dated as of April 26, 2004, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(f)
| 4 | .2.1 |  | Indenture dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(g)
| 4 | .2.2 |  | Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(h)
| 4 | .2.3 |  | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e)
| 4 | .2.4 |  | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f)
| 4 | .3.1 |  | Indenture dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(i)
| 4 | .3.2 |  | Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(i)
| 4 | .3.3 |  | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e)
| 4 | .3.4 |  | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f)
| 4 | .4.1 |  | Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(j)
| 4 | .4.2 |  | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e)
| 4 | .4.3 |  | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f)
| 4 | .5.1 |  | Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(j)
| 4 | .5.2 |  | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e)
| 4 | .5.3 |  | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f)
| 4 | .6.1 |  | Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(k)
| 4 | .6.2 |  | First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(e)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .6.3 |  | Second Supplemental Indenture dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee.(l)
| 4 | .7.1 |  | Amended and Restated Indenture dated as of October 16, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee.(m)
| 4 | .7.2 |  | Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(n)
| 4 | .7.3 |  | First Amendment, dated as of October 16, 2001, to Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(m)
| 4 | .8.1 |  | Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(m)
| 4 | .8.2 |  | First Supplemental Indenture, dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(m)
| 4 | .8.3 |  | Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(m)
| 4 | .8.4 |  | First Amendment, dated as of October 18, 2001, to Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(m)
| 4 | .9 |  | Indenture, dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(o)
| 4 | .10 |  | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o)
| 4 | .11 |  | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o)
| 4 | .12 |  | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o)
| 4 | .13.1 |  | Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee, including form of Notes.(p)
| 4 | .13.2 |  | Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(p)
| 4 | .13.3 |  | Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q)
| 4 | .13.4 |  | Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q)
| 4 | .14 |  | Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy Center, as Guarantors, and Wilmington Trust Company, as Trustee and Collateral Agent, including form of Notes.(p)
| 4 | .15 |  | Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(q)
| 4 | .16.1 |  | Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(q)
| 4 | .16.2 |  | Registration Rights Agreement, dated as of November 14, 2003, between the Company and Deutsche Bank Securities, Inc., as Representative of the Initial Purchasers.(q)
| 4 | .17.1 |  | First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q)
| 4 | .17.2 |  | Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .17.3 |  | Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q)
| 4 | .18 |  | Indenture, dated as of June 2, 2004, between Power Contract Financing III, LLC and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(b)
| 4 | .19 |  | Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r)
| 4 | .20.1 |  | Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(s)
| 4 | .20.2 |  | Amendment No. 1 to Rights Agreement, dated as of September 28, 2004, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(l)
| 4 | .20.3 |  | Amendment No. 2 to Rights Agreement, dated as of March 18, 2005, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(bb)
| 4 | .21 |  | Memorandum and Articles of Association of Calpine (Jersey) Limited.(t)
| 4 | .22 |  | Memorandum and Articles of Association of Calpine European Funding (Jersey) Limited.(t)
| 4 | .23 |  | High Tides III
| 4 | .23.1 |  | Amended and Restated Certificate of Trust of Calpine Capital Trust III, a Delaware statutory trust, filed July 19, 2000.(u)
| 4 | .23.2 |  | Declaration of Trust of Calpine Capital Trust III dated June 28, 2000, among the Company, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee and the Administrative Trustees named therein.(u)
| 4 | .23.3 |  | Amendment No. 1 to the Declaration of Trust of Calpine Capital Trust III dated July 19, 2000, among the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein.(u)
| 4 | .23.4 |  | Indenture dated as of August 9, 2000, between the Company and Wilmington Trust Company, as Trustee.(u)
| 4 | .23.5 |  | Remarketing Agreement dated as of August 9, 2000, among the Company, Calpine Capital Trust III, Wilmington Trust Company, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(u)
| 4 | .23.6 |  | Registration Rights Agreement dated as August 9, 2000, between the Company, Calpine Capital Trust III, Credit Suisse First Boston Corporation, ING Barings LLC and CIBC World Markets Corp.(u)
| 4 | .23.7 |  | Amended and Restated Declaration of Trust of Calpine Capital Trust III dated as of August 9, 2000, the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein, including the form of Preferred Security and form of Common Security.(u)
| 4 | .23.8 |  | Preferred Securities Guarantee Agreement dated as of August 9, 2000, between the Company, as Guarantor, and Wilmington Trust Company, as Guarantee Trustee.(u)
| 4 | .24 |  | Pass Through Certificates (Tiverton and Rumford)
| 4 | .24.1 |  | Pass Through Trust Agreement dated as of December 19, 2000, among Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of Certificate.(e)
| 4 | .24.2 |  | Participation Agreement dated as of December 19, 2000, among the Company, Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership, PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee.(e)
| 4 | .24.3 |  | Appendix A — Definitions and Rules of Interpretation.(e)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .24.4 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of December 19, 2000, between PMCC Calpine New England Investment LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, including the forms of Lessor Notes.(e)
| 4 | .24.5 |  | Calpine Guaranty and Payment Agreement (Tiverton) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(e)
| 4 | .24.6 |  | Calpine Guaranty and Payment Agreement (Rumford) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(e)
| 4 | .25 |  | Pass Through Certificates (South Point, Broad River and RockGen)
| 4 | .25.1 |  | Pass Through Trust Agreement A dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 8.400% Pass Through Certificate, Series A.(c)
| 4 | .25.2 |  | Pass Through Trust Agreement B dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 9.825% Pass Through Certificate, Series B.(c)
| 4 | .25.3 |  | Participation Agreement (SP-1) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.4 |  | Participation Agreement (SP-2) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.5 |  | Participation Agreement (SP-3) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.6 |  | Participation Agreement (SP-4) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.7 |  | Participation Agreement (BR-1) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .25.8 |  | Participation Agreement (BR-2) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.9 |  | Participation Agreement (BR-3) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.10 |  | Participation Agreement (BR-4) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.11 |  | Participation Agreement (RG-1) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.12 |  | Participation Agreement (RG-2) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.13 |  | Participation Agreement (RG-3) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.14 |  | Participation Agreement (RG-4) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c)
| 4 | .25.15 |  | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c)
| 4 | .25.16 |  | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c)
| 4 | .25.17 |  | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .25.18 |  | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c)
| 4 | .25.19 |  | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c)
| 4 | .25.20 |  | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c)
| 4 | .25.21 |  | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c)
| 4 | .25.22 |  | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c)
| 4 | .25.23 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c)
| 4 | .25.24 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c)
| 4 | .25.25 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c)
| 4 | .25.26 |  | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c)
| 4 | .25.27 |  | Calpine Guaranty and Payment Agreement (South Point SP-1) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.28 |  | Calpine Guaranty and Payment Agreement (South Point SP-2) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.29 |  | Calpine Guaranty and Payment Agreement (South Point SP-3) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.30 |  | Calpine Guaranty and Payment Agreement (South Point SP-4) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 4 | .25.31 |  | Calpine Guaranty and Payment Agreement (Broad River BR-1) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.32 |  | Calpine Guaranty and Payment Agreement (Broad River BR-2) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.33 |  | Calpine Guaranty and Payment Agreement (Broad River BR-3) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.34 |  | Calpine Guaranty and Payment Agreement (Broad River BR-4) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.35 |  | Calpine Guaranty and Payment Agreement (RockGen RG-1) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.36 |  | Calpine Guaranty and Payment Agreement (RockGen RG-2) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.37 |  | Calpine Guaranty and Payment Agreement (RockGen RG-3) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 4 | .25.38 |  | Calpine Guaranty and Payment Agreement (RockGen RG-4) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c)
| 10 | .1 |  | Financing and Term Loan Agreements
| 10 | .1.1 |  | Share Lending Agreement, dated as of September 28, 2004, among the Company, as Lender, Deutsche Bank AG London, as Borrower, through Deutsche Bank Securities Inc., as agent for the Borrower, and Deutsche Bank Securities Inc., in its capacity as Collateral Agent and Securities Intermediary.(l)
| 10 | .1.2 |  | Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(q)
| 10 | .1.3.1 |  | Letter of Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent.(o)
| 10 | .1.3.2 |  | Amendment to Letter of Credit Agreement, dated as of September 30, 2004, between the Company and The Bank of Nova Scotia, as Administrative Agent.(v)
| 10 | .1.4 |  | Letter of Credit Agreement, dated as of September 30, 2004, between the Company and Bayerische Landesbank, acting through its Cayman Islands Branch, as the Issuer.(v)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 10 | .1.5 |  | Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents.(o)
| 10 | .1.6.1 |  | Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(p)
| 10 | .1.6.2 |  | Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(p)
| 10 | .1.6.3 |  | Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q)
| 10 | .1.6.4 |  | Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q)
| 10 | .1.7 |  | Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(q)
| 10 | .1.8 |  | Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(q)
| 10 | .1.9 |  | Credit Agreement, dated as of June 24, 2004, among Riverside Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(*)
| 10 | .1.10 |  | Credit Agreement, dated as of June 24, 2004, among Rocky Mountain Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(*)
| 10 | .1.11 |  | Credit Agreement, dated as of February 25, 2005, among Calpine Steamboat Holdings, LLC, the Lenders named therein, Calyon New York Branch, as a Lead Arranger, Underwriter, Co-Book Runner, Administrative Agent, Collateral Agent and LC Issuer, CoBank, ACB, as a Lead Arranger, Underwriter, Co-Syndication Agent and Co-Book Runner, HSH Nordbank AG, as a Lead Arranger, Underwriter and Co-documentation Agent, UFJ Bank Limited, as a Lead Arranger, Underwriter and Co-Documentation Agent, and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as a Lead Arranger, Underwriter and Co-Syndication Agent.(*)
| 10 | .2 |  | Security Agreements
| 10 | .2.1 |  | Guarantee and Collateral Agreement, dated as of July 16, 2003, made by the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.2 |  | First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.3 |  | First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 10 | .2.4.1 |  | Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.4.2 |  | Amendment No. 1 to the Second Amendment Pledge Agreement (Stock Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(q)
| 10 | .2.5.1 |  | Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.5.2 |  | Amendment No. 1 to the Second Amendment Pledge Agreement (Membership Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(q)
| 10 | .2.6 |  | First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.7.1 |  | Collateral Trust Agreement, dated as of July 16, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.7.2 |  | First Amendment to the Collateral Trust Agreement, dated as of November 18, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(q)
| 10 | .2.8 |  | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.9 |  | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.10 |  | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.11 |  | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.12 |  | Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.13 |  | Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.14 |  | Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.15 |  | Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.16 |  | Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from the Company to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee.(o)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 10 | .2.17 |  | Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.18 |  | Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.19 |  | Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.20 |  | Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.21 |  | Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(o)
| 10 | .2.22 |  | Designated Asset Sale Proceeds Account Control Agreement, dated as of July 16, 2003, among the Company, Union Bank of California, N.A., and The Bank of New York, as Collateral Agent.(q)
| 10 | .3 |  | Management Contracts or Compensatory Plans or Arrangements.
| 10 | .3.1.1 |  | Employment Agreement, dated as of January 1, 2005, between the Company and Mr. Peter Cartwright.(w)(x)
| 10 | .3.1.2 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Peter Cartwright.(y)(x)
| 10 | .3.2 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Ms. Ann B. Curtis.(c)(x)
| 10 | .3.3 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Ron A. Walter.(c)(x)
| 10 | .3.4 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Robert D. Kelly.(c)(x)
| 10 | .3.5 |  | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Thomas R. Mason.(c)(x)
| 10 | .3.6.1 |  | Consulting Contract, dated as of January 1, 2005, between the Company and Mr. George J. Stathakis.(*)(x)
| 10 | .3.6.2 |  | Consulting Contract, dated as of January 1, 2004, between the Company and Mr. George J. Stathakis.(q)(x)
| 10 | .3.7 |  | Form of Indemnification Agreement for directors and officers.(z)(x)
| 10 | .3.8 |  | Form of Indemnification Agreement for directors and officers.(c)(x)
| 10 | .3.9 |  | Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(q)(x)
| 10 | .3.10 |  | Base Salary, Bonus, Stock Option Grant and Restricted Stock Summary Sheet.(w)(x)
| 10 | .3.11 |  | Form of Stock Option Agreement.(w)(x)
| 10 | .3.12 |  | Form of Restricted Stock Agreement.(w)(x)
| 10 | .3.13 |  | Calpine Corporation 2003 Management Incentive Plan.(*)(x)
| 10 | .3.14 |  | 2000 Employee Stock Purchase Plan.(aa)(x)
| 12 | .1 |  | Statement on Computation of Ratio of Earnings to Fixed Charges.(*)
| 21 | .1 |  | Subsidiaries of the Company.(*)
| 23 | .1 |  | Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm.(*)
| 23 | .2 |  | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.(*)
| 23 | .3 |  | Consent of Netherland, Sewell & Associates, Inc., independent engineer.(*)
| 23 | .4 |  | Consent of Gilbert Laustsen Jung Associates Ltd., independent engineer.(*)
| 24 | .1 |  | Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this report).(*)

##### Table of Contents

Exhibit |  |  |
Number |  |  | Description
| 31 | .1 |  | Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
| 31 | .2 |  | Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
| 32 | .1 |  | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*)
| 99 | .1 |  | Acadia Power Partners, LLC and Subsidiary, Consolidated Financial Statements, December 31, 2003, 2002 and 2001.(*)
| 99 | .2 |  | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.(*)

(*) |  | Filed herewith.
(a) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K/ A filed with the SEC on September 14, 2004.
(b) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004.
(c) |  | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2001, filed with the SEC on March 29, 2002.
(d) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-06259) filed with the SEC on June 19, 1996.
(e) |  | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.
(f) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2004, filed with the SEC on May 10, 2004.
(g) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.
(h) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-41261) filed with the SEC on November 28, 1997.
(i) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-61047) filed with the SEC on August 10, 1998.
(j) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-72583) filed with the SEC on March 8, 1999.
(k) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17, 2002.
(l) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 30, 2004.
(m) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001.
(n) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-57338) filed with the SEC on April 19, 2001.
(o) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
(p) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003.
(q) |  | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004.
(r) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on October 6, 2004.
(s) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form 8-A/ A (Registration No. 001-12079) filed with the SEC on September 28, 2001.

##### Table of Contents

(t) |  | This document has been omitted in reliance on Item 601(b)(4)(iii) of Regulation S-K. Calpine Corporation agrees to furnish a copy of such document to the SEC upon request.
(u) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration Statement No. 333-47068) filed with the SEC on September 29, 2000.
(v) |  | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2004, filed with the SEC on November 9, 2004.
(w) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 17, 2005.
(x) |  | Management contract or compensatory plan or arrangement.
(y) |  | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, filed with the SEC on February 29, 2000.
(z) |  | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-1/ A (Registration Statement No. 333-07497) filed with the SEC on August 22, 1996.
(aa) |  | Incorporated by reference to Calpine Corporation’s Definitive Proxy Statement on Schedule 14A dated April 13, 2000, filed with the SEC on April 13, 2000.
(bb) |  | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 23, 2005.