UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission file number: 333-117335

Calpine Generating Company, LLC

(A Delaware Limited Liability Company)

CalGen Finance Corp.

(A Delaware Corporation)

I.R.S. Employer Identification Nos.

77-0555128

20-1162632

50 West San Fernando Street, 5th Floor

San Jose, California 95113

Telephone: (408) 995-5115

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

None

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.     þ

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

      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:

      The aggregate market value of the common equity held by non-affiliates of the registrants as of June 30, 2004 was $0.

      Calpine Generating Company, LLC is a single member limited liability company and has no common stock.

      With respect to CalGen Finance Corp., 1,000 shares of common stock, par value $1, were outstanding as of the date hereof.

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DOCUMENTS INCORPORATED BY REFERENCE

None

OMISSION OF CERTAIN INFORMATION

TABLE OF ADDITIONAL REGISTRANTS

FORM 10-K

ANNUAL REPORT

For the Year Ended December 31, 2004

TABLE OF CONTENTS

      The collateral for the outstanding notes described in Note 5 to the consolidated financial statements of Calpine Generating Company, LLC includes the pledge of Calpine Generating Company, LLC’s membership interest in CalGen Expansion Company, LLC. Separate financial statements pursuant to Rule 3.16 of Regulation S-X are not included herein for CalGen Expansion Company, LLC because, with the exception of the nominal capitalization of $1,000 associated with CalGen Finance Corp., the consolidated financial statements of CalGen Expansion Company, LLC are identical to the consolidated financial statements of Calpine Generating Company, LLC included herein.

PART I

      In addition to historical information, this report contains forward-looking statements. Such statements include those concerning Calpine Generating Company, LLC’s (“CalGen” or “the Company”) expected financial performance and its 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 involve a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements such as, but 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 operation of the Pastoria facility, such as failure to obtain the necessary permits to operate or failure of third-party contractors to perform their contractual obligations, (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) uncertainties associated with sources and uses of cash , that actual sources may be lower and actual uses may be higher than estimated, (xi) present and possible future claims, litigation and enforcement actions, (xii) effects of the application of regulations, including changes in regulations or the interpretation thereof, or (xiii) other risks as identified herein. You should also carefully review the risks described in other reports that we file with the Securities and Exchange Commission, including without limitation our Form S-4 filed on July 13, 2004 and amended on October 19, 2004. We undertake no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise. The Risk Factors presented in our Form S-4 filed on July 13, 2004 and amended on October 19, 2004 are hereby incorporated by reference.

      We file annual, quarterly and periodic reports, 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. The SEC also maintains an Internet website at http://www.sec.gov that contains reports 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. 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.

COMPANY OVERVIEW

      We are a power generation company engaged, through our subsidiaries, in the construction, ownership and operation of electric power generation facilities and the sale of energy, capacity and related products in the United States of America. We are an indirect, wholly-owned subsidiary of Calpine Corporation (“Calpine” or the “Parent”). We indirectly own 14 power generation facilities (the “projects” or “facilities”) that are expected to have an aggregate combined estimated peak capacity of 9,834 MW (nominal 8,425 MW without peaking capacity), including our Pastoria facility which is currently under construction. Our combined peak capacity represents approximately 30.6% of Calpine’s 32,149 MW of aggregate estimated peak capacity in operation and under construction. Thirteen of our facilities are natural gas-fired combined cycle facilities and

our Zion facility is a natural gas-fired simple cycle facility. Thirteen of our facilities are currently operating and have an aggregate estimated peak capacity of 9,065 MW.

      CalGen Finance Corp. (“CalGen Finance”) is our wholly-owned subsidiary and was formed solely for the purpose of facilitating the offering of our debt securities by acting as a co-issuer of those securities. CalGen Finance is nominally capitalized and does not have any operations or revenues.

      Calpine Energy Services, L.P. (“CES”) is an indirect wholly-owned subsidiary of Calpine and is primarily engaged in managing the value of Calpine’s electrical generation and gas production assets. It provides trading and risk management services to Calpine and its affiliates in connection with the scheduling of electrical energy and capacity sales and fuel deliveries to meet delivery requirements and the optimization of the value of Calpine’s electrical generation and gas assets. CES supplies gas to and purchases power from our facilities pursuant to the WECC Fixed Price Gas Sale and Power Purchase Agreement and the Index Based Gas Sale and Power Purchase Agreement, described in more detail below under “Principal Agreements.”

      Calpine Operating Services Company, Inc. (“COSCI”) was formed in 2002 to consolidate the operational functions of Calpine and certain of Calpine’s affiliates. Each of our facilities is operated and maintained under a Master Operation and Maintenance Agreement with COSCI, which has an initial term of 10 years beginning March 23, 2004. Under the Master Operation and Maintenance Agreement, COSCI provides all services necessary to operate and maintain all facilities, including developing operating plans for each facility. Major maintenance, which is currently provided pursuant to agreements with Siemens Westinghouse Power Corporation or General Electric Company, is expected to be provided by COSCI when those agreements are terminated. See “Principal Agreements.”

      Calpine Construction Management Company, Inc. (“CCMCI”), an indirect wholly-owned subsidiary of Calpine, is managing the construction of the Pastoria facility under a Master Construction Management Agreement. Under this agreement, CCMCI is responsible for managing all of the construction and supply contracts related to the Pastoria facility and supervising and coordinating all construction activities. CCMCI is also responsible for the acceptance and commissioning of this facility, and for running all performance and acceptance tests. See “Principal Agreements.”

PRINCIPAL AGREEMENTS

      On March 23, 2004, we completed an offering of $2.4 billion in secured term loans and secured notes. Concurrent with the closing of this offering, we entered into a series of agreements with certain of our affiliates.

Purchase of Gas and Sale of Power

      Each of our facilities entered into the Index Based Gas Sale and Power Purchase Agreement (the “Index Based Agreement”) with CES. In addition, the Delta and Los Medanos facilities entered into the WECC Fixed Price Gas Sale and Power Purchase Agreement (the “Fixed Price Agreement”) with CES. Under these agreements, CES purchases substantially all of the output from each facility (subject to certain exceptions for direct sales to third parties), and sells or delivers to each facility substantially all of the gas required for its operations (subject to certain exceptions for gas purchases from third parties).

      Fixed Price Agreement. Under the Fixed Price Agreement, CES purchases a total of 500 MW of capacity and associated energy from the Delta and Los Medanos facilities for a fixed price. In addition, CES will provide substantially all of the gas required to generate the energy scheduled pursuant to this agreement. The agreement is written such that CES makes a net payment of $3,615,346 (equivalent to $7.231/kW-month) each month for power purchased and gas sold under this agreement. In addition, CES makes variable operation and maintenance payments, which are dependent on the amount of energy delivered and the amount of operating time during on-peak hours. CES has the right in its sole discretion to schedule deliveries of energy from each facility up to its respective contracted capacity. However, the fixed payment shall be payable in full whether or not electricity deliveries have been scheduled, except for a facility’s failure to deliver. Calpine

guarantees CES’s performance under this agreement. The Fixed Price Agreement is in effect through December 31, 2009, unless terminated earlier as permitted. Upon expiration or termination of the agreement, all capacity and associated energy would automatically be subject to the Index Based Agreement.

      Index Based Agreement. Under the Index Based Agreement, CES purchases the available electric output of each facility not previously sold under another long-term agreement. In addition, CES sells to each facility substantially all of the gas required to operate. Calpine guarantees CES’s performance under this agreement, which is in effect through December 31, 2013, unless terminated earlier as permitted.

      Pursuant to the Index Based Agreement, our off-peak, peaking and power augmentation products will be sold to CES at a fixed price through December 31, 2013. In addition, all of our remaining on-peak capacity will be sold to CES at a floating spot price that reflects the positive (if any, but never negative) difference between day-ahead power prices and day-ahead gas prices using indices chosen to approximate the actual power price that would be received and the actual gas price that would be paid in the market relevant for each facility. Each month, CES pays a net contract price for energy purchased and gas sold under this agreement. The contract price will equal the sum of:

      The Index Based Agreement also provides for the issuance of letters of credit under our revolving credit facility which support certain gas supply agreements between CES, the projects and third parties. The Index Based Agreement has been amended since the closing of the offering of the original notes to provide for the issuance of letters of credit under our revolving credit facility to support certain gas supply agreement between CES and third parties under certain circumstances, to account for Solutia’s rejection of certain agreements with the Decatur facility, and to permit “buy-sell” arrangements under certain circumstances that will enable us to buy gas directly and have it transported by CES.

Operation of Facilities

      Master Operation and Maintenance Agreement. Under the Master Operation and Maintenance Agreement (the “O&M Agreement”), COSCI provides all services necessary to operate and maintain each facility (other than major maintenance, which is not currently provided by COSCI under the Master Maintenance Services Agreement described below and general and administrative services, which are provided as described under the Administrative Services Agreement below). Covered services include labor and operating costs and fees, routine maintenance, materials and supplies, spare parts (except for combustion turbine hot path spare parts), tools, shop and warehouse equipment, safety equipment and certain project consumables and contract services (including facility maintenance, temporary labor, consultants, waste disposal, corrosion control, fire protection, engineering and environmental services), as well as procurement of water supply, water treatment and disposal, waste disposal, electricity usage and demand costs, fixed utility access, interconnection and interconnection maintenance charges, gas and electric transmission costs and emergency services.

      All work and services performed under the O&M Agreement is provided on a cost reimbursable basis plus reasonable overhead. Costs payable to COSCI shall not, in the aggregate, exceed costs for similar goods

or services that would normally be charged by unrelated third parties and shall in no event exceed the prices that COSCI charges to unrelated third parties for such goods or services. Calpine guarantees COSCI’s performance under this agreement The O&M Agreement has an initial term of 10 years beginning March 23, 2004 and is automatically extended for successive one-year periods thereafter until terminated by either party.

      Master Maintenance Services Agreement. At December 31, 2004, major maintenance services were provided for under agreements with Siemens Westinghouse Power Corporation or General Electric Company. Under the Master Maintenance Services Agreement (the “Maintenance Agreement”), COSCI will provide major maintenance services when agreements with third parties are terminated. Until the third-party agreements are terminated, the Maintenance Agreement provides that COSCI will act as the administrator of the third-party maintenance agreements. Calpine guarantees COSCI’s performance under the Maintenance Agreement. In addition, Calpine indemnifies the facilities for any costs or expenses incurred in the termination of these third-party maintenance agreements.

      The Maintenance Agreement applies to major maintenance services, such as turbine overhauls or other major maintenance events as agreed upon by the parties, and is distinct from the O&M Agreement (which provides routine operation and maintenance). Under the Maintenance Agreement, COSCI provides periodic inspection services relating to the combustion turbines for each covered facility, including all labor, supervision and technical assistance (including the services of an experienced maintenance program engineer) necessary to provide these inspection services. COSCI also provides new parts and repairs or replaces old or worn out parts for the combustion turbines, and will provide technical field assistance, project engineers and support personnel related to the performance of its services under this agreement. The services under this agreement are to be consistent with the annual operating plan for each facility developed pursuant to the O&M Agreement. The Maintenance Agreement was executed on March 23, 2004 and has an initial term of 10 years.

Project Construction

      Master Construction Management Agreement. Under the Master Construction Management Agreement (the “Construction Agreement”), CCMCI manages the construction of the Pastoria facility and the coordination of the various construction and supply contracts. In addition, CCMCI is responsible for the acceptance and commissioning of Pastoria and its various subsystems as they are completed, for starting up the facility and for running all performance and acceptance tests. The Construction Agreement is effective until the final completion of the facility. Calpine guarantees CCMCI’s obligations under this agreement.

      CCMCI is reimbursed for all project personnel and third party costs incurred in connection with the construction of the facility.

General Administrative Matters

      Administrative Services Agreement. Under the Administrative Services Agreement (the “Administrative Agreement”), Calpine Administrative Services Company, Inc. (“CASCI”) performs the following administrative services: accounting, financial reporting, budgeting and forecasting, tax, cash management, review of significant operating and financial matters, contract administrative services, invoicing, computer and information services and such other administrative and regulatory filing services as may be directed by us. We pay CASCI on a cost reimbursable basis, including internal Calpine costs and reasonable overhead, for services provided. The Administrative Agreement was executed on March 23, 2004 and has an initial term of 10 years. Calpine guarantees CASCI’s obligations under this agreement.

THE MARKET FOR ELECTRICITY

      The electric power industry represents one of the largest industries in the United States and impacts nearly every aspect of our economy, with an estimated end-user market of nearly $268 billion of electricity sales in 2004 based on information published by the Energy Information Administration of the Department of Energy (“EIA”). Historically, the power generation industry has been largely characterized by electric utility monopolies producing electricity from old, inefficient, polluting, high-cost generating facilities selling to a

captive customer base. However, industry trends and regulatory initiatives have transformed some markets into more competitive grounds where load-serving entities and end-users may purchase electricity from a variety of suppliers, including independent power producers (“IPPs”), power marketers, regulated public utilities and others. For the past decade, the power industry has been deregulated at the wholesale level allowing generators to sell directly to the load serving entities such as public utilities, municipalities and electric cooperatives. Although industry trends and regulatory initiatives aimed at further deregulation have slowed, the power industry continues to transform into a more competitive market.

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

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

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

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

Regional Markets

      West. The West has historically been characterized by tight supply/demand fundamentals. Some of the challenges include a lengthy and difficult permitting process, stricter environmental regulations and difficulties in gaining access to water. In addition, it is difficult to find new power generating sites, particularly in California, where most of our Western facilities are located, given the cost of real estate and the general public’s “not in our backyard” mentality. Furthermore, gas system bottlenecks and electric transmission constraints in this region can limit the supply of fuel and power to certain submarkets, which increases power prices and volatility. The West’s baseload demand is primarily met with nuclear, coal, and hydro generation. However, gas-fired power generation facilities generally set the market clearing price in the West and CalGen’s newer, more efficient gas-fired facilities are able to compete favorably. In recent years, a significant

portion of older and less efficient capacity has been displaced and retired. Provided that this trend continues, we expect to see improvements in the relative economics of our Western facilities.

      ERCOT. Located entirely within the State of Texas, Electric Reliability Council of Texas (“ERCOT”) is isolated from our other regions due to transmission constraints. In recent years, ERCOT has experienced an increase in the construction and development of new and efficient natural gas-fired generation, which sets the market price for power during almost all hours of the year. We primarily compete with other combined cycle power generation facilities, combustion turbine facilities, and older, less efficient oil and gas steam turbine facilities. An estimated 2,500 MW of older oil and gas power generation has been retired in recent years. A continuation of this trend would improve spark spreads and increase the operating hours of our facilities. According to NERC, electricity consumption in ERCOT grew by over 5.0% per year during the mid to late 1990’s and by approximately 3.9% in 2004. We believe that spark spreads could increase to the extent demand continues to grow. Higher demand could also increase our run hours.

      Southeast. The Southeast can be characterized as having a high level of baseload coal and nuclear generation. As a result, natural gas-fired generation does not set the market price for power as often as it does in the West and ERCOT. Additionally, increased construction and development of new gas-fired generation has created an oversupply in the region. However, strong energy growth in comparison with other regions could ease the overbuild situation in the next three to five years.

      Other. We also have facilities located in Oklahoma and Illinois. These regions have a significant proportion of coal-fired power generation and are currently characterized by low marginal costs relative to natural gas-fired capacity. Coal commodity prices currently drive regional generation economics, setting the market price for power for most of the year. Emissions regulations could have a significant impact on the coal plants causing retirements or retrofits that could increase the market price. Approximately 30.0% of our capacity in these markets is committed for delivery under long-term contracts.

      The following table describes, by region, our facilities and their estimated peak capacity and allocates our generation capacity by contract type:

This table includes our Pastoria facility which is currently under construction.

DESCRIPTION OF POWER GENERATION FACILITIES

      We own 14 power generation facilities that are expected to have an aggregate combined estimated peak capacity of 9,834 MW (nominal 8,425 MW without peaking capacity), upon completion of the Pastoria Energy Center which is currently under construction. Our portfolio of power generation assets experienced a weighted average combined cycle heat rate of 7,110 btu/kwh in 2004. Substantially all of our power generation facilities are located on sites which we own or lease on a long-term basis. See Item 2. “Properties.”

      Thirteen of our facilities are natural gas-fired combined cycle facilities while Zion Energy Center is a natural gas-fired simple cycle facility. The three principal components of a combined cycle facility are the combustion turbine, the heat recovery steam generator (“HRSG”) and the steam turbine. In a combined cycle facility, inlet air is introduced into the combustion turbines before being compressed by the turbine-driven compressor. Fuel and compressed air then mix and burn in the turbine combustion system, creating a high-pressure hot gas, which is expanded through a four-stage power turbine. The combustion turbine drives the turbine’s compressor section and the electric generator. Heat from the combustion turbine exhaust is directed to the HRSG to convert water into steam to generate additional electric energy, thereby increasing the thermal cycle efficiency. The steam turbine uses the steam from the HRSG to create mechanical energy that is converted into electrical energy by a generator. For emissions control, each combustion turbine’s exhaust passes through a catalyst bed for control and reduction of nitrogen oxides. A selective catalytic reduction system, including ammonia injection, is used for nitrogen oxide control. Some of the facilities also provide an oxidation catalyst for control of carbon monoxide emissions. A simple cycle facility has the same gas turbine components as a combined cycle facility, but it does not have a steam generator or steam turbine and the accompanying water treatment facilities to support that equipment.

Operating Power Plants

The West (Delta, Goldendale, Los Medanos and Pastoria)

      We own 2,488 MW of estimated peak capacity (nominal 2,292 MW without peaking capacity) in the West. Of this total, 1,448 MW (nominal 1,296 MW without peaking capacity) is in operation in California, 769 MW (nominal 759 MW without peaking capacity) is under construction in California, and 271 MW (nominal 237 MW without peaking capacity) is in operation in Washington.

      Delta Facility. The Delta facility is a nominal 799 MW natural gas-fired combined cycle generating facility consisting of three combustion turbines and three HRSGs with an estimated peak capacity of 882 MW. The facility is an exempt wholesale generator (“EWG”) and is located on a 20-acre site in Pittsburg, California, which we lease from The Dow Chemical Company (“Dow”). The initial term of the lease expires in 2050; however, we have the right to extend the lease on a month-to-month basis. Either party may terminate the lease if the other party materially defaults on its obligations under the lease. The facility commenced commercial operations in June 2002.

      The facility currently leases certain of its equipment from our affiliate and wholly-owned subsidiary, CalGen Project Equipment Finance. This leased equipment was pledged as part of the offering of the original notes.

      CES supplies the facility with natural gas, which is transported from PG&E’s pipeline system across a lateral pipeline co-owned by the facility, the Los Medanos facility and our affiliate, Gilroy Energy Center, LLC, as tenants-in-common. The lateral pipeline is operated by our affiliate, CPN Pipeline Company.

      The facility interconnects to the PG&E interstate electric system and sells the power it generates to CES, under a Reliability-Must-Run (“RMR”) agreement with the California Independent System Operator (“CAISO”).

      Goldendale Facility. The Goldendale facility is a nominal 237 MW natural gas-fired combined cycle power generating facility consisting of a combustion turbine and an HRSG, which supplies steam to a steam turbine generator, with an estimated peak capacity of 271 MW. The facility is an EWG and is located on a 42-acre site owned by the facility in Goldendale, Washington. The facility commenced commercial operation in September 2004.

      CES supplies the facility with natural gas, which is transported across an interstate pipeline and a 5-mile lateral pipeline owned and operated by Northwest Pipeline Corporation, a subsidiary of The Williams Companies, Inc.

      The facility interconnects to a Bonneville Power Administration (“BPA”) substation through the transmission system of Klickitat Public Utility District and sells the power it generates to CES. The facility has also obtained certain transmission rights through the BPA.

      Los Medanos Facility. The Los Medanos facility is a nominal 497 MW natural gas-fired combined cycle generating facility consisting of two combustion turbines, each with its own HRSG. The steam generators supply steam to a single steam turbine generator. Two auxiliary boilers supplement the facility’s steam production capabilities. The facility has an estimated peak capacity of 566 MW and is a “qualifying facility” (“QF”) under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). It is located on a 12-acre site in Pittsburg, California, which we lease from USS-POSCO Industries (“UPI”). The initial term of the lease expires in 2021; however, we have a right to extend the lease for up to four consecutive five-year terms. The facility commenced commercial operation in August 2001.

      CES supplies the facility with natural gas, which is transported from PG&E’s pipeline system across a lateral pipeline co-owned by the facility, the Delta facility and our affiliate, Gilroy Energy Center, LLC, as tenants-in-common. The lateral pipeline is operated by our affiliate, CPN Pipeline Company.

      The facility interconnects to the PG&E interstate electric system and sells the power it generates to CES and UPI, and may supply power to Dow. It is also a party to an RMR agreement with CAISO, pursuant to which it sells reliability services and may sell energy. The facility delivers power to UPI by means of on-site interconnections.

      Pastoria Facility. In April 2001 we acquired the rights to develop the 769-megawatt 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. The Pastoria facility will be a nominal 759 MW gas-fired combined cycle power generating facility, with an estimated peak capacity of 769 MW. The facility is an EWG and is currently under construction on a 30-acre site in Kern County, California, which we lease from Tejon Ranchcorp, Inc. The initial term of the lease expires in 2026; however we have the right to extend the lease for up to three consecutive five-year terms.

      The commercial operation of the facility will commence in two phases. Phase I will consist of one combustion turbine and one HRSG, as well as a steam turbine generator. Phase II will consist of two combustion turbines and two HRSG, as well as a steam turbine generator. CCMCI manages the construction process and is also the prime construction contractor.

      CES will supply the facility with natural gas, which will be transported from the Kern River Gas Transmission Company’s interstate transmission system to a lateral pipeline owned by the facility and operated by our affiliate, CPN Pipeline Company. CES has certain arrangements with third parties related to the facility’s gas interconnection and transportation. As security for the performance of CES’s obligations under the Index Based Agreement, it has granted the facility a security interest in these arrangements.

      The facility interconnects to a CAISO-controlled power grid at a substation owned and operated by Southern California Edison Company and will sell the power it generates to CES.

ERCOT (Baytown, Channel, Corpus Christi and Freestone)

      We own 2,963 MW (nominal 2,705 MW without peaking capacity) of estimated peak capacity in ERCOT, which is located entirely within the State of Texas.

      Baytown Facility. The Baytown facility is a nominal 742 MW natural gas-fired combined cycle generating facility consisting of three combustion turbines, with three HRSGs that supply steam to a steam turbine generator. Two auxiliary boilers supplement the facility’s steam production capabilities. The facility has an estimated peak capacity of 830 MW and is a QF under PURPA. The facility commenced commercial operation in June 2002.

      The facility is located on a 24-acre site in Baytown, Texas, which we lease from Bayer Corporation (“Bayer”). The initial term of the lease expires in 2022; however, we have the right to extend the lease for up to four consecutive five-year terms. Either party may terminate the lease if the other party materially defaults on its obligations under the lease or cross defaults occur with respect to certain other agreements between Bayer and the facility. If the facility materially breaches its energy services agreement with Bayer, Bayer may, at its option, take over the operation of the facility. This step-in right is not subject to third-party security interests, including the interests securing the notes.

      On termination of the energy services agreement with Bayer, Bayer has an option to purchase the facility in whole or in part. If Bayer terminates the energy services agreement for convenience, the facility terminates the agreement because of a material default by Bayer or the agreement terminates because the facility is substantially destroyed, Bayer would be required to pay a purchase price equal to the greater of fair market value or book value plus a premium if it exercises its purchase option. If the energy services agreement is terminated due to a delivery breach by the facility, Bayer would be required to pay a purchase price equal to book value less Bayer’s pre-termination damages or 80.0% of book value, whichever Bayer prefers. If the

energy services agreement expires and Bayer exercises its purchase option, the purchase price would be the greater of book value or fair market value.

      CES supplies the facility with natural gas, which is transported across a lateral gas pipeline owned and operated by our affiliate, Calpine Texas Pipeline. As security for the performance of its transportation obligations, Calpine Texas Pipeline has granted the facility a security interest in the portion of the lateral pipeline necessary to support project operations.

      The facility interconnects with a transmission system owned by CenterPoint Energy (“CenterPoint”). The facility also interconnects with the Bayer distribution system for purposes of supplying power to Bayer and sells power it generates to CES and to Bayer.

      Channel Facility. The Channel facility is a nominal 527 MW natural gas-fired combined cycle generating facility, with an estimated peak capacity of 574 MW. Phase I of the facility, consisting of one combustion turbine and an HRSG, commenced commercial operation in July 2001. Phase II of the facility, consisting of one combustion turbine and an HRSG, as well as a steam turbine generator, commenced commercial operation in April 2002. Three auxiliary boilers supplement the facility’s steam production capabilities. The facility is a QF and is located on a 12-acre site in Houston, Texas, that we lease from Lyondell-CITGO Refining L.P. (“LCR”).

      The initial term of the lease expires in 2041; however, we have the right to extend the lease for either 10 or 25 years. If the facility materially breaches certain of its lease obligations or defaults on the energy services agreement between LCR and the facility, title to the facility’s boilers, water facilities, and 138 KV substation automatically passes to LCR. This right is not subject to third-party security interests, including the interests securing the notes.

      CES supplies the facility with natural gas, which is transported across pipelines owned and operated by affiliates of Kinder Morgan, Inc. Refinery gas and natural gas may also be supplied to the facility by LCR by means of an on-site interconnect.

      The facility interconnects with the transmission system of CenterPoint. Power supplied to LCR is delivered by means of on-site interconnections and the facility sells the power it generates to CES and LCR.

      Corpus Christi Facility. The Corpus Christi facility is a nominal 414 MW natural gas-fired combined cycle generating facility, with an estimated peak capacity of 537 MW. The facility commenced commercial operation in October 2002 and consists of two combustion turbines and two HRSGs that supply steam to a single steam turbine generator. Two auxiliary boilers supplement the facility’s steam production capabilities.

      The facility is a QF and is located on a nine-acre site in Corpus Christi, Texas, which we lease from CITGO Refining and Chemicals Company L.P. (“CITGO”). The initial term of the lease expires in 2042; however, we have the right to extend the lease for up to two consecutive five-year terms. In the event we decide to dispose of all or any part of our interest in the facility, CITGO must first be offered such interest.

      The facility obtains natural gas from CES, and natural gas and other gas products from CITGO, which is transported by CrossTex CCNG Transmission, Ltd. (“CrossTex”). The facility accesses the gas from two pipelines owned by CrossTex and a pipeline owned by EPGT Texas Pipeline, L.P. Fuel supplied to the facility by CITGO is delivered to the facility through an on-site pipeline that interconnects with CITGO.

      The facility interconnects with AEP Texas Central Company’s transmission system and sells the power it generates to CES, CITGO, Elementis Chromium L.P. (“Elementis”) and Flint Hills Resources, L.P. (“Flint Hills”). Power supplied to CITGO, Elementis and Flint Hills is delivered through on-site interconnections.

      Freestone Facility. The Freestone facility is a nominal 1,022 MW natural gas-fired combined cycle generating facility consisting of four combustion turbines, four HRSGs and two steam turbine generators, configured in two largely independent power blocks. The facility has an estimated peak capacity of 1,022 MW and commenced commercial operation in June 2002. The facility is an EWG and is located on a 506-acre site owned by the facility near Fairfield, Texas.

      CES supplies the facility with natural gas, which is transported across a lateral gas pipeline owned and operated by our affiliate, Calpine Texas Pipeline. As security for the performance of its transportation obligations, Calpine Texas Pipeline has granted the facility a security interest in the lateral pipeline.

      The facility interconnects to TXU Corp.’s transmission system and sells the power it generates to CES.

The Southeast (Carville, Columbia, Decatur, Morgan)

      We own 2,876 MW of estimated peak capacity (nominal 2,434 MW without peaking capacity) in the Southeast. Of this total 1,704 MW (nominal 1,515 MW without peaking capacity) is in operation in Alabama, 531 MW (nominal 455 MW without peaking capacity) is in operation in Louisiana, and 641 MW (nominal 464 MW without peaking capacity) is in operation in South Carolina.

      Carville Facility. The Carville facility is a nominal 455 MW natural gas-fired combined cycle cogeneration facility consisting of two combustion turbines, two HRSGs and a single steam turbine generator, with an estimated peak capacity of 531 MW. The facility is a QF and is located on a 40-acre site owned by the facility in St. Gabriel, Louisiana, adjacent to a styrene monomer manufacturing facility owned by Cos-Mar, Inc. (“Cos-Mar”). The facility commenced commercial operation in June 2003.

      CES supplies the facility with natural gas, which is transported through pipelines connected to Acadian Gas Pipeline System’s and Bridgeline Holdings, L.P.’s transportation system.

      The facility sells the power it generates to CES, Cos-Mar and Entergy. The facility delivers power to Cos-Mar and Entergy by means of the on-site interconnections.

      Columbia Facility. The Columbia facility is a nominal 464 MW natural gas-fired combined cycle power generation facility consisting of two combustion turbines, each with its own HRSG supplying steam to a single steam turbine generator. Three auxiliary boilers supplement the facility’s steam production capabilities. The facility has an estimated peak capacity of 641 MW and commenced commercial operation in March 2004.

      The facility is a QF and is located on a 24-acre site near Columbia, South Carolina, which we lease from Eastman Chemical Company (“Eastman”). The initial term of the lease expires in 2044 and, if both parties agree, the term may be extended. Either party may terminate the lease if the other party materially defaults on its obligations under the lease or, Eastman may terminate the lease if certain cross defaults occur with respect to certain other agreements between Eastman and the facility. If the facility materially breaches certain of its lease obligations or cross defaults, Eastman may, at its option, step-in and operate the facility. This step-in right is not subject to third-party security interests, including the interests securing the notes. In the event we decide to dispose of all or any part of our interest in the facility, Eastman must first be offered such interest.

      CES supplies the facility with natural gas, which is transported across intrastate pipeline systems owned and operated by South Carolina Pipeline Corporation and Southern Natural Gas Company, under both firm and interruptible transportation agreements.

      The facility interconnects with the South Carolina Electric and Gas Co. power transmission system and sells the power it generates to CES.

      Decatur Facility. The Decatur facility is a nominal 793 MW natural gas-fired combined cycle generating facility, with an estimated peak capacity of 852 MW. Phase I of the facility, consisting of two combustion turbines with HRSGs and a steam turbine generator, commenced commercial operation in June 2002. Phase II of the facility, consisting of one combustion turbine and an HRSG, commenced commercial operation in June 2003.

      The facility sells the power it generates to CES and to the Tennessee Valley Authority (“TVA”). The facility had an arrangement to sell certain of the power it generated to Solutia, which filed for protection from creditors pursuant to Chapter 11 of the bankruptcy code in December 2003. As a result, Solutia rejected certain of our contracts as executory contracts.

      The facility is currently a QF. However, Solutia, Inc. (“Solutia”), the Decatur facility’s steam host, is subject to a bankruptcy proceeding and recently rejected its steam sales agreement with the Decatur facility.

As a result, the facility does not satisfy the Federal Energy Regulatory Commission’s (“FERC”) operating and efficiency standards for QFs. The Decatur facility received a waiver of these operating and efficiency standards for calendar year 2004 and 2005. Solutia also rejected a facility lease addendum, which had allowed the Decatur facility to supply power to Solutia. CES has agreed to purchase the facility’s capacity pursuant to the Index Based Agreement. The Decatur facility has the right to file for EWG status, which would maintain Decatur’s exemption from Public Utility Holding Company Act of 1935, as amended (“PUHCA”) if it fails to maintain its QF status — for example if it cannot replace its steam host and is unable to obtain further waivers from FERC. In addition, if Decatur fails to maintain its QF status, it would need to apply for and be granted market-based rate authority from FERC to sell power at wholesale under the Index Based Agreement.

      The facility is located on a 20-acre site near Decatur, Alabama, which we lease from Solutia. The initial term of the lease expires in 2024, however, we have the right to extend the lease for up to three consecutive 15-year terms. Either party may terminate the lease if the other party materially defaults on its obligations under the lease, and Solutia may terminate the lease if certain cross defaults occur with respect to certain other agreements between Solutia and the facility.

      CES supplies the facility with natural gas, which is transported by means of the intrastate pipeline owned and operated by Enbridge Pipelines (Bamagas Intrastate) LLC (“Enbridge”), which interconnects with three interstate pipelines. Enbridge provides firm transportation rights to the facility.

      Morgan Facility. The Morgan facility is a nominal 722 MW natural gas-fired combined cycle generating facility, with an estimated peak capacity of 852 MW. Phase I of the facility, consisting of one combustion turbine generator and one HRSG, commenced commercial operation in January 2004. Phase II of the facility, consisting of two combustion turbine generators, two HRSGs and a steam turbine generator, commenced commercial operation in June 2003. The facility did not meet FERC’s efficiency requirements for QFs in the first period (April 2003 to April 2004). FERC granted a 12-month waiver on April 16, 2004 for the first period. Morgan has met the requirements to be a QF for the second period, calendar year 2004, however.

      The facility is located on a 17-acre site near Decatur, Alabama, which we lease from BP Amoco Chemical Company (“BP Amoco”). The initial term of the lease expires in 2033; however, we have the right to extend the lease for an additional term of up to 35 years.

      CES supplies the facility with natural gas, which is delivered to the facility from the Tennessee Gas and Texas Eastern Transmission interstate pipelines by means of a lateral pipeline owned and operated by Enbridge.

      The facility interconnects with TVA’s power transmission system and sells the power it generates to CES, BP Amoco and TVA.

Other (Oneta and Zion)

      We own 1,507 MW of estimated peak capacity (nominal 994 MW without peaking capacity) in our other regions, Oklahoma and Illinois. Of this total, 513 MW of peak capacity is in operation in Illinois and 994 MW (nominal 994 MW without peaking capacity) is in operation in Oklahoma.

      Oneta Facility. The Oneta facility is a nominal 994 MW natural gas-fired combined cycle generating facility, with an estimated peak capacity of 994 MW. Phase I of the facility, consisting of two combustion turbines, each with its own HRSG, and one steam turbine, commenced commercial operation in July 2002. Phase II of the facility, consisting of two more combustion turbines with HRSGs and another steam turbine, commenced commercial operation in June 2003. The facility is an EWG and is located on a 58-acre site that the facility owns near Coweta, Oklahoma.

      CES supplies the facility with natural gas, which is delivered to the facility through pipelines owned by Enogex, Inc. under agreements between CES and a subsidiary of Enogex. Natural gas is also delivered to the facility through pipelines owned by Oneok Gas Transportation, LLC. CES has certain arrangements with third parties related to the facility’s gas interconnection and transportation. As security for its performance under the Index Based Agreement, CES has granted the facility a security interest in these arrangements.

      The facility is interconnected to Public Service Company of Oklahoma’s power transmission system and sells the power it generates to CES. The facility has not obtained long-term firm electric transmission service; therefore all transmission service is currently short-term, on an hourly or daily basis.

      Zion Facility. The Zion facility is a 513 MW simple-cycle peaking generating facility. Phase I of the facility, consisting of two combustion turbines, commenced commercial operation in June 2002. Phase II of the facility, consisting of a third combustion turbine, commenced commercial operation in June 2003. The facility is an EWG and is located on a 114-acre site owned by the facility in Zion, Illinois.

      The facility purchased certain of its equipment from our wholly-owned subsidiary, CalGen Equipment Finance. CalGen Equipment Finance’s interest in this installment sale contract was pledged as part of the offering of the original notes. The facility is designed to permit the installation of additional generating units.

      The facility obtains natural gas and oil from and exclusively sells power, on demand, to the Wisconsin Electric Power Company (“WEPCo.”). Natural gas is transported across Natural Gas Pipeline Company of America’s pipeline system. When needed, oil is transported by tanker truck. The facility is interconnected to Commonwealth Edison Company’s power transmission system. The electrical and gas interconnection facilities were designed to support expansion of the facility to a nominal capacity of 825 MW.

STRATEGY

      As a wholly-owned subsidiary of Calpine, our strategy is closely linked to Calpine’s overall strategy, which includes an objective to become North America’s most efficient, cost competitive and environmentally friendly power company. Our natural gas-fired facilities, which have been built from 1999 to the present, use modern technology for competitive, fuel-efficient operations to meet the most stringent environmental and regulatory requirements.

      We will continue to focus on maximizing the value of our power generation facilities through the following actions:

      We believe that our regional strengths and overall size provides greater dispatch flexibility and creates certain efficiencies for procurement, operations and maintenance. In addition, operating in different power markets limits our exposure to regulatory, fuel procurement and spark spread risks specific to certain markets. A substantial portion of our cash flow is based on revenues generated under the Fixed Price and Index Based Agreements which mitigates our exposure to natural gas and power price fluctuations.

GOVERNMENT REGULATION

      We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our energy generation facilities. Federal laws and regulations govern transactions by electric and gas utility companies, the types of fuel which may be utilized by an electricity generating plant, the type of energy which may be produced by such a plant, the ownership of a plant, and access to and service on the transmission grid. In most instances, public utilities that serve retail customers are subject to rate regulation by the state’s related utility regulatory commission. A state utility regulatory commission is often primarily responsible for determining whether a public utility may recover the costs of wholesale electricity purchases or other supply procurement-related activities through the retail rates the utility charges its customers. The state utility

regulatory commission may, from time to time, impose restrictions or limitations on the manner in which a public utility may transact with wholesale power sellers, such as independent power producers. Under certain circumstances where specific exemptions are otherwise unavailable, state utility regulatory commissions may have broad jurisdiction over non-utility electric power plants. Energy producing facilities also are subject to federal, state and local laws and administrative regulations which govern the emissions and other substances produced, discharged or disposed of by a plant and the geographical location, zoning, land use and operation of a plant. Applicable federal environmental laws typically have both state and local enforcement and implementation provisions. These environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy producing facility and that the facility then operate in compliance with such permits and approvals.

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

Federal Energy Regulation

      PURPA and the regulations adopted thereunder by FERC provide certain incentives for cogeneration facilities and small power production facilities, which satisfy FERC’s criteria for qualifying facility (“QF”) status. First, FERC’s implementing regulations exempt most QFs from the 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. 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 our facilities 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, our Decatur facility has temporarily been rendered incapable of meeting such requirements due to the loss of their 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.

      As a wholly-owned subsidiary of Calpine, we are subject to certain risks of losing our QF status. For example, if one of Calpine’s facilities (including a CalGen facility) 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 Calpine 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. If Calpine loses the PUHCA exemption, it could cause all of Calpine’s remaining QFs to lose their respective QF status, because no more than 50% of a QF’s equity may be owned by such electric utility holding companies. Loss of QF status may also trigger defaults under covenants to maintain QF status in the projects’ power sales agreements, steam

sales agreements and financing agreements and may result in termination, penalties or acceleration of indebtedness under such agreements.

      Under Section 32 of PUHCA, the owner of a facility can become an Exempt Wholesale Generator (“EWG”) if the owner is engaged directly, or indirectly through one or more affiliates, and exclusively in the business of owning and/or operating an eligible electric generating facility and all of the facility’s output is sold at wholesale for resale rather than directly to end users. As an EWG, the owner of the eligible generating facility is exempt from PUHCA even if the generating facility does not qualify as a QF. Therefore, another possible response to the loss or potential loss of QF status would be to apply to have the facility’s owner qualify as an EWG. However, assuming this changed status would be permissible under the terms of the applicable power sales agreement, rate approval from FERC would be required. In addition, the facility would be required to cease selling electricity to any retail electric customers (such as the thermal energy customer) to retain its EWG status.

      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.

      We have an ownership interest in 13 gas-fired power plants in operation and one gas-fired power plant 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; 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.

      Under the Federal Power Act (“FPA”), FERC is authorized to regulate the transmission of electric energy and the sale of electric energy at wholesale in interstate commerce. Unless otherwise exempt, any

person that owns or operates facilities used for such purposes is a public utility subject to FERC jurisdiction. FERC regulation under the FPA includes approval of the disposition of FERC-jurisdictional utility property, authorization of the issuance of securities by public utilities, regulation of the rates, terms and conditions for the transmission or sale of electric energy at wholesale in interstate commerce, the regulation of interlocking directorates, and the imposition of a uniform system of accounts and reporting requirements for public utilities.

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

      Many of our generating projects are or will be operated as QFs and therefore are or will be exempt from FERC regulation under the FPA. However, our Decatur facility will be an EWG, which is or will be subject to FERC jurisdiction under the FPA. Several of our facilities have 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.

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

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

Western Energy Markets

      There was significant price volatility in both wholesale electricity and gas markets in the Western United States for much of calendar year 2000 and extending through the second quarter of 2001. Due to a number of factors, including drier than expected weather, which led to lower than normal hydro-electric capacity in California and the Northwestern United States, inadequate natural gas pipeline and electric generation capacity to meet higher than anticipated energy demand in the region, the inability of the California utilities to manage their exposure to such price volatility due to regulatory and financial constraints, and evolving market structures in California, prices for electricity and natural gas were much higher than anticipated. A number of federal and state investigations and proceedings were commenced to address the crisis.

      There are currently a number of proceedings pending at FERC which were initiated as a direct result of the price levels and volatility in the energy markets in the Western United States during this period. Many of these proceedings were initiated by buyers of wholesale electricity seeking refunds for purchases made during this period or the reduction of price terms in contracts entered into at this time. Calpine has been a party to some of these proceedings. As part of certain proceedings, 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.

      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 our facilities are either QFs or EWGs, none are currently subject to such regulation. However, states may also assert jurisdiction over the sitting and construction of electricity generating facilities including QFs and EWGs. In California, for example, the PUC has been required by statute to adopt and enforce maintenance and operation standards for generating facilities “located in the state,” including EWGs but excluding QFs, for the purpose of ensuring their reliable operation. The adopted standards are now in effect.

      State PUCs also have jurisdiction over the transportation of natural gas by local distribution companies (“LDCs”). Each state’s regulatory laws are somewhat different; however, all generally require the LDC to obtain approval from the PUC for the construction of facilities and transportation services if the LDCs

generally applicable tariffs do not cover the proposed transaction. LDC rates are usually subject to continuing PUC oversight.

Environmental Regulations

      The construction and operation of 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.

      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.

      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 we are in material compliance with applicable discharge requirements of the Clean 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.

      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.

      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.

EMPLOYEES

      As of December 31, 2004 and 2003, we had no employees of our own. See Item  I. Business, Company Overview for relationships with affiliated companies, which supply services to the Company.

SUMMARY OF KEY EVENTS

Finance

      On March 23, 2004, CalGen, formerly Calpine Construction Finance Company II, LLC (“CCFC II”), completed its offering of secured term loans and secured notes. As expected, we realized net total proceeds from the offerings (after payment of transaction fees and expenses, including the fee payable to Morgan Stanley in connection with an Index Hedge) of approximately $2.4 billion. The offerings included:

      The secured term loans and secured notes described above in each case are secured, 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 security and none of the indebtedness is guaranteed by Calpine. Net proceeds from the offerings were used to repay amounts outstanding under the $2.5 billion CCFC II revolving construction credit facility (the “Construction Facility”), which was scheduled to mature in November 2004, and to pay fees and transaction costs associated with the refinancing. Concurrently with this refinancing, we amended and restated the CCFC II credit facility (as amended and restated, the “Revolving Credit Facility”) to reduce the commitments under the facility to $200.0 million and extend its maturity to March 2007. Interest under the Revolving Credit Facility equals LIBOR plus 350 basis points (or, at our election, the Base Rate plus 250 basis points). Outstanding indebtedness and letters of credit under the newly issued notes and term loans at December 31, 2004 and at the refinancing date totaled approximately $190.0 and $1.9 million, respectively. Outstanding indebtedness and letters of credit under the Construction Facility at December 31, 2003 totaled approximately $2.3 billion. See “— Summary of Key Events” for additional information.

      Ratings of new issuances by CalGen and certain of its wholly-owned subsidiaries:

      Our principal executive office located in San Jose, California is provided by our parent, Calpine, and held by Calpine under leases that expire through 2014.

      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.”

      See Note 11 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.

      Not applicable.

PART II

      Calpine Generating Company, LLC’s membership units are all owned indirectly by Calpine Corporation.

Selected Consolidated Financial Data

Selected Operating Information

Executive Overview

      Calpine Generating Company, LLC (“CalGen”) is a Delaware limited liability company and an indirect wholly owned subsidiary of Calpine Corporation (“Calpine” or the “Parent”). We are engaged, through our subsidiaries, in the construction, ownership and operation of electric power generation facilities and the sale of energy, capacity and related products in the United States of America. We indirectly own 14 power generation facilities (the “projects” or “facilities”) that are expected to have an aggregate combined estimated peak capacity of 9,834 MW (nominal 8,425 MW without peaking capacity), including our Pastoria facility which is currently under construction. Our aggregate combined estimated peak capacity represents approximately 30.6% of Calpine’s 32,149 MW of aggregate estimated peak capacity in operation and under construction. Thirteen of our facilities are natural gas-fired combined cycle facilities, and our Zion facility is a natural gas-fired simple cycle facility. Thirteen of our facilities are currently operating and have an aggregate estimated peak capacity of 9,065 MW.

      Our revenues are generated from the sale of electrical capacity and energy together with a by product, steam, through a series of agreements with third parties and through the Fixed Price and Index Based Agreements with CES. In connection with our refinancing on March 23, 2004, we entered into the Fixed Price and Index Based Agreements with CES. Previously, CES had purchased most of the available capacity and energy of our facilities, including ancillary services and other generation-based products and services, at negotiated internal transfer prices agreed upon when the various facilities commenced operations. In addition, CES supplied substantially all fuel requirements to the facilities, also at negotiated internal transfer prices. Under the Fixed Price and Index Based Agreements, CES purchases a portion of our energy at a fixed price and all of our remaining energy (after sales pursuant to our third-party agreements) at floating prices based on day-ahead energy and gas prices. See Item 1. “Business — Principal Agreements.”

      On March 23, 2004, CalGen issued $2.4 billion in secured term loans and debt securities (the “2004 Refinancing”) to replace the $2.5 billion credit facility we entered into in October 2000 (the “Construction Facility”). The new debt securities were issued in various traunches and except for the Third Priority Secured Notes Due 2011, carry a floating interest rate based on LIBOR plus a spread. The Third Priority Secured Notes Due 2011 carry a fixed interest rate of 11.5%.

      Concurrently with the 2004 Refinancing, CalGen entered into an agreement for a $200 million revolving credit facility (the “Revolving Credit Facility”) with a group of banks led by The Bank of Nova Scotia and a $750 million unsecured subordinated working capital facility (the “Working Capital Facility”) with CalGen Holdings, Inc., our sole member. The working capital facility is guaranteed by Calpine and may only be drawn in limited circumstances. In addition, CalGen had previously received additional financing from Calpine in the form of subordinated debt (the “Subordinated Parent Debt”). Effective March 23, 2004, Calpine converted the Subordinated Parent Debt, totaling approximately $4.4 billion, to equity in a non-cash capital contribution.

Results of Operations

      Our revenues are generated from the following sources:

      Prior to the 2004 Refinancing, for those fuel contracts where the title of fuel did not transfer to CalGen, the related power sales agreements were accounted for as tolling agreements, and the associated fuel costs were presented as a reduction of the related power revenues. The new contracts executed with CES on March 23, 2004 are not considered to be tolling agreements since title to the gas transfers, and as such, the projects record gross revenue and fuel expense.

      On May 21, 2004 and September 17, 2004, Columbia Energy Center and Goldendale Energy Center, respectively, commenced commercial operations. The Columbia facility is a 455-megawatt combined cycle energy center located in Columbia, South Carolina. The Goldendale facility is a 271-megawatt combined-cycle energy center located in Goldendale, Washington. Assets associated with these two facilities were transferred from construction in progress to building, machinery and equipment upon completion and commencement of operations.

      The financial results discussed below reflect past performance of the projects that have commenced commercial operation and are not expected to be indicative of future results. As discussed above, in March

2004, we entered into new contractual arrangements that are expected to materially change our revenues and expenses for periods after such date. In addition, in the past, our business had been focused on the development and construction of power facilities. With the exception of the Pastoria facility, we have now completed development and construction of the facilities.

Year Ended December 31, 2004 compared to Year Ended December 31, 2003

(in millions, except for unit pricing information, percentages and MW volumes); in the comparative tables below, increases in revenue/income or decreases in expense (for favorable variances) are shown without brackets. Decreases in revenue/income or increase in expense (unfavorable variances are shown with brackets).

      Electricity and steam revenue increased as we completed construction and brought into operation the Goldendale and Columbia baseload power plants during September 2004 and May 2004, respectively, and brought into operation the expansion of the Morgan baseload power plant in January 2004. Electricity and steam revenue also increased as we completed construction and brought into operation the Morgan and Carville baseload power plants during July 2003 and June 2003, respectively, and brought into operation the expansion of the Decatur, Oneta and Zion baseload power plants all during June 2003. Average megawatts in operation of our consolidated plants increased by 25.2% to 8,084 MW while generation increased by 8.7% to 28,211 MW. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 39.7% in 2004 from 45.9% in 2003 primarily because of unattractive margins in the merchant market reflecting near-term over-supply conditions. Our projects in the Southeast experienced an average baseload capacity factor of 11.6% in 2004. The overall increase in revenue was due to an increase in generation combined with the increase in average pricing, which increased 38.4% as average realized electricity prices increased to $60.58/ MWh in 2004 from $43.91/ MWh in 2003, primarily because of the new contractual agreements in 2004 which were no longer tolling arrangements as in 2003.

      To manage forward exposure to price fluctuations, the Company entered into a three-year Index Hedge with Morgan Stanley Capital Group (“MSCG”). The Index Hedge provides for semi-annual payments to the Company if the aggregate spark spread amount calculated under the Index Hedge for any six-month period during the term of the Index Hedge is less than $50.0 million. No payments have been made under the Index Hedge to date. Realized loss on derivative instruments is accounted for in accordance with EITF 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” and represents the amortization of the excess of the amount paid for the Index Hedge over its internally calculated fair value at the date of purchase. Unrealized loss represents changes in the value of the Index Hedge.

      Plant operating expense increased as we completed construction and brought into operation the Goldendale and Columbia baseload power plants and brought into operation the expansion of the Morgan baseload power plant in 2004. Plant operating expense also increased as we completed construction and brought into operation the Morgan and Carville baseload power plants and brought into operation the expansion of the Decatur, Oneta and Zion baseload power plants in 2003. Expressed per MWh of generation, plant operating expense increased from $5.05/ MWh to $6.32/ MWh as we experienced a drop in the baseload capacity factor from 45.9% in 2003 to 39.7% in 2004.

      Purchased power expense decreased due to outages at our Channel and Corpus Christi facilities in 2003. Channel experienced a shorter outage in 2004.

      As noted above we completed construction and brought into operation the Goldendale and Columbia baseload power plants and brought into operation the expansion of the Morgan baseload power plant in 2004. Additionally, we completed construction and brought into operation the Morgan and Carville baseload power plants and brought into operation the expansion of the Decatur, Oneta and Zion baseload power plants in 2003. Our generation increased by 8.7% as a result. Fuel expense increased in 2004 due to this increase in gas-fired megawatt hours generated and because of a 40.8% increase in gas prices.

      Depreciation and amortization expense increased due to the additional capacity brought on line as explained above.

      Sales, general and administrative expense increased in 2004 due to the operation of new plants and increases in information technology costs and other administrative expenses. In addition, the increase is the result of increased accounting and related fees of $1.6 million associated with our refinancing in March 2004. Sales, general and administrative expense expressed per MWh of generation increased to $0.40/ MWh in 2004 from $0.22/MWh in 2003.

      In 2004, the Company terminated its long-term service agreement at Los Medanos resulting in a cancellation charge of $3.8 million. Calpine indemnifies the Company for all costs associated with the cancellation of these agreements.

      Interest expense, related party decreased primarily due to the refinancing which occurred in March 2004. At the time of this refinancing, the Subordinated Parent Debt was converted to equity by the Parent in a non-cash capital contribution. Partially offsetting the decrease in related party interest expense was an increase in third-party interest expense. This increase is primarily due to the CalGen project debt, which replaced the CCFCII revolving construction credit facility (the “Construction Facility”) in March 2004. This debt accrued interest at a weighted average of approximately 8.6% during 2004 compared with a weighted average interest rate of 2.6% on the Construction Facility. In addition, $11.0 million of the increase is due to the new plants entering commercial operations at which time capitalization of interest expense ceased and interest expense commenced.

      Interest income increased primarily at Columbia Energy Center where it increased by $1.1 million due to the origination of a note receivable in May 2004 with the steam host, Eastman. This increase was partially offset by a decrease of $0.6 million at Delta due to a decrease in cash balances that bear interest.

      Other expense, net increased primarily due to a $1.3 million increase in letter of credit fees at the Zion, Columbia and Decatur Energy Centers. This increase was partially offset by approximately $0.8 million of income related to the cancellation of a capacity contract at Corpus Christi.

Year Ended December 31, 2003 compared to Year Ended December 31, 2002 (in millions, except for unit pricing information, percentages and MW volumes); in the comparative tables below, increases in revenues/income or decreases in expense (favorable variance) are show without brackets. Decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets).

      Electricity and steam revenue increased as we completed construction and brought into operation the Morgan and Carville baseload power plants during July 2003 and June 2003, respectively, and brought into operation the expansion of the Decatur, Oneta and Zion baseload power plants all during June of 2003. Electricity and steam revenue also increased as we completed construction and brought into operation the Delta, Baytown, Freestone and Decatur baseload power plants all during June 2002 and brought into operation the Corpus Christi, Oneta and Zion baseload power plants during October 2002, July 2002 and July 2002, respectively. In addition, we brought into operation the expansion of the Channel baseload power plant during April of 2002. Average megawatts in operation of our consolidated plants increased by 111.7% to 6,459 MW while generation increased by 58.7% to 25,959 MW. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 45.9% in 2003 from 61.2% in 2002 primarily due to our increased merchant operating capacity, mostly in the Southeast market where spot market spark spreads were unattractive, especially during off-peak hours, due to near-term oversupply. Average realized electricity prices increased to $43.91/ MWh in 2003 from $32.78/ MWh in 2002.

      Plant operating expense increased as we completed construction and brought into operation the Morgan and Carville baseload power plants and brought into operation the expansion of the Decatur, Oneta, Zion, Delta, Baytown, Freestone and Decatur baseload power plants in 2002. Plant operating expense also increased as we brought into operation the Corpus Christi, Oneta and Zion baseload power plants in 2002 and brought into operation the expansion of the Channel baseload power plant in 2002. Expressed per MWh of generation, plant operating expense increased from $4.90/ MWh to $5.05/ MWh as we experienced a drop in the baseload capacity factor from 61.2% in 2002 to 45.9% in 2003.

      Purchased power expense increased due to outages at our Channel and Corpus Christi facilities in 2003. There were no such outages in 2002.

      Fuel expense increased as we completed construction and brought into operation the Morgan and Carville baseload power plants and brought into operation the expansion of the Decatur, Oneta, Zion, Delta, Baytown, Freestone and Decatur baseload power plants in 2003. Fuel expense also increased as we brought into operation the Corpus Christi, Oneta and Zion baseload power plants in 2002 and brought into operation the expansion of the Channel baseload power plant in 2002. Fuel expense increased in 2003, due to an overall 58.7% increase in gas-fired megawatt hours generated and 34.0% higher prices.

      Depreciation and amortization expense increased as we completed construction and brought into operation additional capacity, as explained above.

      In March 2002, we recorded a $115.1 million charge in connection with the restructuring of various turbine agreements. The restructuring included adjusting timing of turbine deliveries, payment schedules and the cancellation of some orders. There were no charges of this nature in 2003.

      Sales, general and administrative expense increased in 2003 due to the operation of new plants and increases in information technology costs and plant administrative expenses. Sales, general and administrative expense expressed per MWh of generation increased to $0.22/ MWh in 2003 from $0.20/ MWh in 2002.

      Interest expense increased primarily due to the new plants entering commercial operations at which time capitalization of interest expense ceased and interest expense commenced.

      The increase is primarily due to higher cash balances at the Delta facility in 2003.

      Other expense during 2002 is comprised primarily of $1.5 million relating to costs incurred at the Baytown facility. There were no significant charges of this nature in 2003.

Liquidity and Capital Resources

      Prior to the issuance of our secured term loans and secured notes on March 23, 2004, our primary sources of liquidity were cash flows from operations, borrowing capacity under the $2.5 billion Construction Facility and subordinated borrowings from our parent.

      The Construction Facility was established in October 2000 with a consortium of banks and was scheduled to mature in November 2004. As of December 31, 2003, we had $2.2 billion in borrowings and $53.2 million in letters of credit outstanding under this facility. The Construction Facility was repaid and terminated on March 23, 2004 in connection with the issuance of our secured term loans and secured notes.

      The Subordinated Parent Debt was evidenced by a note agreement dated January 1, 2002 and bore interest at 8.75% per annum. At December 31, 2003, the outstanding balance was $4.6 billion. Under the debt subordination agreement, interest payments to the Parent were not permissible until all senior debt was repaid. Accordingly, the interest on the Subordinated Parent Debt has been treated as a non-cash transaction and has been added back to net income for purposes of computing cash flows from operations in the accompanying statements of cash flows. Effective March 23, 2004, and in connection with the 2004 Refinancing, the Parent transferred the Subordinated Parent Debt balance, which included accrued interest, totaling $4.4 billion, to equity as a non-cash capital contribution.

      On March 23, 2004, we completed an offering of secured term loans and secured notes totaling $2.4 billion. Net proceeds from the offerings were used to repay amounts outstanding under the Construction Facility and to pay fees and transaction costs associated with the refinancing. The new secured term loans and debt securities were issued in various traunches and, except for the Third Priority Secured Notes Due 2011, carry a floating interest rate based on LIBOR plus a spread. The Third Priority Secured Notes Due 2011 carry a fixed interest rate of 11.5%.

      Concurrent with the 2004 Refinancing, we entered into an agreement with a group of banks led by The Bank of Nova Scotia for a $200.0 million revolving credit facility (the “Revolving Credit Facility”). This three-year facility is available for specified working capital purposes, capital expenditures to complete the Pastoria facility and for letters of credit. All amounts outstanding under the Revolving Credit Facility will bear interest at either (i) the Base Rate plus 250 basis points, or (ii) at LIBOR plus 350 basis points. At December 31, 2004, there were no outstanding borrowings under the facility. At December 31, 2004, we had approximately $190.0 million in letters of credit outstanding under this credit facility to support fuel purchases and other operational activities.

      The Company also entered into a $750.0 million unsecured subordinated working capital facility (the “Working Capital Facility”) with CalGen Holdings, Inc., our sole member, which is guaranteed by Calpine. Under the Working Capital Facility, the Company may borrow funds only for specific purposes including claims under its business interruption insurance with respect to any of the facilities or a delay in the start up of the Pastoria facility; losses incurred as a result of uninsured force majeure events; claims for liquidated damages against third party contractors with respect to the Goldendale and Pastoria facilities and spark spread diminution after expiration of the three-year Index Hedge agreement with Morgan Stanley Capital Group.

Borrowings under the Working Capital Facility will bear interest at LIBOR plus 4.0% and interest will be payable annually in arrears and will mature in 2019. At December 31, 2004, there were no outstanding borrowings under the Working Capital Facility.

      To manage forward exposure to price fluctuations, we entered into the Index Hedge. The Index Hedge provides for semi-annual payments to us equal to the amount, if any, that the aggregate spark spread amount calculated under the Index Based Agreement, in each six-month period, falls below $50.0 million. We paid $45.0 million for the Index Hedge, which is in place through April 1, 2007. No payments have been made under the Index Hedge to date.

      Historically, our funding requirements related primarily to the construction of our facilities. With the completion of the Columbia Energy Center and the Goldendale Energy Center in 2004, all of our facilities are operational except for Pastoria, which is expected to commence operations of phase I and phase II in May 2005 and June 2005, respectively. We expect to have sufficient cash flow from operations and borrowings available under our credit facilities to satisfy all obligations under our outstanding indebtedness, and to fund anticipated capital expenditures and working capital requirements for the next twelve months. On December 31, 2004, our liquidity totaled approximately $75 million. This includes cash and cash equivalents on hand of approximately $65 million and $10 million of borrowing capacity under our Revolving Credit Facility. Additionally, as explained above, we have $700 million of borrowing capacity under our Working Capital Facility for specific permitted purposes.

      Cash Flow Activities — The following table summarizes our cash flow activities for the periods indicated:

      Operating activities for the year ended December 31, 2004 provided net cash of $278.6 million, compared with $161.6 million and $133.4 million for the same periods in 2003 and 2002, respectively. The increase in operating cash flow in 2004 compared with 2003 primarily relates to the completion and commencement of operations of the Columbia and Goldendale facilities. In addition, the Morgan and Carville facilities, as well as the expansion of Decatur, Oneta and Zion, went operational in 2003 and were generating operating cash flows for the entire year in 2004, opposed to only a partial year in 2003. These additional generations, in addition to favorable contracts executed in connection with our 2004 Refinancing, resulted in an increase in operating cash flows from increased gross profit and positive changes in our working capital during 2004. This was partially offset by higher interest cost from third-party debt. The increase in operating cash flow in 2003 compared with 2002 primarily relates to the completion and commencement of operations of the Morgan and Carville facilities, and the expansion of Decatur, Oneta and Zion during 2003.

      Investing activities for the year ended December 31, 2004, consumed net cash of $195.6 million, compared with $584.1 million and $1,570.9 million in the same period of 2003 and 2002, respectively. In all periods capital expenditures for new construction of plants represent the majority of investing cash outflows. The decrease between periods is due to the completion of construction of several facilities during 2003 and 2004.

      Financing activities for the year ended December 31, 2004, used net cash of $58.1 million, compared with financing activities providing $436.5 million and $1.4 billion in the same period in 2003 and 2002, respectively.

Current year cash outflows are primarily the result of refinancing transactions, repayments of Subordinated Parent Debt and financing costs. In the same period of 2003 and 2002, financing inflows were comprised primarily of borrowings under the Subordinated Parent Debt.

      Letter of Credit Facilities — At December 31, 2004, we had approximately $190.0 million in letters of credit outstanding under our $200 million revolving credit facility to support fuel purchases and other operational activities. At December 31, 2003, we had approximately $53.2 million in letters of credit outstanding under our revolving credit facility primarily to support the development and construction of our facilities.

      Working Capital — At December 31, 2004, we had working capital (current assets less current liabilities) of approximately $1.5 million, compared to a working capital deficit of approximately $2.0 billion at December 31, 2003. The working capital deficit was primarily due to the classification as a current liability of the outstanding project financing balance of $2.2 billion, which was successfully refinanced in March 2004.

      Capital Expenditures and Sources — Our estimated capital expenditures for 2005 include approximately $74.2 million in construction costs required to complete the Pastoria facility. We also expect to make capital expenditures in 2005 with respect to operations and maintenance, including major maintenance, of approximately $23.6 million. We expect to fund these expenditures through cash on hand and operating cash flow, or potentially from borrowings under our revolving credit facility.

      Distributions to Sole Member — Under the indentures governing the notes, we are generally permitted to make distributions to CalGen Holdings, our sole member, out of excess cash flow generated by operations, provided that cumulative cash flow is positive and that no default or event of default exists and there are no amounts outstanding under our new working capital facility. We expect that all distributable collections (after the payment of operating expenses, debt service and deposits to the reserve accounts) will be distributed to our sole member, as permitted. No such distributions were made in 2004.

      Capital Availability — Under the indentures governing the notes, our ability to borrow additional indebtedness is severely limited. If a need for capital does arise, either because our business changes or because the sources on which we are depending are not available, we may not be able to obtain such capital under the indentures governing the notes or on terms that are attractive to us.

      Performance Indicators — We believe the following factors are important in assessing our ability to continue to fund our growth in the capital markets: (a) various interest coverage ratios; (b) our credit and debt ratings by the rating agencies; (c) our anticipated capital requirements over the coming quarters and years; (d) the profitability of our operations; (e) the non-Generally Accepted Accounting Principles (“GAAP”) financial measures and other performance metrics discussed in “Performance Metrics” below; (f) our cash balances and remaining capacity under existing revolving credit construction and general purpose credit facilities; (g) compliance with covenants in existing debt facilities; (h) progress in raising new or replacement capital; and (i) the stability of future contractual cash flows.

      Off-Balance Sheet Commitments — In accordance with Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 13, “Accounting for Leases,” and SFAS No. 98, “Accounting for Leases; Sale-Leaseback Transactions Involving Real Estate; Sales-Type Leases of Real Estate; Definition of the Lease Term; Initial Direct Costs of Direct Financing Lease — An Amendment of FASB Statements No. 13, 66, and 91 and a Rescission of FASB Statement No. 26 and Technical Bulletin No. 79-11,” our operating leases are not reflected on our balance sheet. All counterparties in these transactions are third parties that are unrelated to us. See Note 11 of the Notes to Consolidated Financial Statements for the future minimum lease payments under our operating leases.

      Compliance with Covenants — Some of 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. Any failure to comply could give holders

of debt the right to accelerate the maturity of all debt outstanding thereunder if the default was not cured or waived. As of and for the year ended December 31, 2004, we were in compliance with our covenants.

      Contractual Obligations — Our contractual obligations as of December 31, 2004, are as follows (in thousands):

      The amounts included above for purchase obligations include the minimum requirements under contract. Agreements that we can cancel without significant cancellation fees are excluded.

Performance Metrics

      In understanding our business, we believe that certain operational non-GAAP financial metrics are particularly important. These are described below:

      Total deliveries of power. We generate power which is sold to CES and third parties, and steam which is primarily sold to third-party hosts. These sales are recorded as electricity and steam revenue. The volume in MWh for power is a key indicator of our level of generation activity.

      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 megawatt hours generated by our power plants (excluding peakers) by the product of multiplying (b) the weighted average megawatts in operation during the period by (c) the total hours in the period. The 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 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 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. We calculate the all-in realized electric price per MWh generated by dividing (a) the sum of adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues, plus realized gain or (loss) on the Index Hedge plus other revenue related to the Index Hedge by (b) total generated MWh in the period.

      Average cost of natural gas expressed in dollars per millions of Btu’s of fuel consumed. The fuel costs for our gas-fired power plants are a function of the prices we pay for fuel purchased from 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 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. 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.

      The table below shows the operating performance metrics discussed above.

Financial Market Risks

      Debt Financing — Certain debt instruments may affect us adversely because of changes in market conditions. In connection with our offering on March 23, 2004, we issued approximately $2.4 billion in new debt. Interest on substantially all of these debt securities is based on LIBOR plus a spread. Significant LIBOR increases could have a negative impact on our future interest expense. In addition, borrowings under our Revolving Credit Facility and our Working Capital Facility carry an interest rate based on LIBOR plus a spread.

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