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Calpine Corp – ‘10-K’ for 12/31/03

On:  Wednesday, 3/24/04, at 9:50pm ET   ·   As of:  3/25/04   ·   For:  12/31/03   ·   Accession #:  891618-4-798   ·   File #:  1-12079

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 3/25/04  Calpine Corp                      10-K       12/31/03   35:7.2M                                   Bowne - Palo Alto/FA

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML   3.19M 
 2: EX-4.14.3   Instrument Defining the Rights of Security Holders     6     27K 
 3: EX-4.14.4   Instrument Defining the Rights of Security Holders     7     36K 
 4: EX-4.16     Instrument Defining the Rights of Security Holders   104    507K 
 5: EX-4.17.1   Instrument Defining the Rights of Security Holders    98    474K 
 6: EX-4.17.2   Instrument Defining the Rights of Security Holders    17     91K 
 7: EX-4.19     Instrument Defining the Rights of Security Holders   160    719K 
 8: EX-4.20     Instrument Defining the Rights of Security Holders   164    722K 
 9: EX-4.21     Instrument Defining the Rights of Security Holders   181    789K 
10: EX-10.1.1.2  Material Contract                                   188    707K 
17: EX-10.1.10.2  Material Contract                                    4     24K 
11: EX-10.1.2.6  Material Contract                                    20     37K 
12: EX-10.1.2.7  Material Contract                                    17     40K 
13: EX-10.1.2.8  Material Contract                                     2     16K 
14: EX-10.1.2.9  Material Contract                                    23     33K 
18: EX-10.1.25  Material Contract                                     28    115K 
15: EX-10.1.7.2  Material Contract                                     6     25K 
16: EX-10.1.8.2  Material Contract                                     4     22K 
19: EX-10.2.2.3  Material Contract                                    28     38K 
20: EX-10.2.2.4  Material Contract                                    45     71K 
21: EX-10.2.3   Material Contract                                    170    635K 
22: EX-10.2.4   Material Contract                                    171    639K 
23: EX-10.3.1   Material Contract                                     54    147K 
24: EX-10.3.7   Material Contract                                      6     28K 
25: EX-12.1     Statement re: Computation of Ratios                    1     14K 
26: EX-21.1     Subsidiaries of the Registrant                         8     42K 
27: EX-23.1     Consent of Experts or Counsel                          1     13K 
28: EX-23.2     Consent of Experts or Counsel                          1     12K 
29: EX-23.3     Consent of Experts or Counsel                          1     12K 
30: EX-23.4     Consent of Experts or Counsel                          1     11K 
31: EX-31.1     Certification per Sarbanes-Oxley Act (Section 302)     2±    15K 
32: EX-31.2     Certification per Sarbanes-Oxley Act (Section 302)     2±    15K 
33: EX-32.1     Certification per Sarbanes-Oxley Act (Section 906)     1     12K 
34: EX-99.1     Miscellaneous Exhibit                                 15     78K 
35: EX-99.2     Miscellaneous Exhibit                                  1     12K 


10-K   —   Annual Report
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Table of Contents
"Part I
"Item 1
"Business
"Item 2
"Properties
"Item 3
"Legal Proceedings
"Item 4
"Submission of Matters to a Vote of Security Holders
"Part Ii
"Item 5
"Market for Registrant's Common Equity and Related Stockholder Matters
"Item 6
"Selected Financial Data
"Item 7
"Management's Discussion and Analysis of Financial Condition and Results of Operations
"Item 7A
"Quantitative and Qualitative Disclosures About Market Risk
"Item 8
"Financial Statements and Supplementary Data
"Item 9
"Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
"Item 9A
"Controls and Procedures
"Part Iii
"Item 10
"Directors and Executive Officers of the Registrant
"Item 11
"Executive Compensation
"Item 12
"Security Ownership of Certain Beneficial Owners and Management
"Item 13
"Certain Relationships and Related Transactions
"Item 14
"Principal Accounting Fees and Services
"Part Iv
"Item 15
"Exhibits, Financial Statement Schedules, and Reports on Form 8-K
"Signatures and Power of Attorney
"Index to Consolidated Financial Statements and Other Information
"The Company

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Table of Contents



UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


Form 10-K

     
(Mark One)
   
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2003
 
or
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from           to
Commission file number: 1-12079


Calpine Corporation

(A Delaware Corporation)

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

50 West San Fernando Street

San Jose, California 95113
Telephone: (408) 995-5115

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

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

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

None

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

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

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

      Aggregate market value of the common equity held by non-affiliates of the registrant as of June 30, 2003, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $2.5 billion. Common stock outstanding as of March 19, 2004: 415,736,644 shares.

DOCUMENTS INCORPORATED BY REFERENCE

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

     
(1) Designated portions of the Proxy Statement relating to the 2004 Annual Meeting of Shareholders
  Part III (Items 10, 11, 12, 13 and 14)





FORM 10-K

ANNUAL REPORT
For the Year Ended December 31, 2003

TABLE OF CONTENTS

             
Page

 PART I
   Business     1  
   Properties     41  
   Legal Proceedings     45  
   Submission of Matters to a Vote of Security Holders     50  
 
 PART II
   Market for Registrant’s Common Equity and Related Stockholder Matters     51  
   Selected Financial Data     53  
   Management’s Discussion and Analysis of Financial Condition and Results of Operations     56  
   Quantitative and Qualitative Disclosures About Market Risk     104  
   Financial Statements and Supplementary Data     104  
   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     105  
   Controls and Procedures     105  
 
 PART III
   Directors and Executive Officers of the Registrant     106  
   Executive Compensation     106  
   Security Ownership of Certain Beneficial Owners and Management     106  
   Certain Relationships and Related Transactions     107  
   Principal Accounting Fees and Services     107  
 
 PART IV
   Exhibits, Financial Statement Schedules, and Reports on Form 8-K     107  
 Signatures and Power of Attorney     121  
 Index to Consolidated Financial Statements and Other Information     F-1  
 EXHIBIT 4.14.3
 EXHIBIT 4.14.4
 EXHIBIT 4.16
 EXHIBIT 4.17.1
 EXHIBIT 4.17.2
 EXHIBIT 4.19
 EXHIBIT 4.20
 EXHIBIT 4.21
 EXHIBIT 10.1.1.2
 EXHIBIT 10.1.2.6
 EXHIBIT 10.1.2.7
 EXHIBIT 10.1.2.8
 EXHIBIT 10.1.2.9
 EXHIBIT 10.1.7.2
 EXHIBIT 10.1.8.2
 EXHIBIT 10.1.10.2
 EXHIBIT 10.1.25
 EXHIBIT 10.2.2.3
 EXHIBIT 10.2.2.4
 EXHIBIT 10.2.3
 EXHIBIT 10.2.4
 EXHIBIT 10.3.1
 EXHIBIT 10.3.7
 EXHIBIT 12.1
 EXHIBIT 21.1
 EXHIBIT 23.1
 EXHIBIT 23.2
 EXHIBIT 23.3
 EXHIBIT 23.4
 EXHIBIT 31.1
 EXHIBIT 31.2
 EXHIBIT 32.1
 EXHIBIT 99.1
 EXHIBIT 99.2


Table of Contents

PART I

 
Item 1. Business

      In addition to historical information, this report contains forward-looking statements. Such statements include those concerning Calpine Corporation’s (“the Company’s”) 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 on a transitional basis 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 produce reduced demand for power, (v) systemic economic slowdowns, which can adversely affect consumption of power by businesses and consumers, (vi) commercial operations of new plants that may be delayed or prevented because of various development and construction risks, such as a failure to obtain the necessary permits to operate, failure of third-party contractors to perform their contractual obligations or failure to obtain project financing on acceptable terms, (vii) cost estimates are preliminary and actual costs may be higher than estimated, (viii) a competitor’s development of lower-cost power plants or of a lower cost means of operating a fleet of power plants, (ix) risks associated with marketing and selling power from power plants in the evolving energy market, (x) the successful exploitation of an oil or gas resource that ultimately depends upon the geology of the resource, the total amount and costs to develop recoverable reserves, and legal title, regulatory, gas administration, marketing and operational factors relating to the extraction of natural gas, (xi) our estimates of oil and gas reserves may not be accurate, (xii) the effects on the Company’s business resulting from reduced liquidity in the trading and power generation industry, (xiii) the Company’s ability to access the capital markets on attractive terms or at all, (xiv) sources and uses of cash are estimates based on current expectations; actual sources may be lower and actual uses may be higher than estimated, (xv) the direct or indirect effects on the Company’s business of a lowering of its credit rating (or actions it may take in response to changing credit rating criteria) including increased collateral requirements, refusal by the Company’s current or potential counterparties to enter into transactions with it and its inability to obtain credit or capital in desired amounts or on favorable terms, (xvi) possible future claims, litigation and enforcement actions pertaining to the foregoing, (xvii) effects of the application of regulations, including changes in regulations or the interpretation thereof; or (xviii) other risks as identified herein. Current information set forth in this filing has been updated to March 24, 2004, and Calpine undertakes no duty to further update this information. All other information in this filing is presented as of the specific date noted and has not been updated since that time.

      We file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You can request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 450 Fifth Street, N.W., Washington, D.C. 20549-1004. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible through the Internet at that website.

      Our reports on Forms 10-K, 10-Q and 8-K, and amendments to those reports, are available for download, free of charge, as soon as reasonably practicable after these reports are filed with the SEC, at our website at www.calpine.com. The content of our website is not a part of this report. You may request a copy of our SEC filings, at no cost to you, by writing or telephoning us at: Calpine Corporation, 50 West San Fernando Street, San Jose, California 95113, attention: Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery.

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OVERVIEW

      We are a leading North American power company engaged in the development, construction, ownership and operation of power generation facilities and the sale of electricity predominantly in the United States, but also in Canada and the United Kingdom. We were established as a corporation in 1984. We focus on two efficient and clean types of power generation technologies, natural gas-fired combustion turbine and geothermal. We currently lease and operate the largest fleet of geothermal power plants in the world, and have increased our operating portfolio of clean burning natural gas power plants by 17,201 megawatts (“MW”) over the past three years. We have a proven track record in the development of new power facilities and may make acquisitions as opportunities arise. We also have in place an experienced gas production and management team to give us a broad range of fuel sourcing options, and we own over 800 billion cubic feet equivalent (“Bcfe”) of net proved natural gas reserves located in Alberta, Canada as well as in the Sacramento Basin, Rockies and Gulf Coast regions of the United States. Additionally, we own a 25% interest in Calpine Natural Gas Trust, which has proved reserves of approximately 72 Bcfe (18 Bcfe net to Calpine’s equity interest). We are currently capable of producing, net to Calpine’s interest, 215 million cubic feet equivalent (“MMcfe”) of natural gas per day, and Calpine Natural Gas Trust (“CNG Trust”) total production, net of royalties, is currently 25 MMcfe (6.2 MMcfe net to Calpine’s interest) of natural gas per day. Calpine has the first right to purchase all of CNG Trust’s production at market prices.

      Currently, we own interests in 87 power plants having a net capacity of 22,206 MW. We also have 12 gas-fired projects and 1 project expansion currently under construction collectively having a net capacity of 7,685 MW. The completion of the new projects currently under construction would give us interests in 99 power plants located in 22 states, 3 Canadian provinces and the United Kingdom, and we will own net capacity of 29,891 MW. Of this total generating capacity, 97% will be attributable to gas-fired facilities and 3% will be attributable to geothermal facilities.

      Calpine Energy Services, L.P. (“CES”) provides the trading and risk management services needed to schedule power sales and to ensure fuel is delivered to the power plants on time to meet delivery requirements and to manage and optimize the value of our physical power generation and gas production assets.

      Complementing CES’s activities, we have recently reorganized our marketing and sales organization to better meet the needs of our growing list of wholesale and large retail customers. We focus our sales activities on load serving entities such as local utilities, municipalities and cooperatives, as well as on large-scale end users such as industrial and commercial companies. See a further discussion of our marketing and sales organization in “Strategy” below. As a general goal, we seek to have 65% of our available capacity sold under long-term contracts or hedged by our risk management group. Currently we have 52% of our available capacity sold or hedged for 2004.

      We continue to strengthen our system operations management and information technology capabilities to enhance the economic performance of our portfolio of assets in our major markets and to provide load-following and other ancillary services to our customers. These operational optimization systems, combined with our sales, marketing and risk management capabilities, enable us to add value to traditional commodity products in ways that not all competitors can match.

      Our construction organization has assembled what we believe to be the best-in-industry team of construction management professionals to ensure that our projects are built using our standard design specifications reflecting our exacting operational standards. We have established strategic alliances with leading equipment manufacturers for gas turbine generators, steam turbine generators and heat recovery steam generators and other key equipment. We will continue to leverage these capabilities and relationships to ensure that our power plants are completed on time and are the best built and lowest cost energy facilities possible.

      With a vision of enhancing the performance of our modern portfolio of gas-fired power plants and lowering our replacement parts maintenance costs, we have fostered the development of our wholly owned subsidiary, Power Systems Manufacturing (“PSM”), to design and manufacture high performance combustion system and turbine blade parts. PSM manufactures new vanes, blades, combustors and other replacement

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parts for the industrial gas turbine industry. It offers a wide range of Low Emissions Combustion systems and advanced airfoils designed to be transparently compatible for retrofitting or replacing existing combustion systems or components operating in General Electric and Siemens Westinghouse turbines.

      In 2003 we expanded our energy services capabilities with the acquisition of Netherlands-based Thomassen Turbine Systems (“TTS”). TTS complements Calpine’s broad array of energy services by selling combustion turbine component parts and repair services worldwide.

      We established Calpine Power Services (“CPS”) to offer the unique skills that we have honed in building and operating our own power plants to third party customers. We are now selling, and have received contracts for, various engineering, procurement, construction management, plant commissioning, operations, and maintenance services through CPS.

      As we build the nation’s most modern and efficient portfolio of gas-fired generation assets and establish our low-cost position, our integrated operations and skill sets have allowed us to weather a multi-year downturn in the North American energy industry. We have demonstrated the flexibility to adapt to fundamental market changes. Specifically, we responded to the market downturn by reducing capital expenditures, selling or monetizing various gas, power, and contractual assets, restructuring our equipment procurement obligations, and reorganizing to reflect our transition from a development focused company to an operations focused company. These efforts have allowed us to cut costs and raise capital while positioning ourselves to continue our quest to be the power company in North America with the largest market capitalization. See Note 25 of the Notes to Consolidated Financial Statements for Operating Segments Disclosures.

THE MARKET

      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 $260 billion of electricity sales in 2003 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, 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 2003 totaled approximately 720,000 MW, while summer generating capacity in 2003 totaled approximately 912,000 MW, creating a peak summer reserve margin of 192,000 MW, or 26.7%. Historically, utility reserve margins have been targeted to be 15% above peak demand to provide for load forecasting errors, scheduled and unscheduled plant outages and local area grid protection. Some regions have margins well in excess of the 15% target range, while other regions remain short of ideal reserve margins. The estimated 192,000 MW of reserve margin in 2003 compares to an estimated 120,000 MW in 2002. The increase is due in large part to the start-up of new low-cost, clean-burning, gas-fired power plants. 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 51% of the electricity generated in the U.S. is fueled by coal, 20% by nuclear sources, 17% 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 installing a significant amount of costly emission control devices. This activity could cause

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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 two years accompanied by a decrease in liquidity in the energy trading markets, and a general lessening of enthusiasm for investing in energy companies. In 2003 while electricity prices generally increased, the cost of natural gas grew at an even greater rate, further depressing spark spreads (the margin between the value of the electricity sold and the cost of fuel to generate that electricity) from the low levels in 2002.

      Based on strength in residential and commercial demand, overall consumption of electricity was estimated to have grown by approximately 2.9% in 2004 through February compared to the same period in 2003, according to Edison Electric Institute (“EEI”) published data. The growth rate for calendar year 2003 was 1.8%. The growth rate in supply is 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 rising to over $6.40 per million btu (“MMbtu”) in the first quarter of 2004, compared to an average of approximately $5.50 per MMbtu in 2003 and $3 per MMbtu in 2002. 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 improve and capital markets regain their interest in helping to repower America with clean, highly efficient energy technologies.

STRATEGY

      Our vision is to become North America’s largest power company and ultimately become a major worldwide power company. In achieving our corporate strategic objectives, the number one priority for our company is maintaining the highest level of integrity in all of our endeavors. We have posted on our website (www.calpine.com <http://www.calpine.com>) our Code of Conduct applicable to all employees, including our principal executive officer, principal financial officer and principal accounting officer. We intend to satisfy the disclosure requirement under Item 10 of Form 8-K regarding any amendments to or waivers from the Code of Conduct by posting such information on our website at www.calpine.com.

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

Near-Term Objectives

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

  •  Continue to focus on our liquidity position as our second highest priority after integrity;
 
  •  Complete our 2004 refinancing program, which includes Calpine Generating Company, LLC (“CalGen”) (see “Recent Developments” for more information), the remaining outstanding 4% Convertible Senior Notes Due 2006, and the Remarketable Term Income Deferrable Equity Securities (“HIGH TIDES”);
 
  •  Complete our current construction program and start construction of new projects in strategic locations only when financing is available and attractive returns are expected;
 
  •  Continue to lower operating and overhead costs per megawatt hour produced and improve operating performance with an increasingly efficient power plant fleet; and
 
  •  Utilize our industry-leading marketing and sales capabilities to selectively increase our power contract portfolio.

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Longer-Term Objectives

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

      Our “system approach” refers to our ability to cluster our standardized, highly efficient power generation assets within a given energy market and to sell the energy from that system of power plants, rather than using “unit specific” marketing contracts. The clustering of standardized power generation assets allows for significant economies of scale to be achieved. Specifically, construction costs, supply chain activities such as inventory and warehousing costs, labor, and fuel procurement costs can all be reduced with this approach. The choice to focus on highly efficient and clean technologies reduces our fuel costs, a major expense when operating power plants. Furthermore, our lower-than-market heat rate (high efficiency advantage) provides us a competitive advantage in times of rising fuel prices, and our systems approach to fuel purchases reduces imbalance charges when a plant is forced out of service. Finally, utilizing our system approach in a sales contract allows us to provide power to a customer from whichever plant in the system is most economical at a given period of time. In addition, the operation of plants can be coordinated when increasing or decreasing power output throughout the day to enhance overall system efficiency, thereby enhancing the heat rate advantage already enjoyed by the plants. In total, this approach lays a foundation for a sustainable competitive cost advantage in operating our plants.

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

      Recent trends confirm that both buyers and sellers of power benefit from signing long-term power contracts and avoiding the severe volatility often seen with power prices. The trend towards signing long-term contracts is creating opportunities for companies, such as ours, that own power plants and gas reserves to negotiate directly with buyers (end users and load serving entities) that need power, thereby skipping the trading middlemen, many of whom have now exited the market.

      Our marketing and sales organization is dedicated to serving wholesale and industrial customers with reliable, cost-effective electricity and a full range of services. The organization offers customers: (1) wholesale bulk energy; (2) firm supply energy; (3) fully dispatchable energy; (4) full service requirements energy; (5) renewable energy; (6) energy scheduling services; (7) engineering, construction, operations and maintenance services; and (8) critical reliability energy services. Our physical, financial and intellectual assets and our generating facilities that are pooled into unique energy centers in key markets, enable us to create customizable energy solutions for our customers. For example, our wholesale energy products deliver power when, where and in the capacity our customers need. Our power marketing experience gives us the know-how to structure innovative deals that meet our customers’ particular requirements. Our highly tailored, yet understandable energy contracts help customers offset pricing risk and other variables. Our “Virtual Power Plant” projects provide customers with an energy resource that is reliable and flexible. They give customers all of the advantages of owning and operating their own plants without many of the risks, by gaining access to a portfolio of highly efficient generation assets and by implementing our IT solutions to allow power to be dispatched as needed. Marketing and Sales is pursuing 21,000 MW of active opportunities with 135 customers across the United States. This customer base includes municipalities, cooperatives, investor owned utilities, industrial customers and commercial customers across the United States.

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      Our financing strategy includes an objective to achieve and maintain an investment grade credit and bond rating from the major rating agencies within the next several years. We intend to employ various approaches for extending or refinancing existing credit facilities and for financing new plants, with a goal of retaining maximum system operating flexibility. The availability of capital at attractive terms will be a key requirement to enable us to develop and construct new plants. We have adjusted to recent market conditions by taking near-term actions focused on liquidity. We have been very successful throughout 2003 and early 2004 at selling certain less strategically important assets, monetizing several contracts, establishing a Canadian natural gas trust to raise funds based on selling to the trust certain of our oil and gas assets, buying back our debt, issuing convertible and non-convertible senior notes, and raising capital with non-recourse project financing.

COMPETITION

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

      Development and Construction. In this activity, we face competition from independent power producers (“IPPs”), non-regulated subsidiaries of utilities, and increasingly from regulated utilities and large end-users of electricity. Furthermore, the regulatory and community pressures against locating a power plant at a specific site can often be substantial, causing months or years of delays. Similarly, the construction process is highly competitive as there are only a few primary suppliers of key gas turbine, steam turbine and heat recovery steam generator equipment used in a state of the art gas turbine power plant. Additionally, we have seen periods of strong competition with respect to securing the best construction personnel and contractors.

      Power Plant Operations. The competitive landscape faced by our power plant operations organization consists of a patchwork of highly competitive and highly regulated market environments. This patchwork has been caused by an uneven transition to deregulated markets across the various states and provinces of North America. For example, in markets where there is open competition, our merchant capacity (that which has not been sold under a long-term contract) competes directly on a real time basis with all other sources of electricity such as nuclear, coal, oil, gas-fired, and renewable units owned by others. However, there are other markets where the local incumbent utility still predominantly uses its own supply to meet its own demand before dispatching competitively provided power. Each of these markets offers a unique and challenging competitive environment.

      Asset Acquisition and Divestiture. The recent downturn in the electricity industry has prompted many companies to sell assets to improve their financial positions. In addition, the postponement of plans for construction of new power plants is also creating a competitive market for the sale of excess equipment. Although there is a strong buyers market at the moment, relatively few assets are changing hands due to the gap between sellers’ and buyers’ price expectations.

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

      Power Marketing and Sales. Power marketing and sales generally includes all those activities associated with identifying customers, negotiating, and selling energy and service contracts to load-serving entities and large scale industrial and retail end-users. Specifically, there has been a trend for trading companies that served a “middle man” role to exit the industry for financial and business model reasons. Instead, power generators are increasingly selling long-term power directly to load serving entities (utilities, municipalities,

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cooperatives) and large scale end-users, thereby reducing the high levels of price volatility witnessed in the industry since 2001.

RECENT DEVELOPMENTS

      Financing. On January 9, 2004, one of the initial purchasers of the 4 3/4% Contingent Convertible Senior Notes Due 2023 exercised in full its option to purchase an additional $250.0 million of these notes. The notes are convertible into cash and into shares of Calpine common stock upon the occurrence of certain contingencies at an initial conversion price of $6.50 per share, which represents a 38% premium over the New York Stock Exchange closing price of $4.71 per share on November 6, 2003, the date the notes were originally priced. Upon conversion of the notes, we will deliver par value in cash and any additional value in Calpine shares.

      On January 15, 2004, we completed the sale of our 50-percent undivided interest in the 545-megawatt Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the Lower Colorado River Authority (“LCRA”). Under the terms of the agreement, we received a cash payment of $146.8 million and recorded a gain before taxes of $35.5 million in January 2004. In addition, CES entered into a tolling agreement with LCRA to purchase 250 megawatts of electricity through December 31, 2004. At December 31, 2003, we classified our undivided interest in the Lost Pines facility as “held for sale” and reclassified all earnings to discontinued operations (see Note 10 of the Notes to Consolidated Financial Statements).

      In January 2004 CES concluded a settlement with the Commodity Futures Trading Commission (“CFTC”) related to the CFTC’s finding of inaccurate reporting of certain natural gas trading information by one former CES employee during 2001 and 2002. Neither Calpine nor CES benefited from the trader’s conduct. Under the terms of the agreement, CES paid a civil monetary penalty in the amount of $1.5 million without admitting or denying the findings in the CFTC’s order.

      Subsequent to December 31, 2003, we repurchased approximately $177.0 million in principal amount of our outstanding 4% Convertible Senior Notes Due 2006 (“2006 Convertible Senior Notes”) that can be put to us in exchange for approximately $176.0 million in cash. Additionally, on February 9, 2004, we made a cash tender offer, which expired on March 9, 2004, for all of the outstanding 2006 Convertible Senior Notes at a price of par plus accrued interest. On March 10, 2004, we paid an aggregate amount of $412.8 million for the tendered 2006 Convertible Senior Notes which included accrued interest of $3.4 million. Currently, 2006 Convertible Senior Notes in the aggregate principal amount of $73.7 million remain outstanding.

      On February 2, 2004, a class action complaint was filed in the United States District Court for the Southern District of New York against CES and others. The complaint alleges unlawful manipulation of natural gas futures and options contracts traded on NYMEX during the period January 21, 2000 through December 31, 2002. The causes of action alleged are fraudulent concealment and violations of the Commodity Exchange Act, and CES anticipates filing a motion to dismiss the complaint. This complaint was filed as a related action to another consolidated class action complaint involving numerous other defendants. The court has not granted class action certification for any of the matters at this time.

      On February 18, 2004, one of our wholly owned subsidiaries closed on the sale of natural gas properties to Calpine Natural Gas Trust (“CNG Trust”). We received consideration of Cdn$40.5 million (US$30.9 million). We hold 25% of the outstanding trust units of CNG Trust and account for the investment using the equity method.

      On February 18, 2004, we entered into an agreement to purchase the Brazos Valley Power Plant in Fort Bend County, Texas, for approximately $175.0 million in cash, subject to certain adjustments. We expect to acquire the 570-megawatt, natural gas-fired facility with the net proceeds from the sale of Lost Pines 1 and cash on hand. The special purpose companies that own Brazos Valley are indirectly owned by the consortium of banks that had provided construction financing for the power plant and had taken possession of the plant from the original developer in 2003. Upon completion of the transaction, Brazos Valley will become part of the collateral package for the Calpine Construction Finance Company, L.P. (“CCFC I”) First Priority Secured Institutional Term Loans Due 2009 and Second Priority Senior Secured Floating Rate Notes  Due 2011.

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      On February 20, 2004, we completed a $250.0 million, non-recourse project financing for the 600-megawatt Rocky Mountain Energy Center. A consortium of banks financed the construction of the plant at a rate of LIBOR plus 250 basis points. Upon commercial operation of the Rocky Mountain Energy Center in the summer of 2004, the banks will provide a three-year term-loan facility.

      On March 23, 2004, our wholly owned subsidiary 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) in the approximate amount of $2.3 billion. The offerings included:

         
Amount Description Interest Rate



$235.0 million
  First Priority Secured Floating Rate Notes Due 2009   LIBOR plus 375 basis points
$640.0 million
  Second Priority Secured Floating Rate Notes Due 2010   LIBOR plus 575 basis points
$680.0 million
  Third Priority Secured Floating Rate Notes Due 2011   LIBOR plus 900 basis points
$150.0 million
  Third Priority Secured Notes Due 2011   11.50%
$600.0 million
  First Priority Secured Term Loans due 2009   LIBOR plus 375 basis points(1)
$100.0 million
  Second Priority Secured Term Loans due 2010   LIBOR plus 575 basis points(2)


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

      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 refinance amounts outstanding under the $2.5 billion CCFC II revolving construction credit facility, which was scheduled to mature in November 2004, and to pay fees and transaction costs associated with the refinancing. Concurrently with this refinancing, we amended and restated the CCFC II credit facility (as amended and restated, the “CalGen revolving credit facility”) to reduce the commitments under the facility to $200.0 million and extend its maturity to March 2007. Interest under the CalGen revolving facility equals LIBOR plus 350 basis points (or, at our election, the Base Rate plus 250 basis points). Outstanding indebtedness and letters of credit at December 31, 2003, and at the refinancing date, under the CCFC II credit facility totaled approximately $2.3 billion and 2.4 billion, respectively.

      See “— Summary of Key Activities” for 2003 developments.

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DESCRIPTION OF POWER GENERATION FACILITIES

(CALPINE POWER GEOGRAPHICAL MAP)

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      At March 24, 2004, we had ownership or lease interests in 87 operating power generation facilities representing 22,206 megawatts of net capacity. Of these projects, 68 are gas-fired power plants with a net capacity of 21,356 megawatts, and 19 are geothermal power generation facilities with a net capacity of 850 megawatts. We also have 12 gas-fired projects and 1 project expansion currently under construction with a net capacity of 7,685 megawatts. We expect to complete construction of advanced development projects. The timing of the completion of these projects will be based on market fundamentals and when our return on investment criteria are expected to be met, and financing is available on attractive terms. Each of the power generation facilities currently in operation produces electricity for sale to a utility, other third-party end user, or to an intermediary such as a trading company. Thermal energy produced by the gas-fired cogeneration facilities is sold to industrial and governmental users.

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

      Upon completion of our projects under construction, we will provide operating and maintenance services for 97 of the 99 power plants in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps, gas fields, gathering systems and gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operating and maintenance manuals for each power generation facility that we operate. As a facility develops an operating history, we analyze its operation and may modify or upgrade equipment or adjust operating procedures or maintenance measures to enhance the facility’s reliability or profitability. These services are sometimes performed for third parties under the terms of an operating and maintenance agreement pursuant to which we are generally reimbursed for certain costs, paid an annual operating fee and may also be paid an incentive fee based on the performance of the facility. The fees payable to us may be subordinated to any lease payments or debt service obligations of financing for the project.

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

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

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

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

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      Set forth below is certain information regarding our operating power plants and plants under construction as of March 24, 2004.

                                             
Megawatts

Calpine Net
With Calpine Net Interest
Number Baseload Peaking Interest with
of Plants Capacity Capacity Baseload Peaking





In operation
                                       
 
Geothermal power plants
    19       850       850       850       850  
 
Gas-fired power plants
    68       18,941       23,347       17,104       21,356  
Under construction
                                       
 
New facilities
    12       6,057       7,028       6,057       7,028  
 
Expansion project
          438       657       438       657  
     
     
     
     
     
 
   
Total
    99       26,286       31,882       24,449       29,891  
     
     
     
     
     
 

Operating Power Plants

                                                           
Calpine Net
Country, With Calpine Net Interest
US State Baseload Peaking Calpine Interest With Total 2003
or Can. Capacity Capacity Interest Baseload Peaking Generation
Power Plant Province (MW) (MW) Percentage (MW) (MW) MWh(1)








Geothermal Power Plants
                                                       
Sonoma County (12 plants)
    CA       512.0       512.0       100.0 %     512.0       512.0       4,022,608  
Lake County (2 plants)
    CA       145.0       145.0       100.0 %     145.0       145.0       1,202,592  
Calistoga
    CA       73.0       73.0       100.0 %     73.0       73.0       615,960  
Sonoma
    CA       53.0       53.0       100.0 %     53.0       53.0       350,317  
West Ford Flat
    CA       27.0       27.0       100.0 %     27.0       27.0       237,225  
Bear Canyon
    CA       20.0       20.0       100.0 %     20.0       20.0       157,028  
Aidlin
    CA       20.0       20.0       100.0 %     20.0       20.0       146,448  
             
     
             
     
     
 
 
Total Geothermal Power Plants (19)
            850.0       850.0               850.0       850.0       6,732,178  
             
     
             
     
     
 
Gas-Fired Power Plants
                                                       
Saltend Energy Centre
    UK       1,200.0       1,200.0       100.0 %     1,200.0       1,200.0       9,095,929  
Acadia Energy Center
    LA       1,080.0       1,160.0       50.0 %     540.0       580.0       2,259,944  
Oneta Energy Center
    OK       994.0       994.0       100.0 %     994.0       994.0       611,992  
Freestone Energy Center
    TX       1,022.0       1,022.0       100.0 %     1,022.0       1,022.0       4,930,706  
Broad River Energy Center
    SC             840.0       100.0 %           840.0       206,078  
Delta Energy Center
    CA       799.0       882.0       100.0 %     799.0       882.0       5,440,349  
Baytown Energy Center
    TX       742.0       830.0       100.0 %     742.0       830.0       5,045,069  
Morgan Energy Center
    AL       722.0       852.0       100.0 %     722.0       852.0       95,457  
Pasadena Power Plant
    TX       751.0       787.0       100.0 %     751.0       787.0       4,080,123  
Magic Valley Generating Station
    TX       700.0       751.0       100.0 %     700.0       751.0       2,683,274  
Decatur Energy Center
    AL       692.0       838.0       100.0 %     692.0       838.0       429,220  
Hermiston Power Project
    OR       546.0       642.0       100.0 %     546.0       642.0       2,615,001  
Channel Energy Center
    TX       527.0       574.0       100.0 %     527.0       574.0       3,144,479  
Aries Power Project
    MO       516.0       591.0       50.0 %     258.0       295.5       791,065  
South Point Energy Center
    AZ       520.0       530.0       100.0 %     520.0       530.0       2,944,368  
Los Medanos Energy Center
    CA       497.0       566.0       100.0 %     497.0       566.0       3,344,159  
Sutter Energy Center
    CA       535.0       543.0       100.0 %     535.0       543.0       3,234,514  
Lost Pines 1 Power Project(2)
    TX                   0.0 %                 3,101,574  

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Calpine Net
Country, With Calpine Net Interest
US State Baseload Peaking Calpine Interest With Total 2003
or Can. Capacity Capacity Interest Baseload Peaking Generation
Power Plant Province (MW) (MW) Percentage (MW) (MW) MWh(1)








Ontelaunee Energy Center
    PA       561.0       584.0       100.0 %     561.0       584.0       863,253  
Westbrook Energy Center
    ME       528.0       528.0       100.0 %     528.0       528.0       3,307,527  
Corpus Christi Energy Center
    TX       414.0       537.0       100.0 %     414.0       537.0       1,854,208  
Hidalgo Energy Center
    TX       502.0       502.0       78.5 %     394.1       394.1       1,743,360  
Carville Energy Center
    LA       455.0       531.0       100.0 %     455.0       531.0       1,697,994  
Texas City Power Plant
    TX       465.0       471.0       100.0 %     465.0       471.0       2,446,410  
RockGen Energy Center
    WI             460.0       100.0 %           460.0       223,977  
Deer Park Energy Center, Phases 1 and 1a
    TX       354.0       362.0       100.0 %     354.0       362.0       1,823,311  
Clear Lake Power Plant
    TX       335.0       412.0       100.0 %     335.0       412.0       1,918,603  
Zion Energy Center
    IL             513.0       100.0 %           513.0       74,781  
Santa Rosa Energy Center
    FL       250.0       250.0       100.0 %     250.0       250.0       22,706  
Blue Spruce Energy Center
    CO             300.0       100.0 %           300.0       290,410  
Calgary Energy Centre
    AB       250.0       300.0       30.0 %     75.0       90.0       731,449  
Rumford Power Plant
    ME       237.0       251.0       100.0 %     237.0       251.0       1,547,533  
Hog Bayou Energy Center
    AL       246.6       246.6       100.0 %     246.6       246.6       122,762  
Tiverton Power Plant
    RI       240.0       240.0       100.0 %     240.0       240.0       1,689,698  
Gordonsville Power Plant(3)
    VA                   0.0 %                 155,402  
Island Cogeneration
    BC       230.0       230.0       30.0 %     69.0       69.0       1,487,028  
Pine Bluff Energy Center
    AR       213.3       213.3       100.0 %     213.3       213.3       1,503,735  
Los Esteros Critical Energy Center
    CA             180.0       100.0 %           180.0       164,251  
Morris Power Plant
    IL       155.0       177.5       86.0 %     134.0       146.4       484,971  
Dighton Power Plant
    MA       162.0       168.0       100.0 %     162.0       168.0       449,781  
Androscoggin Energy Center
    ME       160.0       160.0       32.3 %     51.7       51.7       796,172  
Auburndale Power Plant
    FL       143.0       153.0       30.0 %     42.9       45.9       1,094,795  
Grays Ferry Power Plant
    PA       143.0       148.0       40.0 %     57.2       59.2       765,609  
Gilroy Peaking Energy Center
    CA             135.0       100.0 %           135.0       69,338  
Gilroy Power Plant
    CA       112.0       131.0       100.0 %     112.0       131.0       184,603  
Pryor Power Plant
    OK       109.0       124.0       80.0 %     87.2       99.2       331,035  
Sumas Power Plant
    WA       120.0       122.0       0.1 %     0.1       0.1       943,343  
Parlin Power Plant
    NJ       89.0       118.0       80.0 %     71.2       94.4       84,825  
Auburndale Peaking Energy Center
    FL             115.0       100.0 %           115.0       36,067  
King City Power Plant
    CA       103.0       115.0       40.0 %     41.2       46.0       928,484  
Kennedy International Airport Power Plant (“KIAC”)
    NY       95.0       105.0       100.0 %     95.0       105.0       581,122  
Bethpage Power Plant
    NY       52.0       53.7       100.0 %     52.0       53.7       423,104  
Bethpage Peaking Energy Center
    NY             48.0       100.0 %           48.0       97,005  
Pittsburg Power Plant
    CA       64.0       71.0       100.0 %     64.0       71.0       239,991  
Newark Power Plant
    NJ       47.0       58.0       80.0 %     37.6       46.4       376,911  
Greenleaf 1 Power Plant
    CA       50.0       50.0       100.0 %     50.0       50.0       388,939  
Greenleaf 2 Power Plant
    CA       50.0       50.0       100.0 %     50.0       50.0       363,320  
Whitby Cogeneration
    ON       50.0       50.0       15.0 %     7.5       7.5       344,648  
King City Peaking Energy Center
    CA             45.0       100.0 %           45.0       17,436  
Yuba City Energy Center
    CA             45.0       100.0 %           45.0       19,078  

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Calpine Net
Country, With Calpine Net Interest
US State Baseload Peaking Calpine Interest With Total 2003
or Can. Capacity Capacity Interest Baseload Peaking Generation
Power Plant Province (MW) (MW) Percentage (MW) (MW) MWh(1)








Feather River Energy Center
    CA             45.0       100.0 %           45.0       15,745  
Creed Energy Center
    CA             45.0       100.0 %           45.0       14,266  
Lambie Energy Center
    CA             45.0       100.0 %           45.0       14,140  
Wolfskill Energy Center
    CA             45.0       100.0 %           45.0       16,820  
Goose Haven Energy Center
    CA             45.0       100.0 %           45.0       13,524  
Riverview Energy Center
    CA             45.0       100.0 %           45.0       15,693  
Stony Brook Power Plant
    NY       36.0       40.0       100.0 %     36.0       40.0       346,971  
Watsonville Power Plant
    CA       29.0       30.0       100.0 %     29.0       30.0       211,755  
Agnews Power Plant
    CA       26.5       28.6       100.0 %     26.5       28.6       219,153  
Philadelphia Water Project
    PA       22.0       23.0       66.4 %     14.6       15.3        
             
     
             
     
     
 
 
Total Gas-Fired Power Plants (68)
            18,941.4       23,346.7               17,103.7       21,355.9       87,610,343  
             
     
             
     
     
 
 
Total Operating Power Plants (87)
            19,791.4       24,196.7               17,953.7       22,205.9       94,342,521  
             
     
             
     
     
 
Consolidated Projects including plants with operating leases
            17,722.4       21,965.7               17,039.2       21,211.9          
Equity (Unconsolidated) Projects
            2,069.0       2,231.0               914.5       994.0          


(1)  Generation MWh is shown here as 100% of each plant’s gross generation in megawatt hours (“MWh”).
 
(2)  This facility is presented here only to state the facility’s generation in MWh for 2003. This facility was sold in January 2004. See Note 10 of the Notes to Consolidated Financial Statements for more information regarding the sale of this facility.
 
(3)  This facility is presented here only to state the facility’s generation in MWh through November 26, 2003, the date it was sold. See Note 7 of the Notes to Consolidated Financial Statements for more information regarding the sale of this facility.

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Projects Under Construction (All gas-fired)

                                                   
Calpine Net
Country, With Calpine Net Interest
US State Baseload Peaking Calpine Interest With
or Can. Capacity Capacity Interest Baseload Peaking
Power Plant Province (MW) (MW) Percentage (MW) (MW)







Projects Under Construction
                                               
Deer Park Energy Center*
    TX       438.0       657.0       100.0 %     438.0       657.0  
Hillabee Energy Center
    AL       710.0       770.0       100.0 %     710.0       770.0  
Pastoria Energy Center
    CA       759.0       769.0       100.0 %     759.0       769.0  
Fremont Energy Center
    OH       550.0       700.0       100.0 %     550.0       700.0  
Columbia Energy Center
    SC       464.0       641.0       100.0 %     464.0       641.0  
Riverside Energy Center
    WI       518.0       602.0       100.0 %     518.0       602.0  
Metcalf Energy Center
    CA       556.0       602.0       100.0 %     556.0       602.0  
Osprey Energy Center
    FL       530.0       609.0       100.0 %     530.0       609.0  
Washington Parish Energy Center
    LA       509.0       565.0       100.0 %     509.0       565.0  
Otay Mesa Energy Center
    CA       510.0       593.0       100.0 %     510.0       593.0  
Rocky Mountain Energy Center
    CO       479.0       601.0       100.0 %     479.0       601.0  
Goldendale Energy Center
    WA       237.0       271.0       100.0 %     237.0       271.0  
Fox Energy Center
    WI       235.0       305.0       100.0 %     235.0       305.0  
             
     
             
     
 
 
Total Projects Under Construction
            6,495.0       7,685               6,495.0       7,685.0  
             
     
             
     
 


Expansion project.

ACQUISITIONS OF POWER PROJECTS AND PROJECTS UNDER CONSTRUCTION

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

      As indicated in the Strategy Section, our development and acquisition activities have been greatly scaled back, for the indefinite future, to focus on liquidity and operational priorities.

Acquisitions

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

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      Although our preference is to own 100% of the power plants we acquire or develop, there are situations when we take less than 100% ownership. Reasons why we may take less than a 100% interest in a power plant may include, but are not limited to: (a) our acquisitions of other independent power producers such as Cogeneration Corporation of America in 1999 and SkyGen Energy LLC in 2000 in which minority interest projects were included in the portfolio of assets owned by the acquired entities (Grays Ferry Power Plant (40% now owned by Calpine) and Androscoggin Energy Center (32.3% now owned by Calpine), respectively); (b) opportunities to co-invest with non-regulated subsidiaries of regulated electric utilities, which under PURPA are restricted to 50% ownership of cogeneration qualifying facilities; and (c) opportunities to invest in merchant power projects with partners who bring marketing, funding, permitting or other resources that add value to a project, for example, Acadia Energy Center in Louisiana (50% owned by Calpine and 50% owned by Cleco Midstream Resources, an affiliate of Cleco Corporation). None of our equity investment projects have nominal carrying values as a result of material recurring losses. Further, there is no history of impairment in any of these investments.

Projects Under Construction

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

      Deer Park Energy Center. In March 2001 we announced plans to build, own and operate a 1,019-megawatt, natural gas-fired energy center in Deer Park, Texas. The Deer Park Energy Center supplies steam to Shell Chemical Company, and electric power generated at the facility is sold on the wholesale market. Construction began in mid-2001. The first and second phases of the project entered commercial operation in June 2003 and the final phase is expected to begin commercial operation in June 2004.

      Hillabee Energy Center. On February 24, 2000, we announced plans to build, own and operate the Hillabee Energy Center, a 770-megawatt, natural gas-fired cogeneration facility in Tallapoosa County, Alabama. Construction began in mid-2001, and we expect commercial operation of the facility will commence in spring 2006.

      Pastoria Energy Center. 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 the fall of 2004 for phase one and in mid-2005 for phase two.

      Fremont Energy Center. On May 23, 2000, we announced plans to build, own and operate the Fremont Energy Center, a 700-megawatt natural gas-fired electricity generating facility to be located near Fremont, Ohio. Commercial operation is expected to commence in the summer of 2006.

      Columbia Energy Center. On September 25, 2001, we announced plans to construct the new 641-megawatt Columbia Energy Center, a natural gas-fired cogeneration facility located on property leased from Voridian (formerly Eastman Chemical Company) in Calhoun County, S.C. The facility will sell electricity to the wholesale power market and will supply thermal energy to Voridian. Commercial operation is expected to commence in the spring of 2004.

      Riverside Energy Center. On December 18, 2002, we announced that construction of the Riverside Energy Center, a 602-megawatt natural gas-fired electricity generating facility had begun in Beloit, Wisconsin. We anticipate commercial operation of the facility to begin in the summer of 2004.

      Metcalf Energy Center. On April 30, 1999, we submitted an Application for Certification with the California Energy Commission (“CEC”) to build, own and operate the Metcalf Energy Center, a 602-megawatt natural gas-fired electricity generating facility located in San Jose, California. The CEC permit was approved on September 21, 2001. Construction of the facility began in June 2002, and commercial operation is anticipated to commence in the summer of 2005.

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      Osprey Energy Center. On January 11, 2000, we announced plans to build, own and operate the Osprey Energy Center, a 609-megawatt, natural gas-fired cogeneration energy center near the city of Auburndale, Florida. Construction commenced in the fall 2001 and commercial operation of the facility is scheduled to begin in the spring of 2004. Upon commercial operation, the Osprey Energy Center will supply electric power to Tampa, Florida-based Seminole Electric Cooperative, Inc. for a period of 16 years.

      Washington Parish Energy Center. On January 26, 2001, we announced the acquisition of the development rights from Cogentrix, an independent power company based in North Carolina, for the 565-megawatt Washington Parish Energy Center, located near Bogalusa, Louisiana. We are managing construction of the facility, which began in January 2001, and will operate the facility when it enters commercial operation, which is anticipated to be in the summer of 2006.

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

      Rocky Mountain Energy Center. In August 2002 we commenced construction of the 601-megawatt, natural gas-fired Rocky Mountain Energy Center in Weld County, Colorado. We will sell the output of the facility to Public Service Co. of Colorado under the terms of a ten-year tolling agreement. Commercial operation of the facility is expected to commence in the summer of 2004.

      Goldendale Energy Center. In April 2001 we acquired the rights to develop a 271-megawatt combined-cycle energy center located in Goldendale, Washington. Construction of the Goldendale Energy Center began in the summer of 2001 and commercial operation is expected to commence in the summer of 2004. Energy generated by the facility will be sold directly into the Northwest Power Pool.

      Fox Energy Center. In 2003 we acquired the fully permitted 305-megawatt Fox Energy Center in Kaukauna, Wisconsin, which will be used to fulfill an existing contract with Wisconsin Public Service. Commercial operation is expected to begin in the summer of 2005.

OIL AND GAS PROPERTIES

      In 1997 we began an equity gas strategy to diversify the gas sources for our natural gas-fired power plants by purchasing Montis Niger, Inc., a gas production and pipeline company operating primarily in the Sacramento Basin in northern California. We currently supply the majority of the fuel requirements for the Greenleaf 1 and 2 Power Plants from these reserves. In October 1999, we purchased Sheridan Energy, Inc. (“Sheridan”), a natural gas exploration and production company operating in northern California and the Gulf Coast region. The Sheridan acquisition provided the initial management team and operational infrastructure to evaluate and acquire oil and gas reserves to keep pace with our growth in gas-fired power plants. In December 1999, we added Vintage Petroleum, Inc.’s interest in the Rio Vista Gas Unit and related areas, representing primarily natural gas reserves located in the Sacramento Basin in northern California. Sheridan was merged into Calpine in April 2000 and Calpine Natural Gas L.P. (“CNGLP”) was established to manage our oil and gas properties in the U.S. Additionally, we own a 25% interest in CNG Trust, which has proved reserves of approximately 72 Bcfe (18 Bcfe, net to Calpine’s equity interest). We are currently capable of producing, net to Calpine’s interest, 215 MMcfe of natural gas per day, and CNG Trust total production, net of royalties, is currently 25 MMcfe (6.2 MMcfe net to Calpine’s interest) of natural gas per day. Calpine has the first right to purchase all of CNG Trust’s production at market prices.

      The focus of the equity gas program has been on acquisitions in strategic markets where we are developing low-cost natural gas supplies and proprietary pipeline systems in support of our natural gas-fired power plants. In conjunction with these efforts we acquired various gas assets and gas companies in 2001 and

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2000. See Note 6 of the Notes to Consolidated Financial Statements for more information regarding the 2001 acquisitions.

      In 2002 and 2003 certain non-strategic divestments were completed to further focus operations on gas production and to enhance liquidity. These divestments are discussed in detail under Note 10 of the Notes to Consolidated Financial Statements.

      As a result of our oil and gas acquisition, divestment and drilling program activity, equity equivalent net production from continuing operations was approximately 260 MMcfe/day at December 31, 2003, enough to fuel approximately 2,300 megawatts of our power plant fleet, assuming an average capacity factor of 70%.

MARKETING, HEDGING, OPTIMIZATION, AND TRADING ACTIVITIES

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

      The hedging, balancing, and optimization activities that we engage in are directly related to exposures that arise from our ownership and operation of power plants and gas reserves and are designed to protect or enhance our “spark spread” (the difference between our fuel cost and the revenue we receive for our electric generation). In many of these transactions CES purchases and resells power and gas in contracts with third parties.

      We utilize derivatives, which are defined in Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” to include many physical commodity contracts and commodity financial instruments such as exchange-traded swaps and forward contracts, to optimize the returns that we are able to achieve from our power and gas assets. From time to time we have entered into contracts considered energy trading contracts under Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” However, our risk managers have low capital at risk and value at risk limits for energy trading, and our risk management policy limits, at any given time, our net sales of power to our generation capacity and limits our net purchases of gas to our fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133. The EITF reached a consensus under EITF Issue No. 02-3 that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. In addition we present on a net basis certain types of hedging, balancing and optimization revenues and costs of revenue under EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes’ As Defined in EITF Issue No. 02-3: “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 03-11”), which we adopted prospectively on October 1, 2003. See Item 7. “Management’s Discussion and Analysis — Impact of Recent Accounting Pronouncements” and Note 2 to the Consolidated Financial Statements for a discussion of the effects of adopting this standard.

      Following is a discussion of the types of electricity and gas hedging, balancing, optimization, and trading activities in which we engage.

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Electricity Transactions

  •  Electricity hedging transactions are entered into to reduce potential volatility in future results. An example of an electricity hedging transaction would be one in which we sell power at a fixed rate to allow us to predict the future revenues from our portfolio of generating plants. Hedging is a dynamic process; from time to time we adjust the extent to which our portfolio is hedged. An example of an electricity hedge adjusting transaction would be the purchase of power in the market to reduce the extent to which we had previously hedged our generation portfolio through fixed price power sales. To illustrate, suppose we had elected to hedge 65% of our portfolio of generation capacity for the following six months but then believed that prices for electricity were going to steadily move up during that same period. We might buy electricity on the open market to reduce our hedged position to, say, 50%. If electricity prices, do in fact increase, we might then sell electricity again to increase our hedged position back to the 65% level and generate additional margin.
 
  •  Electricity balancing activities are typically short-term in nature and are done to make sure that sales commitments to deliver power are fulfilled. An example of an electricity balancing transaction would be where one of our generating plants has an unscheduled outage so we buy replacement power to deliver to a customer to meet our sales commitment.
 
  •  Electricity optimization activity, also generally short-term in nature, is done to maximize our profit potential by executing the most profitable alternatives in the power markets. An example of an electricity optimization transaction would be fulfilling a power sales contract with power purchases from third parties instead of generating power when the market price for power is below the cost of generation. In all cases, optimization activity is associated with the operating flexibility in our systems of power plants, natural gas assets, and gas and power contracts. That flexibility provides us with alternatives to most profitably manage our portfolio.
 
  •  Electricity trading activities are done with the purpose of profiting from movement in commodity prices or to transact business with customers in market areas where we do not have generating assets. An example of an electricity trading contract would be where we buy and sell electricity, typically with trading company counterparties, solely to profit from electricity price movements. We have engaged in limited activity of this type to date in terms of earnings impact. All such activity is done by CES, mostly through short-term contracts. Another example of an electricity trading contract would be one in which we transact with customers in market areas where we do not have generating assets, generally to develop market experience and customer relations in areas where we expect to have generation assets in the future. We have done a small number of such transactions to date.

Natural Gas Transactions

  •  Gas hedging transactions are also entered into to reduce potential volatility in future results. An example of a gas hedging transaction would be where we purchase gas at a fixed rate to allow us to predict the future costs of fuel for our generating plants or conversely where we enter into a financial forward contract to essentially swap floating rate (indexed) gas for fixed price gas. Similar to electricity hedging, gas hedging is a dynamic process, and from time to time we adjust the extent to which our portfolio is hedged. To illustrate, suppose we had elected to hedge 65% of our gas requirements for our generation capacity for the next six months through fixed price gas purchases but then believed that prices for gas were going to steadily decline during that same period. We might sell fixed price gas on the open market to reduce our hedged gas position to 50%. If gas prices do in fact decrease, we might then buy fixed price gas again to increase our hedged position back to the 65% level and increase our margins.
 
  •  Gas balancing activities are typically short-term in nature and are done to ensure that purchase commitments for gas are adjusted for changes in production schedules. An example of a gas balancing transaction would be where one of our generating plants has an unscheduled outage so we sell the gas that we had purchased for that plant to a third party.

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  •  Gas optimization activities are also generally short-term in nature and are done to maximize our profit potential by executing the most profitable alternatives in the gas markets. An example of gas optimization is selling our gas supply, not generating power, and fulfilling power sales contracts with power purchases from third parties, instead of generating power when market gas prices spike relative to our gas supply cost.
 
  •  Gas trading activities are done with the purpose of profiting from movement in commodity prices. An example of gas trading contracts would be where we buy and sell gas, typically with a trading company counterparty, solely to profit from gas price movements or where we transact with customers in market areas where we do not have fuel consumption requirements. We have engaged in a limited level of this type of activity to date. All such activity is done by CES, mostly through short-term contracts.

      In some instances economic hedges may not be designated as hedges for accounting purposes. The accounting treatment of our various risk management and trading activities is governed by SFAS No. 133, EITF Issue No. 02-3, as discussed above, and EITF Issue No. 03-11 which we adopted on October 1, 2003, and is discussed further in Note 2 of the Notes to Consolidated Financial Statements. An example of an economic hedge that is not a hedge for accounting purposes would be a long-term fixed price electric sales contract that economically hedges us against the risk of falling electric prices, but which for accounting purposes is exempted from derivative accounting under SFAS No. 133 as a normal sale. For a further discussion of our derivative accounting methodology, see Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Application of Critical Accounting Policies.”

GOVERNMENT REGULATION

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

Federal Energy Regulation

 
PURPA

      The enactment of the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”), and the adoption of regulations thereunder by the Federal Energy Regulatory Commission (“FERC”) provided incentives for the development of cogeneration facilities and small power production facilities (those utilizing renewable fuels and having a capacity of less than 80 megawatts).

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      A domestic electricity generating project must be a Qualifying Facility (“QF”) under FERC regulations in order to take advantage of certain rate and regulatory incentives provided by PURPA. PURPA exempts owners of QFs from the Public Utility Holding Company Act of 1935, as amended (“PUHCA”), and exempts QFs from most provisions of the Federal Power Act (“FPA”) and, except under certain limited circumstances, state laws concerning rate or financial regulation. These exemptions are important to us and our competitors. We believe that each of the electricity-generating projects in which we own an interest and which operates as a QF power producer meets or will meet the requirements under PURPA necessary for QF status. In some cases our projects have temporarily been rendered incapable of meeting such requirements (due, for example, to the loss of a thermal host) and we have sought waivers of the applicable QF requirements from FERC. In the past FERC has been willing to issue such waivers (which typically are for a one-or two-year period) where it can be shown that the project is expected to be able to meet the applicable QF requirements at the end of the waiver period; however, we cannot provide assurance that such waivers will in every case be granted.

      PURPA provides two primary benefits to QFs. First, QFs generally are relieved of compliance with extensive federal and state regulations that control the financial structure of an electricity generating plant and the prices and terms on which electricity may be sold by the plant. Second, FERC’s regulations promulgated under PURPA 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. The term “avoided cost” is defined as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from QFs, such utility would generate for itself or purchase from another source. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates lower than the utilities’ avoided costs. While public utilities are not explicitly required by PURPA to enter into long-term power sales agreements, PURPA helped to create a regulatory environment in which it has been common for long-term agreements to be negotiated.

      In order to be a QF, a cogeneration facility must produce not only electricity, but also useful thermal energy for use in an industrial or commercial process for heating or cooling applications in certain proportions to the facility’s total energy output, and must meet certain energy efficiency standards. A geothermal facility may qualify as a QF if it produces less than 80 megawatts of electricity. Finally, a QF (including a geothermal QF or other qualifying small power producer) must not be controlled or more than 50% owned by one or more electric utilities or by most electric utility holding companies, or one or more subsidiaries of such a utility or holding company or any combination thereof.

      We endeavor to develop our projects, monitor compliance by the projects with applicable regulations and choose our customers in a manner which minimizes the risks of any project losing its QF status. Certain factors necessary to maintain QF status are, however, subject to the risk of events outside our control. For example, loss of a thermal energy customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a QF could cause the facility to fail requirements regarding the level of useful thermal energy output. Upon the occurrence of such an event, 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 this would be possible.

      If one of the facilities in which we have an interest should lose its status as a QF, the project would no longer be entitled to the exemptions from PUHCA and the FPA. This could also trigger certain rights of termination under the facility’s power sales agreement, could subject the facility to rate regulation as a public utility under the FPA and state law and could result in us inadvertently becoming an electric utility holding company by owning more than 10% of the voting securities of, or controlling, a facility that would no longer be exempt from PUHCA. This could cause all of our remaining projects to lose their qualifying status, because QFs may not be controlled or more than 50% 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 result in termination, penalties or acceleration of indebtedness under such agreements such that loss of status may be on a retroactive or a prospective basis.

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      Under the Energy Policy Act of 1992, if a facility can be qualified as an Exempt Wholesale Generator (“EWG”), meaning that all of its output is sold for resale rather than to end users, it will be exempt from PUHCA even if it does not qualify as a QF. Therefore, another response to the loss or potential loss of QF status would be to apply to have the project qualified 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 customers (such as the thermal energy customer) to retain its EWG status and could become subject to state regulation of sales of thermal energy. See Public Utility Holding Company Regulation.

      Currently, Congress is considering proposed legislation that would repeal PUHCA and amend PURPA by limiting its mandatory purchase obligation to existing contracts, in those regions of the country that are found to have competitive energy markets. In light of the circumstances in California, the Pacific Gas and Electric Company (“PG&E”) bankruptcy and the 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 domestic projects.

Public Utility Holding Company Regulation

      Under PUHCA, any corporation, partnership or other legal 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. 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 dealings of a registered holding company. Under PURPA, most QFs are not public utility companies 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, they have also resulted in increased competition by allowing utilities and their affiliates to develop such facilities which are not subject to the constraints of PUHCA.

Federal Natural Gas Transportation Regulation

      We have an ownership interest in 80 gas-fired power plants in operation or under construction. The cost of natural gas is ordinarily the largest expense of a gas-fired project and is critical to the project’s economics. The risks associated with using natural gas can include the need to arrange gathering, processing, extraction, blending, and storage, as well as transportation of the gas from great distances, including obtaining removal, export and import authority if the gas is transported from Canada; the possibility of interruption of the gas supply or transportation (depending on the quality of the gas reserves purchased or dedicated to the project, the financial and operating strength of the gas supplier, whether firm or non-firm transportation is purchased and the operations of the gas pipeline); and obligations to take a minimum quantity of gas and pay for it (i.e., take-and-pay obligations).

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

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Federal Power Act Regulation

      Under the 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 considered a public utility subject to FERC jurisdiction. FERC regulation under the FPA includes approval of the disposition of 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, 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 power marketers, EWGs and other non-traditional public utilities that lack market power. EWGs are regularly 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. Such action is intended to implement FERC’s policy to foster a more competitive wholesale power market.

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

Federal Open Access Electric Transmission Regulation

      In the summer of 1996 FERC issued Orders Nos. 888 and 889 ordering 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, were required to adopt the pro forma open access transmission tariff establishing terms of non-discriminatory transmission service, including generator interconnection service. Order No. 889 required transmission-owning utilities to publish information concerning the availability of transmission capacity and make such transmission capacity available on a non-discriminatory basis. 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 utilities. The interpretation and application of the requirements of Orders Nos. 888 and 889 continues to be refined through subsequent administrative proceedings at FERC. These orders have been subject to review, and have been affirmed, by the courts.

      In December 1999 FERC issued Order No. 2000, which requires jurisdictional transmission-owning utilities to enter into agreements with ISOs to operate their transmission systems or join a Regional Transmission Organization (“RTO”), which would likewise control the transmission facilities in a certain region. Order No. 2000 sets forth the basic governance terms for RTOs. To date, compliance by the transmission-owning utilities has been uneven and has met with political resistance on the part of the state governments and the state public utilities commissions in some regions of the country. The impact on our business of the implementation of Order No. 2000 and the development of RTOs cannot be predicted.

      In addition to its efforts in Order Nos. 888, 889, and 2000 and in creating RTOs, FERC has attempted to further refine and clarify the rights and obligations of owners and users of the interstate transmission grid in its Standard Market Design (“SMD”) and Interconnection rule-making proceedings. FERC’s intention under the SMD proceedings is to establish a set of standard rules, which could be adopted in the form of a revised tariff by transmission-owning utilities, addressing the manner in which transmission capacity would be allocated, how generation would be dispatched given transmission constraints, the coordination of transmission upgrades and the allocation of costs associated therewith, among other transmission-related issues. The SMD rule-making proceeding is pending currently. The timing of FERC’s issuance of a final order in this proceeding

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is uncertain and has been delayed due to political resistance on the part of the state governments and the state public utilities commissions in some regions in the country. The impact on our business due to the issuance of a final order in this proceeding is uncertain and cannot be predicted at this time.

      On July 24, 2003, FERC issued Order No. 2003 which is the final rule in the Interconnection rule-making proceeding. Order No. 2003 establishes uniform procedures for generator interconnection to the transmission grid, including the allocation of some of the costs associated with transmission system upgrades and special facilities required to interconnect the generator to the grid. Pursuant to Order No. 2003, transmission owners have been directed to make compliance filings with the FERC to implement the requirements of the order. The purpose of Order No. 2003 is to provide greater certainty and reduce costs associated with the interconnection of new generation facilities to the transmission grid.

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 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 volatility in the energy markets in the Western United States during this period. Many of these proceedings were initiated by buyers of wholesale electricity seeking refunds for purchases made during this period or the reduction of price terms in contracts entered into at this time. We have been a party to some of these proceedings. See Item 1. “Business — Risk Factors — California Power Market” and Item 3. “Legal Proceedings.” As part of certain proceedings, and as a result of its own investigations, FERC has ordered the implementation of certain measures for wholesale electricity markets in California and the Western United States, including, the implementation of price caps on the day ahead or real-time prices for electricity through September 30, 2002, and a continuing obligation of electricity generators to offer uncommitted generation capacity to the California Independent System Operator. FERC is continuing to investigate the causes of the price volatility in the Western United States during this period. It is uncertain at this time when these proceedings and investigations at FERC will conclude or what will be the final resolution thereof. See “— Risk Factors — California Power Market” below.

      Other federal and state governmental entities have and continue to conduct various investigations into the causes of the price volatility in the energy markets in the Western United States during this time. 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 pass through the expense associated with a power purchase agreement with an independent power producer to the utility’s retail customers. However, a regulatory commission under certain circumstances may disallow the full reimbursement to a utility for the cost 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

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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. States may assert jurisdiction over the siting and construction of electricity generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities.

      State PUCs also have jurisdiction over the transportation of natural gas by local distribution companies (“LDCs”). Each state’s regulatory laws are somewhat different; however, all generally require the LDC to obtain approval from the PUC for the construction of facilities and transportation services if the LDCs generally applicable tariffs do not cover the proposed transaction. LDC rates are usually subject to continuing PUC oversight. We own and operate numerous midstream assets in a number of states where we have plants and/or oil and gas production.

Regulation of Canadian Gas

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

Environmental Regulations

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

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

Clean Air Act

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

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Clean Water Act

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

Oil Pollution Act of 1990

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

Safe Drinking Water Act

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

Resource Conservation and Recovery Act

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

Comprehensive Environmental Response, Compensation, and Liability Act

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

Canadian Environmental, Health and Safety Regulations

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

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Regulation of U.S. Gas

      The U.S. natural gas industry is subject to extensive regulation by federal, state and local authorities. Calpine holds onshore and offshore federal leases involving the U.S. Dept. of Interior (Bureau of Land Management, Bureau of Indian Affairs and the Minerals Management Service). At the federal level, various federal rules, regulations and procedures apply, including those issued by the U.S. Dept. of Interior as noted above, and the U.S. Dept. of Transportation (U.S. Coast Guard and Office of Pipeline Safety). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. Calpine has state and private oil and gas leases covering developed and undeveloped properties located in Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, Missouri, Montana, New Mexico, Oklahoma, Texas and Wyoming. These federal, state and local authorities have various permitting, licensing and bonding requirements. Varied remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, and suspension of production. As a result, there can be no assurance that we will not incur liability for fines and penalties or otherwise subject Calpine to the various remedies as are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with these federal, state and local rules, regulations and procedures.

RISK FACTORS

Capital Resources

      We have substantial indebtedness that we may be unable to service and that restricts our activities. We have substantial debt that we incurred to finance the acquisition and development of power generation facilities. As of December 31, 2003, our total consolidated funded debt was $17.7 billion, our total consolidated assets were $27.3 billion and our stockholders’ equity was $4.6 billion. Whether we will be able to meet our debt service obligations and repay, extend, or refinance our outstanding indebtedness will be dependent primarily upon the operational performance of our power generation facilities and of our oil and gas properties, movements in electric and natural gas prices over time, and our marketing and risk management activities.

      This high level of indebtedness has important consequences, including:

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

      The operating and financial restrictions and covenants in certain of our existing debt agreements limit or prohibit our ability to:

  •  incur indebtedness;
 
  •  make prepayments on or purchase indebtedness in whole or in part;
 
  •  pay dividends;
 
  •  make investments;

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  •  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.

      Also, if our ownership changes, the indentures governing certain of our senior notes may require us to make an offer to purchase those senior notes. We cannot assure that we will have the financial resources necessary to purchase those senior notes in this event. If we are unable to comply with the terms of our indentures and other debt agreements, or if we fail to generate sufficient cash flow from operations, or to refinance our debt as described below, we may be required to refinance all or a portion of our senior notes and other debt or to obtain additional financing. However, we may be unable to refinance or obtain additional financing because of our high levels of debt and the debt incurrence restrictions under our indentures and other debt agreements. If cash flow is insufficient and refinancing or additional financing is unavailable, we may be forced to default on our senior notes and other debt obligations. In the event of a default under the terms of any of our indebtedness, the debt holders may accelerate the maturity of our obligations, which could cause defaults under our other obligations.

      In addition, our unsecured senior notes and our other senior unsecured debt are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness. Our secured indebtedness includes our $3.7 billion second-priority senior secured term loans and notes. The term loans and notes are secured by a second-priority lien on, among other things, substantially all of the assets owned directly by Calpine Corporation, including natural gas and power plant assets and the equity in all of the subsidiaries directly owned by Calpine Corporation. We also have a $500.0 million working capital facility that is secured by a first-priority lien on the same assets that secure our $3.7 billion second-priority senior secured term loans and notes. The noteholders’ recourse on our $800.0 million CCFC I institutional term loans and secured notes is limited to the assets and contracts associated with the seven natural gas-fired electric generating facilities owned by CCFC I and its subsidiaries (as adjusted for approved dispositions and acquisitions, such as the completed sale of Lost Pines Power Project and the pending acquisition of the Brazos Valley Power Plant). The lenders’ recourse on our $2.5 billion CalGen, formerly CCFC II secured revolving construction financing facility was limited to the assets and contracts associated with the 14 natural gas-fired electric generating facilities owned by subsidiaries of CalGen. The secured institutional term loans and secured notes issued by CalGen, that in March 2004 refinanced the $2.5 billion CalGen facility, are secured, through a combination of direct and indirect stock pledges and asset liens, by CalGen’s 14 power generating facilities and related assets located throughout the United States, and the lenders’ recourse is limited to such security. We have additional non-recourse project financings, secured in each case by the assets of the project being financed.

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

      We are subject to a holders’ put on December 26, 2004, which may require us to repurchase all or a portion of the aggregate principal amount of 4% Convertible Senior Notes Due 2006 (the “2006 Convertible

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Senior Notes”) then outstanding with our choice of cash, stock or a combination thereof. On February 9, 2004, we made a cash tender offer, which expired on March 9, 2004, for all of the outstanding 2006 Convertible Senior Notes at a price of par plus accrued interest. See “Business — Recent Developments” for more information regarding this tender offer. In addition, $276.0 million of our outstanding HIGH TIDES are scheduled to be remarketed no later than November 1, 2004, $360.0 million of our HIGH TIDES are scheduled to be remarketed no later than February 1, 2005, and $517.5 million of our HIGH TIDES are scheduled to be remarketed no later than August 1, 2005. In the event of a failed remarketing, the relevant HIGH TIDES will remain outstanding as convertible securities at a term rate equal to the treasury rate plus 6% per annum and with a term conversion price equal to 105% of the average closing price of our common stock for the five consecutive trading days after the applicable final failed remarketing termination date. We have $224.7 million in aggregate principal amount of 8 1/4% Senior Notes Due 2005 and $148.1 million aggregate principal amount of notes issued in connection with the monetization of a power contract with California Department of Water Resources (“DWR”) which will mature in 2005. In addition to the debt instruments discussed above, we have approximately $349.1 million and $133.9 million of miscellaneous debt and capital lease obligations that are maturing or for which scheduled principal payments will be made in 2004 and 2005, respectively.

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

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

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

      We have financed our existing power generation facilities using a variety of leveraged financing structures, consisting of senior secured and unsecured indebtedness, construction financing, project financing, revolving credit facilities, term loans and lease obligations. As of December 31, 2003, we had approximately $17.7 billion of total consolidated funded debt, consisting of $4.3 billion of secured construction/ project financing, $0.2 billion of capital lease obligations, $9.4 billion in senior notes, $1.3 billion in convertible senior notes, $0.2 billion in preferred interests, $1.2 billion of trust preferred securities and $1.1 billion of secured and unsecured notes payable and borrowings under lines of credit. Each project financing and lease obligation is structured to be fully paid out of cash flow provided by the facility or facilities financed or leased. In the event of a default under a financing agreement which we do not cure, the lenders or lessors would generally have rights to the facility and any related assets. In the event of foreclosure after a default, we might not retain any interest in the facility. While we intend to utilize non-recourse or lease financing when appropriate, market conditions and other factors may prevent similar financing for future facilities. It is possible that we may be unable to obtain the financing required to develop our power generation facilities on terms satisfactory to us.

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

      Our credit ratings have been downgraded and could be downgraded further. On July 17, 2003, Standard & Poor’s placed our corporate rating (currently rated at B), our senior unsecured debt rating (currently at CCC+), our preferred stock rating (currently at CCC), our bank loan rating (currently at B), and our second priority senior secured debt rating (currently at B) under review for possible downgrade.

      On July 23, 2003, Fitch, Inc. downgraded our long-term senior unsecured debt rating from B+ to B- (with a stable outlook), our preferred stock rating from B- to CCC (with a stable outlook), and initiated coverage of our senior secured debt rating at BB- (with a stable outlook).

      On October 20, 2003, Moody’s downgraded the rating of our long-term senior unsecured debt from B1 to Caa1 (with a stable outlook) and our senior implied rating from Ba3 to B2 (with a stable outlook). The ratings on our senior unsecured debt, senior unsecured convertible debt and convertible preferred securities were also lowered (with a stable outlook) from B1 to Caa1, from B1 to Caa1 and from B2 to Caa3, respectively.

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

      Our ability to repay our debt depends upon the performance of our subsidiaries. Almost all of our operations are conducted through our subsidiaries and other affiliates. As a result, we depend almost entirely upon their earnings and cash flow to service our indebtedness, including our ability to pay the interest and principal of our senior notes. The financing agreements of certain of our subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions, or otherwise transfer funds to us prior to the payment of their other obligations, including their outstanding debt, operating expenses, lease payments and reserves.

      Our subsidiaries and other affiliates are separate and distinct legal entities and, except in limited circumstances, have no obligation to pay any amounts due on our senior notes or our $500.0 million secured working capital credit facility and do not guarantee the payment of interest on or principal of such debt. The right of the holders of such debt to receive any assets of any of our subsidiaries or other affiliates upon our liquidation or reorganization will be subordinated to the claims of any subsidiaries’ or other affiliates’ creditors (including trade creditors and holders of debt issued by our subsidiaries or affiliates). As of December 31, 2003, our subsidiaries had $4.3 billion of secured construction/project financing. We may utilize project financing when appropriate in the future, and this financing will be effectively senior to our secured and unsecured debt.

      The senior note indentures and our senior secured credit facilities impose limitations on our ability and the ability of our subsidiaries to incur additional indebtedness. However, the senior note indentures do not limit the amount of construction/project financing that our subsidiaries may incur to finance the acquisition and development of new power generation facilities. The senior secured credit facilities do impose limitations on certain types of non-recourse financings.

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Operations

      Revenue may be reduced significantly upon expiration or termination of our power sales agreements. Some of the electricity we generate from our existing portfolio is sold under long-term power sales agreements that expire at various times. We also sell power under short to intermediate (1 to 5 year) contracts. When the terms of each of these various power sales agreements expire, it is possible that the price paid to us for the generation of electricity under subsequent arrangements may be reduced significantly.

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

      As a result, in part, of the fallout from Enron’s declaration of bankruptcy on December 2, 2001, companies using derivatives have become more sensitive to the inherent risks of such transactions. Consequently, many companies, including us, are requiring cash collateral for certain derivative transactions in excess of what was previously required. As of December 31, 2003, we had $188.0 million in margin deposits with counterparties, net of deposits posted by counterparties with us, and had posted $14.5 million of letters of credit, compared to $25.2 million and $106.1 million, respectively, at December 31, 2002. Future cash collateral requirements may increase based on the extent of our involvement in derivative activities and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market.

      We may be unable to obtain an adequate supply of natural gas in the future. To date, our fuel acquisition strategy has included various combinations of our own gas reserves, gas prepayment contracts, short-, medium-and long-term supply contracts and gas hedging transactions. In our gas supply arrangements, we attempt to match the fuel cost with the fuel component included in the facility’s power sales agreements in order to minimize a project’s exposure to fuel price risk. In addition, the focus of CES is to manage the “spark spread” for our portfolio of generating plants — the spread between the cost of fuel and electricity revenues — and we actively enter into hedging transactions to lock in gas costs and spark spreads. We believe that there will be adequate supplies of natural gas available at reasonable prices for each of our facilities when current gas supply agreements expire. However, gas supplies may not be available for the full term of the facilities’ power sales agreements, and gas prices may increase significantly. Additionally, our credit ratings may inhibit our ability to procure gas supplies from third parties. If gas is not available, or if gas prices increase above the level that can be recovered in electricity prices, there could be a negative impact on our results of operations or financial condition.

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

  •  necessary power generation equipment;
 
  •  governmental permits and approvals;
 
  •  fuel supply and transportation agreements;
 
  •  sufficient equity capital and debt financing;

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  •  electrical transmission agreements;
 
  •  water supply and wastewater discharge agreements; and
 
  •  site agreements and construction contracts.

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

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

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

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

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

      In certain situations, power sales agreements entered into with a utility early in the development phase of a project may enable the utility to terminate the agreement, or to retain security posted as liquidated damages, if a project fails to achieve commercial operation or certain operating levels by specified dates or fails to make specified payments. In the event a termination right is exercised, the default provisions in a financing agreement may be triggered (rendering such debt immediately due and payable). As a result, the project may be rendered insolvent and we may lose our interest in the project. In recent years we have begun to rely more

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frequently on traditional project financing, so the risk of a financing agreement default linked to a default under a power sales agreement may come into play.

      Our power generation facilities may not operate as planned. Upon completion of our projects currently under construction, we will operate 97 of the 99 power plants in which we will have an interest. The continued operation of power generation facilities, including, upon completion of construction, the facilities owned directly by Calpine, involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes, and performance below expected levels of output or efficiency. Although from time to time our power generation facilities have experienced equipment breakdowns or failures, these breakdowns or failures have not had a significant effect on the operation of the facilities or on our results of operations. For calendar year 2003, our gas-fired and geothermal power generation facilities operated at an average availability of approximately 91% and 97%, respectively. Although our facilities contain various redundancies and back-up mechanisms, a breakdown or failure may prevent the affected facility from performing under applicable power sales agreements. In addition, although insurance is maintained to protect against operating risks, the proceeds of insurance may not be adequate to cover lost revenues or increased expenses. As a result, we could be unable to service principal and interest payments under our financing obligations which could result in losing our interest in one or more power generation facility.

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

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

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

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

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

Market

      We depend on our electricity and thermal energy customers. Our systems of power generation facilities rely on one or more power sales agreements with one or more utilities or other customers for a substantial portion of our revenue. In addition, sales of electricity to one customer during 2003, the DWR, comprised approximately 14% of our total revenue that year. The loss of significant power sales agreements with DWR or an adverse change in DWR’s ability to pay for power delivered under our contracts could have a negative effect on our results of operations. In addition, any material failure by any customer to fulfill its obligations under a power sales agreement could have a negative effect on the cash flow available to us and on our results of operations.

      Competition could adversely affect our performance. The power generation industry is characterized by intense competition, and we encounter competition from utilities, industrial companies and other independent power producers. In recent years, there has been increasing competition among generators in an effort to obtain power sales agreements, and this competition has contributed to a reduction in electricity prices in certain markets. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power industry. In California, the California Public Utilities Commission (“CPUC”) issued decisions that provide for direct access for all customers as of April 1, 1998; however, the CPUC suspended direct access in California effective September 20, 2001, due to the problems that arose in California’s newly deregulated markets. As a result, uncertainty exists as to the future course for direct access in California in the aftermath of the energy crisis in that state. In Texas, legislation phased in a deregulated power market, which commenced on January 1, 2001. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the supply of electricity in the future will increase this pressure.

      Our international investments may face uncertainties. We have investments in oil and natural gas resources and power projects in Canada in development and in operation, an investment in an energy service business in the Netherlands, an investment in a power generation facility in development in Mexico, and an investment in a power generation facility in the U.K. that is in operation, and we may pursue additional international investments in the future subject to the limitations on our expansion plans due to current capital market constraints. International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the countries in which we invest. Risks specifically related to investments in non-United States projects may include:

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

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California Power Market

      The unresolved issues arising from the California power market, where 42 of our 99 power plants are located, could adversely affect our performance. The volatility in the California power market from mid-2000 through mid-2001 has produced significant unanticipated results.

      California Refund Proceeding. On August 2, 2000, the California Refund Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric Company under Section 206 of the Federal Power Act alleging, among other things, that the markets operated by the California Independent System Operator (“CAISO”) and the California Power Exchange (“CalPX”) were dysfunctional. In addition to commencing an inquiry regarding the market structure, FERC established a refund effective period of October 2, 2000, to June 19, 2001, for sales made into those markets.

      On December 12, 2002, the Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability (“December 12 Certification”) making an initial determination of refund liability. On March 26, 2003, FERC also issued an order adopting many of the ALJ’s findings set forth in the December 12 Certification (the “March 26 Order”). In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the refund period, FERC ordered that the basis for calculating a party’s potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the refund proceeding. We believe, based on information that we have analyzed to date, that any refund liability that may be attributable to us will increase modestly, from approximately $6.2 million to at least $8.4 million, after taking the appropriate set-offs for outstanding receivables owed by the CalPX and CAISO to Calpine. We have fully reserved the amount of refund liability that by our current analysis would potentially be owed under the refund calculation clarification in the March 26 order. We note that, in March 2004, CAISO transmitted new tentative price data as part of the process of further refining the refund calculation. We have not completed our analysis of this new tentative price data (which has not been approved by FERC and is subject to change), but it is possible that the revised price data will result in an increase in the refund liability that may be attributable to us. The final determination of the refund liability is subject to further Commission proceedings to ascertain the allocation of payment obligations among the numerous buyers and sellers in the California markets. At this time, we are unable to predict the timing of the completion of these proceedings or the final refund liability. Thus, the impact on our business is uncertain at this time.

      FERC Investigation into Western Markets. On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron and others used their market position to distort electric and natural gas markets in the West. The scope of the investigation is to consider whether, as a result of any manipulation in the short-term markets for electric energy or natural gas or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West are potentially unjust and unreasonable. FERC has stated that it may use the information gathered in connection with the investigation to determine how to proceed on any existing or future complaint brought under Section 206 of the Federal Power Act involving long-term power contracts entered into in the West since January 1, 2000, or to initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding on its own initiative. On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific Separate Proceedings and Generic Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies (the “Initial Report”) summarizing its initial findings in this investigation. There were no findings or allegations of wrongdoing by Calpine set forth or described in the Initial Report. On March 26, 2003, the FERC staff issued a final report in this investigation (the “Final Report”). The FERC staff recommended that FERC issue a show cause order to a number of companies, including Calpine, regarding certain power scheduling practices that may have been be in violation of the CAISO’s or CalPX’s tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. Calpine believes that it did not violate these tariffs and that, to the extent that such a finding could be made, any potential liability would not be material.

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

      CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility “avoided cost” to be used to set energy payments for certain QF contracts by determining the short run avoided cost (“SRAC”) energy price formula. In mid-2000 our QF facilities elected the option set forth in Section 390 of the California Public Utility Code, which provides QFs the right to elect to receive energy payments based on the CalPX market clearing price instead of the price determined by SRAC. Having elected such option, we were paid based upon the CalPX zonal day-ahead clearing price (“CalPX Price”) from summer 2000 until January 19, 2001, when the CalPX ceased operating a day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the CalPX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the CalPX-based pricing option. The CPUC at one point issued a proposed decision to the effect that the CalPX Price was the appropriate price for energy payments under the California Public Utility Code but tabled it, and a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. We believe that the CalPX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings.

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

Government Regulation

      We are subject to complex government regulation which could adversely affect our operations. Our activities are subject to complex and stringent energy, environmental and other governmental laws and regulations. The construction and operation of power generation facilities and oil and gas exploration and production require numerous permits, approvals and certificates from appropriate foreign, federal, state and local governmental agencies, as well as compliance with environmental protection legislation and other regulations. While we believe that we have obtained the requisite approvals and permits for our existing operations and that our business is operated in accordance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations may be revised or reinterpreted, or new laws and regulations may become applicable to us that may have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed facilities may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory

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compliance for the construction of new facilities is a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays or significant loss of value in a project.

      Environmental regulations have had and will continue to have an impact on our cost of doing business and our investment decisions. For example, the existing market-based cap-and-trade emissions allowance system in Texas requires operators to either reduce nitrogen oxide (“NOx”) emissions or purchase additional NOx allowances in the marketplace. Rather than purchase additional allowances, we have chosen to install additional NOx emission controls as part of a $31 million steam capacity upgrade at our Texas City facility and to retrofit our Clear Lake, Texas facility with similar technology at a cost of approximately $17 million. These new emission control systems will allow us to meet our thermal customers’ needs while reducing the need to purchase allowances for our facilities in Texas.

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

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

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

      Currently, Congress is considering proposed legislation that would repeal PUHCA, and would amend PURPA by limiting its mandatory purchase obligation to existing contracts in those regions of the country that are found to have competitive energy markets. In light of the circumstances in California, the 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 this legislation or regulatory initiatives will be adopted or, if adopted,

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what form they may take. We cannot provide assurance that any legislation or regulation ultimately adopted would not adversely affect our existing domestic projects.

      In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry and increase access to electric utilities’ transmission and distribution systems for independent power producers and electricity consumers. However, in light of the circumstances in the California power markets and the bankruptcies of both PG&E and Enron, the pace and direction of further deregulation at the state level in many jurisdictions is uncertain. See “California Power Market” risk factors.

Other Risk Factors

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

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

      Our results are subject to quarterly and seasonal fluctuations. Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including without limitation:

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

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

      The ultimate outcome of the legal proceedings relating to our activities cannot be predicted. Any adverse determination could have a material adverse effect on our financial condition and results of operations.

      We are party to various litigation matters arising out of the normal course of business, the more significant of which are summarized in “Item 3. Legal Proceedings.” These matters include securities class action lawsuits, such as Hawaii Structural Ironworkers Pension Fund v. Calpine et al, which relates to our April 2002 equity offering and also named the underwriters of that offering as defendants. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result, these matters may potentially be material to our financial condition and results of operations.

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

  •  general conditions in our industry, the power markets in which we participate, or the worldwide economy;
 
  •  announcements of developments related to our business or sector;
 
  •  fluctuations in our results of operations;
 
  •  our debt to equity ratios and other leverage ratios;
 
  •  effects of significant events relating to the energy sector in general;
 
  •  sales of substantial amounts of our securities into the marketplace;
 
  •  an outbreak of war or hostilities;
 
  •  a shortfall in revenues or earnings compared to securities analysts’ expectations;
 
  •  changes in analysts’ recommendations or projections; and
 
  •  announcements of new acquisitions or development projects by us.

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

EMPLOYEES

      As of December 31, 2003, we employed 3,418 people, of whom 62 (domestic and international) were represented by collective bargaining agreements. We have never experienced a work stoppage or strike, and we consider relations with our employees to be good. Although we are an asset-based company, we are successful because of the talents, intelligence, resourcefulness and energy level of our employees. As discussed in our strategy section, our employee knowledge base enables us to optimize the value and profitability of our electricity production and prudently manage the risks inherent in our business.

SUMMARY OF KEY ACTIVITIES

Finance

      New Issuances by Calpine Corporation and certain of its wholly owned subsidiaries:

         
Date Amount Description



2/13/03
  Cdn $153.3 million (US $100.9 million)  
Closed a secondary offering for the Calpine Power Income Fund
6/13/03
  $802.2 million  
Power Contract Financing, L.L.C, completed an offering of $339.9 million aggregate principal amount of 5.2% Senior Secured Notes Due 2006 and $462.3 million aggregate principal amount of 6.256% Senior Secured Notes Due 2010
7/16/03
  $3.3 billion  
Completed an offering of a $750.0 million floating rate term loan, $500.0 of million Second Priority Senior Secured Floating Rate Notes Due 2007, $1.15 billion aggregate principal amount of 8.5% Second Priority Senior Secured Notes Due 2010, and $900.0 million aggregate principal amount of 8.75% Second Priority Senior Secured Notes Due 2013
7/16/03
  $500.0 million  
Completed a $300.0 million two-year working capital revolver and a $200.0 million four-year term loan

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Date Amount Description



7/16/03
  $200.0 million  
Entered into a cash collateralized letter of credit facility for up to $200.0 million
8/14/03
  $750.0 million  
CCFC I and CCFC Finance Corp. completed an offering of $385.0 million aggregate principal amount of First Priority Floating Rate Secured Institutional Term Loans Due 2009, as well as $365.0 million aggregate principal amount of Second Priority Secured Floating Rate Notes Due 2011
8/25/03
  $230.0 million  
Completed non-recourse project financing for Riverside Energy Center
9/25/03
  $50.0 million  
CCFC I and CCFC Finance Corp. completed an offering of an additional $50.0 million aggregate principal amount of Second Priority Senior Secured Floating Rate Notes Due 2011
9/30/03
  $301.7 million  
Gilroy Energy Center, LLC, completed an offering of 4% Senior Secured Notes Due 2011.
10/6/03
  $120.0 million  
Calpine Power Income Fund obtained an extendible revolving term credit facility
10/15/03
  Cdn $184.5 million (US $139.4 million)  
Completed initial public offering of Calpine Natural Gas Trust
11/7/03
  $140.0 million  
Completed a non-recourse term loan for Blue Spruce Energy Center
11/17/03
  $650.0 million  
Completed offering of 4 3/4% Contingent Convertible Senior Notes Due 2023
11/18/03
  $400.0 million  
Completed offering of 9 7/8% Second Priority Senior Secured Notes Offering Due 2011

      Repurchases/ Repayments:

         
Date Amount Description



7/03
  $949.6 million  
Repaid outstanding balance under our $1.0 billion secured term credit facility
7/03
  $555.5 million  
Repaid outstanding balance on certain of our revolving credit facilities
7/03
  $50.0 million  
Repaid the outstanding balance on our California peaker financing
8/03
  $880.1 million  
Repaid the outstanding balance on our CCFC I project financing
6/03-12/03
  $1.9 billion  
Repurchased various debt securities
9/03-10/03
  $182.5 million  
Exchanged debt securities and HIGH TIDES for common stock in privately negotiated transactions

      Other:

     
Date Description


1/7/03
 
Entered into renegotiated power purchase and sales agreements with PG&E and DWR
1/21/03
 
Entered into a 16-year power purchase and sale agreement with Long Island Power Authority
1/27/03
 
Entered into a 3-year power purchase agreement with Nevada Power Company, a subsidiary of Sierra Pacific Resources
2/26/03
 
Federal Energy Regulatory Commission approved a Reliability Must-Run Settlement Agreement
3/17/03
 
Entered into a long-term power sales agreement with Southern California Edison
4/29/03
 
Completed sale of a preferred interest in a subsidiary that leases and operates King City Power Plant for $82.0 million
5/9/03
 
Entered into a two-year agreement to provide up to 300 megawatts of power to Brazos Electric Power Cooperative, Inc.

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Date Description


5/12/03
 
Completed the contract monetization and restructuring of our interest in Acadia Energy Center
5/15/03
 
Completed $82.8 million monetization of an existing power sales agreement with the Bonneville Power Administration
6/2/03
 
Standard & Poor’s downgraded the corporate credit rating to B from BB
7/17/03
 
Standard & Poor’s placed our corporate rating (currently rated at B), senior unsecured debt rating (currently at CCC+), preferred stock rating (currently at CCC), bank loan rating (currently at B) and second priority senior secured debt rating (currently at B) under review for possible downgrade
7/23/03
 
Fitch, Inc. downgraded the rating on long-term senior unsecured debt from B+ to B- (with a stable outlook) and preferred stock rating from B- to CCC (with a stable outlook), and initiated coverage of our senior secured debt rating at BB- (with a stable outlook)
8/7/03
 
Bankruptcy court approved final settlement with Enron resulting in our recording other revenue of $67.3 million
9/3/03
 
Completed sale of a 70-percent interest in Auburndale Power Plant to Pomifer Power Funding, LLC, a subsidiary of ArcLight Energy Partners Fund 1, L.P., for $88.0 million
9/30/03
 
Received funding on a third party preferred equity investment in GEC Holdings, LLC
10/20/03
 
Moody’s downgraded the rating on long-term senior unsecured debt from B1 to Caa1 (with a stable outlook) and senior implied rating from Ba3 to B2 (with a stable outlook). The ratings on senior unsecured debt, senior unsecured convertible debt and convertible preferred securities were also lowered (with a stable outlook) from B1 to Caa1, from B1 to Caa1 and from B2 to Caa3, respectively
10/23/03
 
Entered into a 2-year agreement to supply electricity to Reliant Energy Electric Solutions, LLC
11/26/03
 
Completed sale of unconsolidated investment in Gordonsville Power Plant for $36.2 million cash payment
12/2/03
 
Entered into a one-year agreement to provide up to 155 megawatts of power to Utility Choice Electric
12/4/03
 
Completed monetization of PG&E note receivable for $133.4 million

Power Plant Development and Construction

             
Date Project Description



  1/03     Goose Haven Energy Center   Commercial Operation
  1/03     Lambie Energy Center   Commercial Operation
  1/03     Creed Energy Center   Commercial Operation
  3/03     Los Esteros Energy Center   Commercial Operation
  3/03     Wolfskill Energy Center   Commercial Operation
  4/03     Blue Spruce Energy Center   Commercial Operation
  4/03     Calgary Energy Center   Commercial Operation
  5/03     Riverview Energy Center   Commercial Operation
  6/03     Carville Energy Center   Commercial Operation
  6/03     Santa Rosa Energy Center   Commercial Operation
  6/03     Oneta Energy Center, Phase II   Commercial Operation
  6/03     Deer Park Energy Center, Phases I and IA   Commercial Operation
  6/03     Decatur Energy Center, Phase I   Commercial Operation
  6/03     Morgan Energy Center, Units 2 and 3   Commercial Operation
  6/03     Zion Energy Center Expansion, Unit 3   Commercial Operation

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Turbine Restructuring Program

             
Date of Reduction in Capital
Announcement Spending Earnings Effect



  2/11/03     $3.4 billion  
Pre-tax charge of approximately $207.4 million in the quarter ended December 31, 2002
 
Annual Meeting of Stockholders on May 28, 2003
 
Stockholders’ Voting Results

  •  Election of Jeffrey E. Garten, George J. Stathakis and John O. Wilson as Class I Directors for a three-year term expiring 2006
 
  •  Proposal that the Board of Directors be requested to redeem the stockholders right plan unless such plan is approved by a majority vote of the stockholders to be held as soon as may be practicable — approved
 
  •  Proposal that the Board of Directors take the necessary steps to declassify the Board of Directors for the purpose of establishing elections for directors — approved
 
  •  Ratification of the appointment of PricewaterhouseCoopers LLP as independent accountants for the fiscal year ending December 31, 2003

      The three-year terms of Class II and Class III Directors continued after the Annual Meeting and will expire in 2004 and 2005, respectively. The Class II Directors are Ann B. Curtis, Kenneth T. Derr and Gerald Greenwald. The Class III Directors are Susan C. Schwab, Susan Wang and Peter Cartwright.

      See Item 1. “Business — Recent Developments” for 2004 developments.

 
Item 2. Properties

      Our principal executive office located in San Jose, California is held under leases that expire through 2008, and we also lease offices, with leases expiring through 2013, in Dublin and Folsom, California; Houston and Pasadena, Texas; Boston, Massachusetts; Washington, D.C.; Calgary, Alberta; and Jupiter, Florida. We hold additional leases for other satellite offices.

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

      We have leasehold interests in 107 leases comprising 21,888 acres of federal, state and private geothermal resource lands in The Geysers area in northern California. In the Glass Mountain and Medicine Lake areas in northern California, we hold leasehold interests in 41 leases comprising approximately 46,519 acres of federal geothermal resource lands.

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

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      Based on independent petroleum engineering reports of Netherland, Sewell & Associates Inc., and Gilbert Laustsen Jung Associates Ltd., as of December 31, 2003, utilizing year end product prices and costs held constant, our proved oil, natural gas, and natural gas liquids (“NGLs”) reserve volumes, in millions of barrels (“MMBbls”) and billions of cubic feet (“Bcf”) are as follows:

                   
As of December 31, 2003

Oil and NGLs
(MMBbls) Gas (Bcf)


United States
               
Proved developed
    1.9       369  
Proved undeveloped
    1.5       186  
     
     
 
 
Total
    3.4       555  
     
     
 
Canada
               
Proved developed
    6.8       176  
Proved undeveloped
    0.7       25  
     
     
 
 
Total
    7.5       201  
     
     
 
Consolidated
               
Proved developed
    8.7       545  
Proved undeveloped
    2.2       211  
     
     
 
 
Total
    10.9 (1)     756  
     
     
 


(1)  10.9 MMBbls of oil is equivalent to 65.4 Bcf of gas using a conversion factor of six thousand cubic feet of gas to one barrel of crude oil and natural gas liquids. On an equivalent basis, proved reserves at year-end totaled 821 Bcfe.

      Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimated future development costs associated with proved producing and non-producing plus proved undeveloped reserves as of December 31, 2003, totaled approximately $222 million.

      The following table sets forth our interest in undeveloped acreage, developed acreage and productive wells in which we own a working interest as of December 31, 2003. Gross represents the total number of acres or wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in the gross acres or wells. Productive wells are wells in which we have a working interest and are capable of producing oil or natural gas.

                                                 
Undeveloped Acres Developed Acres Productive Wells



Gross Net Gross Net Gross Net






United States
                                               
Arkansas
    160       80       3,521       1,399       32       15  
California
    17,999       17,482       48,334       37,617       278       231  
Colorado
    9,704       9,302       10,854       5,944       83       82  
Kansas
    118,488       107,933                          
Louisiana
    1,421       507       10,356       1,955       27       5  
Mississippi
    4,257       857       12,653       3,102       13       3  
Missouri
    35,008       31,651       43       43              
Montana
    43,290       30,259       960       240       2       1  
New Mexico
                13,017       9,924       90       64  

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Undeveloped Acres Developed Acres Productive Wells



Gross Net Gross Net Gross Net






Offshore
    2,625       2,625       21,260       16,141       34       24  
Oklahoma
    492       92       13,007       4,475       43       12  
Texas
    54,081       26,378       96,678       48,524       601       299  
Wyoming
    50,750       39,649       600       2              
     
     
     
     
     
     
 
 
Total United States
    338,275       266,815       231,283       129,366       1,203       736  
     
     
     
     
     
     
 
Canada
                                               
Alberta
    834,332       567,958       847,269       375,195       1,851       459  
British Columbia
    298,955       69,520       16,826       4,322              
Saskatchewan
    158       13       394       70              
     
     
     
     
     
     
 
 
Total Canada
    1,133,445       637,491       864,489       379,587       1,851       459  
     
     
     
     
     
     
 
Consolidated Total
    1,471,720       904,306       1,095,772       508,953       3,054       1,195  
     
     
     
     
     
     
 

      The following table sets forth the number of gross exploratory and gross development wells drilled in which we participated during the last three fiscal years. The number of wells drilled refers to the number of wells commenced at any time during the respective fiscal year. Productive wells are either producing wells or wells capable of commercial production. At December 31, 2003, we were in the process of drilling 2 wells (net 2) in the US and 3 wells (net 1) in Canada.

                                                   
Exploratory Development


Productive Dry Total Productive Dry Total






2003
                                               
United States
    17       8       25       20       5       25  
Canada
    1       2       3       158       3       161  
     
     
     
     
     
     
 
 
Total
    18       10       28       178       8       186  
     
     
     
     
     
     
 
2002
                                               
United States
          6       6       41       4       45  
Canada
    1       1       2       87       8       95  
     
     
     
     
     
     
 
 
Total
    1       7       8       128       12       140  
     
     
     
     
     
     
 
2001
                                               
United States
    5       2       7       66       12       78  
Canada
    2             2       186       26       212  
     
     
     
     
     
     
 
 
Total
    7       2       9       252       38       290  
     
     
     
     
     
     
 

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

                                                   
Exploratory Development


Productive Dry Total Productive Dry Total






2003
                                               
United States
    14.0       4.5       18.5       18.5       3.4       21.9  
Canada
    0.3       0.7       1.0       42.5       1.0       43.5  
     
     
     
     
     
     
 
 
Total
    14.3       5.2       19.5       61.0       4.4       65.4  
     
     
     
     
     
     
 
2002
                                               
United States
          3.9       3.9       36.4       2.8       39.2  
Canada
    0.5       0.5       1.0       38.9       4.2       43.1  
     
     
     
     
     
     
 
 
Total
    0.5       4.4       4.9       75.3       7.0       82.3  
     
     
     
     
     
     
 
2001
                                               
United States
    2.2       1.0       3.2       58.9       7.4       66.3  
Canada
    1.6             1.6       97.2       19.7       116.9  
     
     
     
     
     
     
 
 
Total
    3.8       1.0       4.8       156.1       27.1       183.2  
     
     
     
     
     
     
 

      The following table shows our annual average wellhead sales prices and average production costs (excluding production taxes). The average sales prices with hedges include realized gains and losses for derivative contracts we enter into with non-affiliates to manage price risk related to our sales volumes.

                                                     
With Hedges Without Hedges


2003 2002 2001 2003 2002 2001






UNITED STATES
                                               
 
Sales price
                                               
   
Natural gas (per Mcf)(1)
  $ 5.30     $ 3.14     $ 4.90     $ 5.30     $ 3.06     $ 4.81  
   
Oil and condensate (per barrel)
  $ 29.64     $ 21.58     $ 23.30     $ 29.64     $ 21.58     $ 23.30  
   
Natural gas liquids (per barrel)
  $ 18.42     $ 13.35     $ 15.67     $ 18.42     $ 13.35     $ 15.67  
 
Production cost (per Mcfe)(2)
  $ 0.61     $ 0.50     $ 0.53     $ 0.61     $ 0.50     $ 0.53  
 
CANADA
                                               
 
Sales price
                                               
   
Natural gas (per Mcf)
  $ 4.81     $ 2.44     $ 3.17     $ 4.81     $ 2.44     $ 3.25  
   
Oil and condensate (per barrel)
  $ 26.01     $ 21.95     $ 20.49     $ 28.72     $ 22.29     $ 20.16  
   
Natural gas liquids (per barrel)
  $ 26.31     $ 18.48     $ 20.96     $ 26.31     $ 18.48     $ 20.96  
 
Production cost (per Mcfe)
  $ 0.96     $ 0.60     $ 0.53     $ 0.96     $ 0.60     $ 0.53  
 
TOTAL
                                               
 
Sales price
                                               
   
Natural gas (per Mcf)
  $ 5.13     $ 2.76     $ 3.76     $ 5.13     $ 2.72     $ 3.78  
   
Oil and condensate (per barrel)
  $ 27.46     $ 21.90     $ 20.69     $ 29.08     $ 22.20     $ 20.38  
   
Natural gas liquids (per barrel)
  $ 26.10     $ 18.35     $ 20.90     $ 26.10     $ 18.35     $ 20.90  
 
Production cost (per Mcfe)
  $ 0.75     $ 0.56     $ 0.53     $ 0.75     $ 0.56     $ 0.53  


(1)  Thousand cubic feet.
 
(2)  Thousand cubic feet equivalent.

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Item 3. Legal Proceedings

      We are party to various litigation matters arising out of the normal course of business, the more significant of which are summarized below. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result of these matters, may potentially be material to our consolidated financial statements.

      Securities Class Action Lawsuits. Since March 11, 2002, fourteen shareholder lawsuits have been filed against Calpine and certain of its officers in the United States District Court, Northern District of California. The actions captioned Weisz v. Calpine Corp., et al., filed March 11, 2002, and Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002, are purported class actions on behalf of purchasers of Calpine stock between March 15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18, 2002, is a purported class action on behalf of purchasers of Calpine stock between February 6, 2001 and December 13, 2001. The eleven other actions, captioned Local 144 Nursing Home Pension Fund v. Calpine Corp., Lukowski v. Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., Laborers Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp., and Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The complaints in these eleven actions are virtually identical — they are filed by three law firms, in conjunction with other law firms as co-counsel. All eleven lawsuits are purported class actions on behalf of purchasers of Calpine’s securities between January 5, 2001 and December 13, 2001.

      The complaints in these fourteen actions allege that, during the purported class periods, certain Calpine executives issued false and misleading statements about Calpine’s financial condition in violation of Sections 10(b) and 20(1) of the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek an unspecified amount of damages, in addition to other forms of relief.

      In addition, a fifteenth securities class action, Ser v. Calpine, et al., was filed on May 13, 2002. The underlying allegations in the Ser action are substantially the same as those in the above-referenced actions. However, the Ser action is brought on behalf of a purported class of purchasers of Calpine’s 8.5% Senior Notes Due February 15, 2011 (“2011 Notes”) and the alleged class period is October 15, 2001 through December 13, 2001. The Ser complaint alleges that, in violation of Sections 11 and 15 of the Securities Act of 1933, the Supplemental Prospectus for the 2011 Notes contained false and misleading statements regarding Calpine’s financial condition. This action names Calpine, certain of its officers and directors, and the underwriters of the 2011 Notes offering as defendants, and seeks an unspecified amount of damages, in addition to other forms of relief.

      All fifteen of these securities class action lawsuits were consolidated in the U.S. District Court for the Northern District Court of California. The plaintiffs filed a first amended complaint in October 2002. The amended complaint did not include the 1933 Act complaints raised in the bondholders’ complaint, and the number of defendants named was reduced. On January 16, 2003, before our response was due to this amended complaint, the plaintiffs filed a further second complaint. This second amended complaint added three additional Calpine executives and Arthur Andersen LLP as defendants. The second amended complaint set forth additional alleged violations of Section 10 of the Securities Exchange Act of 1934 relating to allegedly false and misleading statements made regarding Calpine’s role in the California energy crisis, the long term power contracts with the California Department of Water Resources, and Calpine’s dealings with Enron, and additional claims under Section 11 and Section 15 of the Securities Act of 1933 relating to statements regarding the causes of the California energy crisis. We filed a motion to dismiss this consolidated action in early April 2003.

      On August 29, 2003, the judge issued an order dismissing, with leave to amend, all of the allegations set forth in the second amended complaint except for a claim under Section 11 of the Securities Act relating to statements relating to the causes of the California energy crisis and the related increase in wholesale prices contained in the Supplemental Prospectuses for the 2011 Notes.

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      The judge instructed plaintiffs to file a third amended complaint, which they did on October 17, 2003. The third amended complaint names Calpine and three executives as defendants and alleges the Section 11 claim that survived the judge’s August 29, 2003 order.

      On November 21, 2003, Calpine and the individual defendants moved to dismiss the third amended complaint on the grounds that plaintiff’s Section 11 claim was barred by the applicable one-year statute of limitations. On February 5, 2004, the judge denied our motion to dismiss but has asked the parties to be prepared to file summary judgment motions to address the statute of limitations issue. Our answer to the third amended complaint has been filed. We consider the lawsuit to be without merit and we intend to continue to defend vigorously against these allegations.

      Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was filed on March 11, 2003, against Calpine, its directors and certain investment banks in the California Superior Court, San Diego County. The underlying allegations in the Hawaii Structural Ironworkers Pension Fund action (“Hawaii action”) are substantially the same as the federal securities class actions described above. However, the Hawaii action is brought on behalf of a purported class of purchasers of Calpine’s equity securities sold to public investors in its April 2002 equity offering. The Hawaii action alleges that the Registration Statement and Prospectus filed by Calpine which became effective on April 24, 2002, contained false and misleading statements regarding Calpine’s financial condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933. The Hawaii action relies in part on Calpine’s restatement of certain past financial results, announced on March 3, 2003, to support its allegations. The Hawaii action seeks an unspecified amount of damages, in addition to other forms of relief.

      We removed the Hawaii action to federal court in April 2003 and filed a motion to transfer the case for consolidation with the other securities class action lawsuits in the U.S. District Court Northern District Court of California in May 2003. The plaintiff sought to have the action remanded to state court, and on August 27, 2003, the U.S. District Court for the Southern District of California granted plaintiff’s motion to remand the action to state court. In early October 2003 plaintiff agreed to dismiss the claims it has against three of the outside directors.

      On November 5, 2003, Calpine, the individual defendants and the underwriter defendants filed motions to dismiss this complaint on numerous grounds. On February 6, 2004, the court issued a tentative ruling sustaining our motion to dismiss on the issue of the plaintiff’s standing. The court found that the plaintiff had not shown that it had purchased Calpine’ stock “traceable” to the April 2002 equity offering. The court overruled our motion to dismiss on all other grounds. We have requested oral argument on these other issues which oral argument is currently scheduled for March 2004. We consider this lawsuit to be without merit and intend to continue defend vigorously against it.

      Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in the Calpine Corporation Retirement Savings Plan (the “401(k) Plan”) filed a class action lawsuit in the Northern District Court of California. The underlying allegations in this action (“Phelps action”) are substantially the same as those in the securities class actions described above. However, the Phelps action is brought on behalf of a purported class of participants in the 401(k) Plan. The Phelps action alleges that various filings and statements made by Calpine during the class period were materially false and misleading, and that the defendants failed to fulfill their fiduciary obligations as fiduciaries of the 401(k) Plan by allowing the 401(k) Plan to invest in Calpine common stock. The Phelps action seeks an unspecified amount of damages, in addition to other forms of relief. In May 2003 Lennette Poor-Herena, another participant in the 401(k) Plan, filed a substantially similar class action lawsuit as the Phelps action also in the Northern District of California. Plaintiffs’ counsel is the same in both of these actions, and they have agreed to consolidate these two cases and to coordinate them with the consolidated federal securities class actions described above. On January 20, 2004, plaintiff James Phelps filed a consolidated ERISA complaint naming Calpine and numerous individual current and former Calpine Board members and employees as defendants. Calpine’s response to the amended complaint is due March 22, 2004. We consider this lawsuit to be without merit and intend to vigorously defend against it.

      Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of Calpine against its directors and one of its senior officers. This lawsuit is captioned Johnson v.

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Cartwright, et al. and is pending in the California Superior Court, Santa Clara County. Calpine is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about Calpine and stock sales by certain of the director defendants and the officer defendant. In December 2002 the court dismissed the complaint with respect to certain of the director defendants for lack of personal jurisdiction, though the plaintiff may appeal this ruling. In early February 2003 the plaintiff filed an amended complaint. In March 2003 Calpine and the individual defendants filed motions to dismiss and motions to stay this proceeding in favor of the federal securities class actions described above. In July 2003 the Court granted the motions to stay this proceeding in favor of the consolidated federal securities class actions described above. We consider this lawsuit to be without merit and intend to vigorously defend against it.

      Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a derivative suit in the United States District Court for the Northern District California on behalf of Calpine against its directors, captioned Gordon v. Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to dismiss the action against certain of the director defendants on the grounds of lack of personal jurisdiction, as well as to dismiss the complaint in total on other grounds. In February 2003 plaintiff agreed to stay these proceedings in favor of the consolidated federal securities class action described above and to dismiss without prejudice certain director defendants. On March 4, 2003, the plaintiff filed papers with the court voluntarily agreeing to dismiss without prejudice the claims he had against three of the outside directors. We consider this lawsuit to be without merit and intend to continue to defend vigorously against it.

      Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, Calpine sued Automated Credit Exchange (“ACE”) in the Superior Court of the State of California for the County of Alameda for negligence and breach of contract to recover reclaim trading credits, a form of emission reduction credits that should have been held in Calpine’s account with U.S. Trust Company (“US Trust”). Calpine wrote off $17.7 million in December 2001 related to losses that it alleged were caused by ACE. Calpine and ACE entered into a Settlement Agreement on March 29, 2002, pursuant to which ACE made a payment to Calpine of $7 million and transferred to Calpine the rights to the emission reduction credits to be held by ACE. We recognized the $7 million as income in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. (“InterGen”) against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to Calpine’s loss from ACE. InterGen’s complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. By a judgment entered on October 30, 2002, the Bankruptcy Court consolidated ACE and the other Sholtz controlled entities with the bankruptcy estate of EonXchange. Subsequently, the Trustee of EonXchange filed a separate motion to substantively consolidate Anne Sholtz into the bankruptcy estate of EonXchange. Although Anne Sholtz initially opposed such motion, she entered into a settlement agreement with the Trustee consenting to her being substantively consolidated into the bankruptcy proceeding. The Bankruptcy Court entered an order approving Anne Sholtz’s settlement agreement with the Trustee on April 3, 2002. On July 10, 2003, Howard Grobstein, the Trustee in the EonXchange bankruptcy, filed a complaint for avoidance against Calpine, seeking recovery of the $7 million (plus interest and costs) paid to Calpine in the March 29, 2002 Settlement Agreement. The complaint claims that the $7 million received by Calpine in the Settlement Agreement was transferred within 90 days of the filing of bankruptcy and therefore should be avoided and preserved for the benefit of the bankruptcy estate. On August 28, 2003, Calpine filed its answer denying that the $7 million is an avoidable preference. Discovery is currently ongoing. Calpine believes that it has valid defenses to this claim and will vigorously defend against this complaint. On January 26, 2004, Calpine filed a Motion for Partial Summary Judgment asserting that the Bankruptcy Court did not properly consolidate Anne Sholtz into the bankruptcy estate of EonXchange. If the motion is granted, at least $2.9 million of the $7 million that the Trustee is seeking to recover from Calpine could not be avoided as a preferential transfer. We believe we have adequately reserved for the possible loss, if any, it may ultimately incur as a result of this matter.

      International Paper Company v. Androscoggin Energy LLC. In October 2000 International Paper Company (“IP”) filed a complaint in the Federal District Court for the Northern District of Illinois against

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Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. We had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which closed in October 2000. AELLC filed a counterclaim against IP that has been referred to arbitration. AELLC may commence the arbitration counterclaim after discovery has progressed further. On November 7, 2002, the court issued an opinion on the parties’ cross motions for summary judgment finding in AELLC’s favor on certain matters though granting summary judgment to IP on the liability aspect of a particular claim against AELLC. The Court also denied a motion submitted by IP for preliminary injunction to permit IP to make payment of funds into escrow (not directly to AELLC) and require AELLC to post a significant bond.

      In mid-April of 2003 IP unilaterally availed itself to self-help in withholding amounts in excess of $2.0 million as a set-off for litigation expenses and fees incurred to date as well as an estimated portion of a rate fund to AELLC. Upon AELLC’s amended complaint and request for immediate injunctive relief against such actions, the Court ordered that IP must pay the approximately $1.2 million withheld as attorneys’ fees related to the litigation as any such perceived entitlement was premature, but deferred to provide injunctive relief on the incomplete record concerning the offset of $799,000 as an estimated pass-through of the rate fund. IP complied with the order on April 29, 2003, and tendered payment to AELLC of the approximately $1.2 million. On June 26, 2003, the court entered an order dismissing AELLC’s Amended Counterclaim without prejudice to AELLC refiling the claims as breach of contract claims in a separate lawsuit. On June 30, 2003, AELLC filed a motion to reconsider the order dismissing AELLC’s Amended Counterclaim. On December 11, 2003, the Court denied in part IP’s summary judgment motion pertaining to damages. In short, the Court: (i) determined that, as a matter of law, IP is entitled to pursue an action for damages as a result of AELLC’s breach, and (ii) ruled that sufficient questions of fact remain to deny IP summary judgment on the measure of damages as IP did not sufficiently establish causation resulting from AELLC’s breach of contract (the liability aspect of which IP obtained a summary judgment in December 2002). On February 2, 2004, the parties filed a pretrial order with the Court. The case appears likely scheduled for trial in the second quarter of 2004, subject to the Court’s discretion and calendar. We believe we have adequately reserved for the possible loss, if any, we may ultimately incur as a result of this matter.

      Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22, 2003, Pacific Gas and Electric Company (“PG&E”) filed with the California Public Utilities Commission (“CPUC”) a Complaint of PG&E and Request for Immediate Issuance of an Order to Show Cause (“Complaint”) against Calpine Corporation, CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas Company, and Lodi Gas Storage, LLC (“LGS”) . The Complaint requests the CPUC to issue an order requiring the defendants to show cause why they should not be ordered to cease and desist from using any direct interconnections between the facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek and obtain regulatory approval from the CPUC. The Complaint also seeks an order directing defendants to pay to PG&E any underpayments of PG&E’s tariffed transportation rates and to make restitution for any profits earned from any business activity related to LGS’ direct interconnections to any entity other than PG&E. The Complaint further alleges that various natural gas consumers, including Calpine-affiliated generation projects within California, are engaged with defendants in the acts complained of, and that the defendants unlawfully bypass PG&E’s system and operate as an unregulated local distribution company within PG&E’s service territory. On August 27, 2003, Calpine filed its answer and a motion to dismiss. LGS has also made similar filings. On October 16, 2003, the presiding administrative law judge denied the motion to dismiss and on October 24, 2003, issued a Scoping Memo and Ruling establishing a procedural schedule and set the matter for an evidentiary hearing. Although Calpine has denied the allegations in the Complaint and believes this Complaint to be without merit, on January 15, 2004, Calpine, LGS and PG&E executed a Settlement Agreement to resolve all outstanding allegations and claims raised in the Complaint. Certain aspects of the Settlement Agreement are effective immediately and the effectiveness of other provisions is subject to the approval of the Settlement Agreement by the CPUC; in the event the CPUC fails to approve the Settlement Agreement, its operative terms and conditions become null and void. The Settlement Agreement provides, in part, for: 1) PG&E to be paid $2.7 million; 2) the disconnection of the LGS interconnections with Calpine; 3) Calpine to obtain PG&E consent or regulatory or other governmental approval before resuming any sales or

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exchanges at the Ryer Island Meter Station; 4) PG&E’s withdrawal of its public utility claims against Calpine; and 5) no party admitting any wrongdoing. Accordingly, the presiding administrative law judge vacated the hearing schedule and established a new procedural schedule for the filing of the Settlement Agreement. On February 6, 2004, the Settlement Agreement was filed with the CPUC. Parties have the opportunity to submit comments and reply comments on the Settlement Agreement and then the matter shall be before the CPUC for its consideration.

      Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On November 5, 2003, Panda Energy International, Inc. and certain related parties, including PLC II, LLC, (collectively “Panda”) filed suit against Calpine and certain of its affiliates in the U.S. District Court for the Northern District of Texas, alleging, among other things, that we breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta Energy Center (“Oneta”), which we acquired from Panda, in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits from Oneta plant and that Calpine’s actions have reduced the profits from Oneta plant thereby undermining Panda’s ability to repay monies owed to Calpine on December 1, 2003, under a promissory note on which approximately $38.6 million (including interest) is currently outstanding. The note is collateralized by Panda’s carried interest in the income generated from Oneta, which achieved full commercial operations in June 2003. We have filed a counterclaim against Panda Energy International, Inc. (and PLC II, LLC) based on a guaranty, and have also filed a motion to dismiss as to the causes of action alleging federal and state securities laws violations. We consider Panda’s lawsuit to be without merit and intend to defend vigorously against it. We stopped accruing interest income on the promissory note due December 1, 2003, as of the due date because of Panda’s default in repayment of the note.

      California Business & Professions Code Section 17200 Cases, of which the lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al. This purported class action complaint filed in May 2002 against twenty energy traders and energy companies, including CES, alleges that defendants exercised market power and manipulated prices in violation of California Business & Professions Code Section 17200 et seq., and seeks injunctive relief, restitution, and attorneys’ fees. We also have been named in seven other similar complaints for violations of Section 17200. All seven cases were removed from the various state courts in which they were originally filed to federal court for pretrial proceedings with other cases in which we are not named as a defendant. We consider the allegations to be without merit, and filed a motion to dismiss on August 28, 2003. The court granted the motion, and plaintiffs have appealed.

      Prior to the motion to dismiss being granted, one of the actions, captioned Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to the Superior Court of the State of California for the County of Alameda. On January 12, 2004, CES was added as a defendant in Millar. This action includes similar allegations to the other 17200 cases, but also seeks rescission of the long term power contracts with the California Department of Water Resources. We anticipate filing a timely motion for dismissal of this action as well.

      McClintock et al. v. Vikram Budhraja, et al. California Department of Water Resources Case. On May 1, 2002, California State Senator Tom McClintock and others filed a complaint against Vikram Budhraja, a consultant to the California Department of Water Resources (“DWR”), DWR itself, and more than twenty-nine energy providers and other interested parties, including Calpine. The complaint alleged that the long term power contracts that DWR entered into with these energy providers, including Calpine, were rendered void because Budhraja, who negotiated the contracts on behalf of DWR, allegedly had an undisclosed financial interest in the contracts due to his connection with one of the energy providers, Edison International. Among other things, the complaint sought an injunction prohibiting further performance of the long term contracts and restitution of any funds paid to energy providers by the State of California under the contracts. The action had been stayed by order of the Court since August 26, 2002, pending resolution of an earlier filed state court action involving the same parties and subject matter captioned Carboneau v. State of California in which we are not a defendant. We considered the allegations in this lawsuit to be without merit and filed a motion for dismissal with prejudice on November 26, 2003, which was granted. No appeal was filed and therefore the case has been concluded in its entirety.

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      Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy Services, L.P. before the FERC, filed on December 4, 2001. Nevada Section 206 Complaint. On December 4, 2001, Nevada Power Company (“NPC”) and Sierra Pacific Power Company (“SPPC”) filed a complaint with FERC under Section 206 of the Federal Power Act against a number of parties to their power sales agreements, including Calpine. NPC and SPPC allege in their complaint, which seeks a refund, that the prices they agreed to pay in certain of the power sales agreements, including those signed with Calpine, were negotiated during a time when the power market was dysfunctional and that they are unjust and unreasonable. The Administrative Law Judge issued an Initial Decision on December 19, 2002, that found for Calpine and the other respondents in the case and denied NPC the relief that it was seeking. In June 2003, FERC rejected the complaint. Some plaintiffs appealed to the FERC and their request for rehearing was denied. The FERC decision is therefore final, and the matter is pending on appeal before the United States Court of Appeals for the Ninth Circuit.

      Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6, 2002, Calpine Canada Natural Gas Partnership (“Calpine Canada”) filed a complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp. (“Enron Canada”) owed it approximately $1.5 million from the sale of gas in connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron Canada has not sought bankruptcy relief and has counterclaimed in the amount of $18 million. Discovery is currently in progress, and we believe that Enron Canada’s counterclaim is without merit and intend to vigorously defend against it.

      Jones v. Calpine Corporation. On June 11, 2003, the Estate of Darrell Jones and the Estate of Cynthia Jones filed a complaint against Calpine in the U.S. District Court, Western District of Washington. Calpine purchased Goldendale Energy, Inc., a Washington corporation, from Darrell Jones. The agreement provided, among other things, that upon substantial completion of the Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0 million less $0.2 million per day for each day that elapsed between July 1, 2002, and the date of substantial completion. Substantial completion of the Goldendale facility has not occurred and the daily reduction in the payment amount has reduced the $18.0 million payment to zero. The complaint alleges that by not achieving substantial completion by July 1, 2002, Calpine breached its contract with Mr. Jones, violated a duty of good faith and fair dealing, and caused an inequitable forfeiture. The complaint seeks damages in an unspecified amount in excess of $75,000. On July 28, 2003, Calpine filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. The court granted Calpine’s motion to dismiss the complaint on March 10, 2004. The plaintiffs have filed a motion for reconsideration of the decision, and the plaintiffs may also ultimately appeal. Calpine still, however, expects to make the $6.0 million payment to the estates when the project is completed.

      In addition, we are involved in various other legal actions proceedings, and state and regulatory investigations relating to our business. These actions and proceedings are described in detail elsewhere in this report. See Item 1. “Business — Risk Factors — California Power Market.” We are involved in various other claims and legal actions arising out of the normal course of our business. We do not expect that the outcome of these proceedings will have a material adverse effect on our financial position or results of operations.

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

      None.

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PART II

 
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

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

                 
High Low


2003
               
First Quarter
  $ 4.42     $ 2.51  
Second Quarter
    7.25       3.33  
Third Quarter
    8.03       4.76  
Fourth Quarter
    5.25       3.28  
2002
               
First Quarter
  $ 17.28     $ 6.15  
Second Quarter
    13.55       5.30  
Third Quarter
    7.29       2.36  
Fourth Quarter
    4.69       1.55  

      As of March 19, 2004, there were approximately 2,169 holders of record of our common stock. On March 19, 2004, the last sale price reported on the New York Stock Exchange for our common stock was $5.14 per share.

      We have not declared any cash dividends on the common stock during the past two fiscal years. We do not anticipate paying any cash dividends on the common stock in the foreseeable future because we intend to retain our earnings to finance the expansion of our business, to repay debt, and for general corporate purposes. In addition, our ability to pay cash dividends is restricted under certain of our indentures and our other debt agreements. Future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual restrictions and such other factors as the board of directors may deem relevant.

Convertible Senior Notes

      4% Convertible Senior Notes Due 2006. On December 26, 2001, we completed a private placement of $1.0 billion aggregate principal amount of our 4% Convertible Senior Notes Due 2006 (“2006 Convertible Senior Notes”). The initial purchaser of the 2006 Convertible Senior Notes was Deutsche Bank Alex. Brown Inc. Deutsche Bank exercised its option to acquire an additional $200.0 million aggregate principal amount of the 2006 Convertible Senior Notes by purchasing an additional $100.0 million aggregate principal amount of the 2006 Convertible Senior Notes on each of December 31, 2001, and January 3, 2002. The offering price of the 2006 Convertible Senior Notes was 100% of the principal amount, less an aggregate underwriting discount of $30.0 million. Each sale of the 2006 Convertible Senior Notes to Deutsche Bank was exempt from registration in reliance on Section 4(2) under the Securities Act of 1933, as amended, as a transaction not involving a public offering. The 2006 Convertible Senior Notes were re-offered by Deutsche Bank to qualified institutional buyers in reliance on Rule 144A under the Securities Act.

      We subsequently filed with the SEC a registration statement with respect to resales of the 2006 Convertible Senior Notes, which was declared effective by the SEC on June 21, 2002.

      The 2006 Convertible Senior Notes are convertible into shares of our common stock at a conversion price of $18.07 per share which represents a 13.0% premium over the New York Stock Exchange closing price of $15.99 per share on December 26, 2001. The conversion price is subject to adjustment in certain circumstances. We have reserved 66,408,411 shares of our authorized common stock for issuance upon

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conversion of the 2006 Convertible Senior Notes, which are convertible at any time on or before the close of business on the day that is two business days prior to the maturity date, December 26, 2006, unless we have previously repurchased the 2006 Convertible Senior Notes. Holders of the 2006 Convertible Senior Notes have the right to require us to repurchase their notes on at par plus accrued interest December 26, 2004. We may choose to pay the repurchase price in cash or shares of common stock, or a combination thereof. As of December 31, 2003, we had repurchased $539.9 million of principal amount of the 2006 Convertible Senior Notes in open market and privately negotiated transactions, leaving an outstanding balance of $660.1 million.

      Subsequent to December 31, 2003, we repurchased approximately $177.0 million in principal amount of our outstanding 2006 Convertible Senior Notes that can be put to us in exchange for approximately $176.0 million in cash. Additionally, on February 9, 2004, we made a cash tender offer, which expired on March 9, 2004, for all of the outstanding 2006 Convertible Senior Notes at a price of par plus accrued interest. On March 10, 2004, we paid an aggregate amount of $412.8 million for the tendered 2006 Convertible Senior Notes which included accrued interest of $3.4 million. Currently, 2006 Convertible Senior Notes in the aggregate principal amount of $73.7 million remain outstanding.

      4 3/4% Contingent Convertible Senior Notes Due 2023. On November 17, 2003, we completed the issuance of $650 million aggregate principal amount of our 4 3/4% Contingent Convertible Senior Notes Due 2023 (“2023 Convertible Notes”). The initial purchasers of the 2023 Convertible Notes were Deutsche Bank Securities Inc., Credit Lyonnais Securities (USA) Inc., Harris Nesbitt Corp. and Williams Capital Group LP (the “initial purchasers”). One of the initial purchasers, Deutsche Bank Securities Inc., exercised its option to acquire an additional $250.0 million aggregate principal amount of the 2023 Convertible Notes on January 9, 2004. The offering price of the 2023 Convertible Notes was 100% of the principal amount of the 2023 Convertible Senior Notes, less an aggregate underwriting discount of $24.75 million. Each sale of the 2023 Convertible Notes to an initial purchaser was exempt from registration in reliance on Section 4(2) under the Securities Act of 1933, as amended, as a transaction not involving a public offering. The 2023 Convertible Notes were offered by each initial purchaser to qualified institutional buyers in reliance on Rule 144A under the Securities Act.

      Upon the occurrence of certain contingencies, the 2023 Convertible Notes are convertible, at the option of holder, into cash and shares of our common stock at an initial conversion price of $6.50 per share, which represents a 38% premium over The New York Stock Exchange closing price of $4.71 per share on November 6, 2003. The number of shares of our common stock a holder ultimately receives upon conversion is determined by a formula based on the closing price of our common stock on The New York Stock Exchange over a period of five consecutive trading days during a specified period. We have initially reserved 69,230,000 shares of our authorized common stock for issuance upon conversion of the 2023 Convertible Notes, and have undertaken to reserve additional shares as may be necessary to satisfy our obligation to deliver shares upon conversion if our stock price increases such that the numbers of shares reserved is inadequate. Upon conversion of the 2023 Convertible Notes, we will deliver par value in cash and any additional value in shares of our common stock. The 2023 Contingent Notes will mature on November 15, 2023. We may redeem some or all of the notes at any time on or after November 22, 2009, at a redemption price, payable in cash, of 100% of the principal amount of the notes, plus accrued and unpaid interest and additional interest, if any, up to but not including the date of redemption. Holders have the right to require us to repurchase all or a portion of the 2023 Convertible Notes on November 22, 2009, 2013 and 2018, at 100% of their principal amount plus any accrued and unpaid interest. We have the right to repurchase the 2023 Convertible Senior Notes with cash, shares of our common stock, or a combination of cash and our common stock.

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Item 6. Selected Financial Data
 
Selected Consolidated Financial Data
                                           
Years Ended December 31,

2003 2002 2001 2000 1999





(In thousands, except earnings per share)
Statement of Operations data:
                                       
Total revenue
  $ 8,919,539     $ 7,391,861     $ 6,714,929     $ 2,374,695     $ 888,328  
     
     
     
     
     
 
Income before discontinued operations and cumulative effect of a change in accounting principle
  $ 109,753     $ 53,690     $ 582,966     $ 332,754     $ 89,000  
Discontinued operations, net of tax
    (8,674 )     64,928       39,490       36,330       17,650  
Cumulative effect of a change in accounting principle
    180,943             1,036              
     
     
     
     
     
 
Net income
  $ 282,022     $ 118,618     $ 623,492     $ 369,084     $ 106,650  
     
     
     
     
     
 
Basic earnings per common share:
                                       
 
Income before discontinued operations and cumulative effect of a change in accounting principle
  $ 0.28     $ 0.15     $ 1.92     $ 1.18     $ 0.39  
 
Discontinued operations, net of tax
    (0.02 )     0.18       0.13       0.13       0.08  
 
Cumulative effect of a change in accounting principle, net of tax
    0.46                          
     
     
     
     
     
 
 
Net income
  $ 0.72     $ 0.33     $ 2.05     $ 1.31     $ 0.47  
     
     
     
     
     
 
Diluted earnings per common share:
                                       
 
Income before discontinued operations and cumulative effect of a change in accounting principle
  $ 0.28     $ 0.15     $ 1.69     $ 1.07     $ 0.38  
 
Discontinued operations, net of tax provision
    (0.02 )     0.18       0.11       0.11       0.07  
 
Cumulative effect of a change in accounting principle, net of tax
    0.45                          
     
     
     
     
     
 
 
Net income
  $ 0.71     $ 0.33     $ 1.80     $ 1.18     $ 0.45  
     
     
     
     
     
 
Balance Sheet data:
                                       
Total assets
  $ 27,303,932     $ 23,226,992     $ 21,937,227     $ 10,610,232     $ 4,400,902  
Short-term debt and capital lease obligations
    349,128       1,651,448       903,307       64,525       47,470  
Long-term debt and capital lease obligations
    17,328,181       12,462,290       12,490,175       5,018,044       2,214,921  
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts(1)
  $  —     $ 1,123,969     $ 1,122,924     $ 1,122,390     $ 270,713  


(1)  Included in long-term debt as of December 31, 2003. See Note 11 of the Notes to Consolidated Financial Statements for more information.

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Reconciliation of GAAP cash provided from Years Ended December 31,
operating activities to EBITDA, as
adjusted(1): 2003 2002 2001 2000 1999






(In thousands)
Cash provided by operating activities
  $ 290,559     $ 1,068,466     $ 423,569     $ 875,751     $ 314,361  
Less: Changes in operating assets and liabilities, excluding the effects of acquisitions(2)
    (609,840 )     480,193       (359,640 )     277,696       8,213  
Less: Additional adjustments to reconcile net income to net cash provided by operating activities, net(2)
    618,377       469,655       159,717       228,971       199,498  
     
     
     
     
     
 
GAAP net income
    282,022       118,618       623,492       369,084       106,650  
Income from unconsolidated investments in power projects and oil and gas properties
    (76,703 )     (16,552 )     (16,946 )     (28,796 )     (36,593 )
Distributions from unconsolidated investments in power projects and oil and gas properties
    141,627       14,117       5,983       29,979       43,318  
     
     
     
     
     
 
 
Adjusted net income
    346,946       116,183       612,529       370,267       113,375  
Interest expense
    726,103       413,690       196,622       81,890       96,932  
 1/3 of operating lease expense
    37,357       37,007       33,173       21,154       11,198  
Distributions on trust preferred securities
    46,610       62,632       62,412       45,076       2,565  
Provision (benefit) for income taxes
    (134 )     (14,945 )     297,614       231,419       61,523  
Depreciation, depletion and amortization expense
    608,182       474,225       319,884       199,763       112,665  
Interest expense, provision for income taxes and depreciation from discontinued operations
    3,390       92,544       90,601       74,163       35,093  
     
     
     
     
     
 
EBITDA, as adjusted(1)
  $ 1,768,454     $ 1,181,336     $ 1,612,835     $ 1,023,732     $ 433,351  
     
     
     
     
     
 


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

For the year ended December 31, 2003 EBITDA, as adjusted, includes a $180.9 million (net of tax) gain from the cumulative effect of a change in accounting principle and a $278.6 million gain from the repurchase of debt, offset by approximately $273.0 million of certain charges, consisting primarily of foreign currency translation losses, equipment cancellation and impairment costs, certain mark-to-market activity, and minority interest expense, some of which required, or will require cash settlement. EBITDA, as adjusted for the year ended December 31, 2002 includes a non-cash equipment cancellation charge of $404.7 million, a $118.0 million gain on the repurchase of debt, and approximately $55.0 million of certain charges, some of which required, or will require cash settlement.

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

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Selected Operating Information

                                             
Years Ended December 31,

2003 2002 2001 2000 1999





(Dollars in thousands, except production and pricing data)
Power Plants(1):
                                       
Electricity and steam (“E&S”) revenues:
                                       
 
Energy
  $ 3,361,095     $ 2,273,524     $ 1,701,533     $ 1,220,684     $ 452,909  
 
Capacity
    844,195       781,127       525,174       376,085       252,565  
 
Thermal and other
    490,454       167,551       158,617       99,297       54,851  
     
     
     
     
     
 
   
Subtotal
  $ 4,695,744     $ 3,222,202     $ 2,385,324     $ 1,696,066     $ 760,325  
Spread on sales of purchased power(2)
    24,118       527,546       345,834       11,262       2,476  
     
     
     
     
     
 
Adjusted E&S revenues
  $ 4,719,862     $ 3,749,748     $ 2,731,158     $ 1,707,328     $ 762,801  
Megawatt hours produced
    82,423,422       72,767,280       42,393,726       22,749,588       14,802,709  
All-in electricity price per megawatt hour generated
  $ 57.26     $ 51.53     $ 64.42     $ 75.05     $ 51.53  


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

      Set forth above is certain selected operating information for our power plants and, through May 1999 for our geothermal steam fields at The Geysers, for which results are consolidated in our statements of operations. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenues include, besides traditional capacity payments, other revenues such as Reliability Must Run and Ancillary Service revenues. The information set forth under thermal and other revenue consists of host steam sales and other thermal revenue, including our geothermal steam field revenues prior to our acquisition of the PG&E geothermal power plants at The Geysers on May 7, 1999.

      Set forth below is a table summarizing the dollar amounts and percentages of our total revenue for the years ended December 31, 2003, 2002, and 2001, that represent purchased power and purchased gas sales for hedging and optimization and the costs we incurred to purchase the power and gas that we resold during these periods (in thousands, except percentage data):

                         
Year Ended December 31,

2003 2002 2001



Total revenue
  $ 8,919,539     $ 7,391,861     $ 6,714,929  
Sales of purchased power for hedging and optimization(1)
    2,714,187       3,145,991       3,332,412  
As a percentage of total revenue
    30.4 %     42.6 %     49.6 %
Sale of purchased gas for hedging and optimization
    1,320,902       870,466       526,517  
As a percentage of total revenue
    14.8 %     11.8 %     7.8 %
Total cost of revenue (“COR”)
    8,082,838       6,385,208       5,491,800  
Purchased power expense for hedging and optimization(1)
    2,690,069       2,618,445       2,986,578  
As a percentage of total COR
    33.3 %     41.0 %     54.4 %
Purchased gas expense for hedging and optimization
    1,279,568       821,065       492,587  
As a percentage of total COR
    15.8 %     12.9 %     9.0 %


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

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      The primary reasons for the significant levels of these sales and costs of revenue items include: (a) significant levels of hedging, balancing and optimization activities by our CES risk management organization; (b) particularly volatile markets for electricity and natural gas, which prompted us to frequently adjust our hedge positions by buying power and gas and reselling it; (c) the accounting requirements under Staff Accounting Bulletin (“SAB”) No. 101, “Revenue Recognition in Financial Statements,” and Emerging Issues Task Force (“EITF”) Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” under which we show most of our hedging contracts on a gross basis (as opposed to netting sales and cost of revenue); and (d) rules in effect throughout 2001 and 2002 associated with the NEPOOL market in New England, which require that all power generated in NEPOOL be sold directly to the Independent System Operator (“ISO”) in that market; we then buy from the ISO to serve our customer contracts. Generally accepted accounting principles required us to account for this activity, which applies to three of our merchant generating facilities, as the aggregate of two distinct sales and one purchase until our prospective adoption of EITF Issue No. 03-11 on October 1, 2003. This gross basis presentation increased revenues but not gross profit. The table below details the financial extent of our transactions with NEPOOL for all financial periods prior to the adoption of EITF Issue No. 03-11. Our entrance into the NEPOOL market began with our acquisition of the Dighton, Tiverton, and Rumford facilities on December 15, 2000.

                           
Nine Months Ended Year Ended December 31,
September 30,
2003 2002 2001



(In thousands)
Sales to NEPOOL from power we generated
  $ 258,945     $ 294,634     $ 285,706  
Sales to NEPOOL from hedging and other activity
    117,345       106,861       165,416  
     
     
     
 
 
Total sales to NEPOOL
  $ 376,290     $ 401,495     $ 451,122  
Total purchases from NEPOOL
  $ 310,025     $ 360,113     $ 413,875  


      (The statement of operations data information and the balance sheet data information contained in the Selected Financial Data is derived from the audited Consolidated Financial Statements of Calpine Corporation and Subsidiaries. See the Notes to the Consolidated Financial Statements and Item 7. “Management’s Discussion and Analysis of Financial Condition — Results of Operation” for additional information.)

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

Overview

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

      Our key opportunities and challenges include:

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

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      Since the latter half of 2001, there has been a significant contraction in the availability of capital for participants in the energy sector. This has been due to a range of factors, including uncertainty arising from the collapse of Enron Corp. and a perceived near-term surplus supply of electric generating capacity. These factors have continued through 2003 and into 2004, during which decreased spark spreads have adversely impacted our liquidity and earnings. While we have been able to continue to access the capital and bank credit markets on attractive terms, we recognize that the terms of financing available to us in the future may not be attractive. To protect against this possibility and due to current market conditions, we scaled back our capital expenditure program to enable us to conserve our available capital resources. We have recently completed the refinancing of Calpine Generating Company (“CalGen,” formerly CCFC II) revolving construction facility indebtedness of approximately $2.3 billion as further discussed in Note 27 of the Notes to Consolidated Financial Statements. Remaining debt maturities are relatively modest in 2004 and 2005 as shown in Note 17 of the Notes to Consolidated Financial Statements.

      Set forth below are the Results of Operations for the years ending December 31, 2003, 2002, and 2001.

Results of Operations

 
Year Ended December 31, 2003, Compared to Year Ended December 31, 2002 (in millions, except for unit pricing information, percentages and MW volumes).
 
Revenue
                                 
2003 2002 $ Change % Change




Total revenue
  $ 8,919.5     $ 7,391.9     $ 1,527.6       20.7 %

      The increase in total revenue is explained by category below.

                                   
2003 2002 $ Change % Change




Electricity and steam revenue
  $ 4,695.7     $ 3,222.2     $ 1,473.5       45.7 %
Sales of purchased power for hedging and optimization
    2,714.2       3,146.0       (431.8 )     (13.7 )%
     
     
     
         
 
Total electric generation and marketing revenue
  $ 7,409.9     $ 6,368.2     $ 1,041.7       16.4 %
     
     
     
         

      Electricity and steam revenue increased as we completed construction and brought into operation 5 new baseload power plants, 7 new peaker facilities and 3 project expansions in 2003. Average megawatts in operation of our consolidated plants increased by 40% to 20,092 MW while generation increased by 13%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 53% in 2003 from 65% in 2002 primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas, and to a lesser extent due to unscheduled outages caused by equipment problems at certain of our plants in the first half of 2003. Average realized electricity prices, before the effects of hedging, balancing and optimization, increased to $56.97/MWh in 2003 from $44.28/MWh in 2002.

      Sales of purchased power for hedging and optimization decreased during 2003, due primarily to adoption of EITF Issue No. 03-11 and lower realized prices on term power hedges.

                                   
2003 2002 $ Change % Change




Oil and gas sales
  $ 107.7     $ 120.9     $ (13.2 )     (10.9 )%
Sales of purchased gas for hedging and optimization
    1,320.9       870.5       450.4       51.7 %
     
     
     
         
 
Total oil and gas production and marketing revenue
  $ 1,428.6     $ 991.4     $ 437.2       44.1 %
     
     
     
         

      Oil and gas sales are net of internal consumption, which is eliminated in consolidation. Internal consumption increased by $228.7 to $409.1 in 2003. Before intercompany eliminations, oil and gas sales increased by $215.4 to $516.7 in 2003 from $301.3 in 2002 due primarily to 76% higher average realized natural gas pricing in 2003.

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      Sales of purchased gas for hedging and optimization increased during 2003 due to higher prices for natural gas.

                                   
2003 2002 $ Change % Change




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

      Realized revenue on power and gas mark-to-market activity represents the portion of mark-to-market contracts actually settled.

      Mark-to-market activities, which are shown on a net basis, results from general market price movements against our open commodity derivative positions, including positions accounted for as trading under EITF Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”) and other mark-to-market activities. These commodity positions represent a small portion of our overall commodity contract position. Realized revenue represents the portion of contracts actually settled, while unrealized revenue represents changes in the fair value of open contracts, and the ineffective portion of cash flow hedges. The decrease in mark-to-market activities revenue in 2003 is due primarily to a $27.3 reduction in value of option contracts associated with a spark spread protection arrangement for the CCFC I financing and a decline in the value of a long-term spark spread option contract accounted for on a mark-to-market basis under SFAS No. 133.

                                 
2003 2002 $ Change % Change




Other revenue
  $ 107.5     $ 10.8     $ 96.7       895.4 %

      Other revenue increased during 2003 primarily due to a $67.3 reduction in liability in connection with our settlement with Enron, primarily related to the termination of commodity contracts following the Enron bankruptcy. We also realized $23.6 of revenue from Thomassen Turbine Systems (“TTS”), which we acquired in February 2003. Power Systems Mfg., LLC (“PSM”) revenues increased $6.2 in 2003 as compared to 2002.

 
Cost of Revenue
                                 
2003 2002 $ Change % Change




Total cost of revenue
  $ 8,082.8     $ 6,385.2     $ 1,697.6       26.6 %

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

                                   
2003 2002 $ Change % Change




Plant operating expense
  $ 679.0     $ 506.0     $ 173.0       34.2 %
Royalty expense
    24.9       17.6       7.3       41.5 %
Purchased power expense for hedging and optimization
    2,690.1       2,618.4       71.7       2.7 %
     
     
     
         
 
Total electrical generation and marketing expense
  $ 3,394.0     $ 3,142.0     $ 252.0       8.0 %
     
     
     
         

      Plant operating expense increased due to 5 new baseload power plants, 7 new peaker facilities and 3 expansion projects completed during 2003. Additionally, we experienced higher transmission expenses and higher maintenance expense as several newer plants underwent their first scheduled hot gas path overhauls which generally first occur after a plant has been in operation for three years.

      Royalty expense increased primarily due to an increase in electric revenues at The Geysers geothermal plants.

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

                                     
2003 2002 $ Change % Change




Oil and gas production expense
  $ 86.9     $ 84.4     $ 2.5       3.0 %
Oil and gas exploration expense
    19.3       13.1       6.2       47.3 %
     
     
     
         
 
Oil and gas operating expense
    106.2       97.5       8.7       8.9 %
Purchased gas expense for hedging and optimization
    1,279.6       821.1       458.5       55.8 %
     
     
     
         
   
Total oil and gas operating and marketing expense
  $ 1,385.8     $ 918.6     $ 467.2       50.9 %
     
     
     
         

      Oil and gas production expense increased primarily due to higher production taxes and higher gas treating and transportation costs, which were primarily the result of higher oil and gas prices plus an increase in operating cost and an increase in the average Canadian dollar foreign exchange rate in 2003.

      Oil and gas exploration expense increased primarily as a result of $9.5 in dry hole drilling expenses in 2003 compared to $5.0 in 2002.

      Purchased gas expense for hedging and optimization increased during 2003 due to higher prices for gas in 2003.

                                 
2003 2002 $ Change % Change




Fuel expense
  $ 2,564.7     $ 1,752.9     $ 811.8       46.3 %

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

                                 
2003 2002 $ Change % Change




Depreciation, depletion and amortization expense
  $ 583.9     $ 453.4     $ 130.5       28.8 %

      Depreciation, depletion and amortization expense increased in 2003 primarily due to additional power facilities in consolidated operations subsequent to 2002. Additionally, in 2003 we incurred $18.2 in accelerated depletion expense for oil and gas impairment charges compared to $6.0 in 2002.

                                 
2003 2002 $ Change % Change




Operating lease expense
  $ 112.1     $ 111.0     $ 1.1       1.0 %

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

                                 
2003 2002 $ Change % Change




Other cost of revenue
  $ 42.3     $ 7.3     $ 35.0       479.5 %

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

 
(Income)/Expenses
                                 
2003 2002 $ Change % Change




(Income) from unconsolidated investments in power projects and oil and gas properties
  $ (76.7 )   $ (16.6 )   $ 60.1       362.0 %

      The increase in income is primarily due to a $52.8 gain recognized on the termination of the tolling agreement with Aquila Merchant Services, Inc. (“AMS”) on the Acadia Energy Center (see Note 7 of the

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Notes to Consolidated Financial Statements). Additionally, we realized a pre-tax gain of $7.1 from the sale of our interest in the Gordonsville Energy Center to Dominion Virginia Power.
                                 
2003 2002 $ Change % Change




Equipment cancellation and impairment cost
  $ 64.4     $ 404.7     $ (340.3 )     (84.1 )%

      In 2003 the pre-tax equipment cancellation and impairment charge was primarily a result of cancellation costs related to three turbines and three heat recovery steam generators and impairment charges related to four turbines. The pre-tax charge of $404.7 in 2002 was the result of turbine and other equipment order cancellation charges and related write-offs as a result of our scale-back in construction and development activities. For further information, see Note 4 of the Notes to Consolidated Financial Statements.

                                 
2003 2002 $ Change % Change




Long-term service agreement cancellation charges
  $ 16.4     $     $ 16.4       100.0 %

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

                                 
2003 2002 $ Change % Change




Project development expense
  $ 21.8     $ 67.0     $ (45.2 )     (67.5 )%

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

                                 
2003 2002 $ Change % Change




Sales, general and administrative expense
  $ 265.7     $ 229.0     $ 36.7       16.0 %

      Sales, general and administrative expense increased due to $16.1 of stock-based compensation expense associated with our adoption of SFAS No. 123, “Accounting for Stock-Based Compensation,” effective January 1, 2003, on a prospective basis. $7.1 of the increase is attributable to the acquisition of TTS in February 2003. Other causes of the increase include an increase of $7.3 in insurance costs and an increase in write-off of excess office space of $6.2. Sales, general and administrative expense expressed per MWh of generation increased to $3.22/ MWh in 2003 from $3.15/ MWh in 2002, due to a lower average capacity factor in 2003.

                                 
2003 2002 $ Change % Change




Interest expense
  $ 726.1     $ 413.7     $ 312.4       75.5 %

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

                                 
2003 2002 $ Change % Change




Distributions on trust preferred securities
  $ 46.6     $ 62.6     $ (16.0 )     25.6 %

      As a result of the deconsolidation of the three Calpine Capital Trusts upon adoption of FIN 46-R as of October 1, 2003, the distributions paid on the Trust Preferred Securities during the fourth quarter of 2003

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were no longer recorded on our books and were replaced by interest expense on our debt to the Calpine Capital Trusts, thus explaining the decrease in distributions on trust preferred securities in 2003.
                                 
2003 2002 $ Change % Change




Interest (income)
  $ (39.7 )   $ (43.1 )   $ 3.4       (7.9 )%

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

                                 
2003 2002 $ Change % Change




Minority interest expense
  $ 27.3     $ 2.7     $ 24.6       911.1 %

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

                                 
2003 2002 $ Change % Change




(Income) from repurchase of various issuances of debt
  $ (278.6 )   $ (118.0 )   $ (160.6 )     136.1 %

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

                                 
2003 2002 $ Change % Change




Other (income)
  $ (46.1 )   $ (34.2 )   $ (11.9 )     34.8 %

      Other income during 2003 is comprised primarily of gains of $62.2 on the sale of oil and gas assets to Calpine Natural Gas Trust and $57.0 from the termination of a power contract at our RockGen Energy Center. This income was offset primarily by $33.3 of foreign exchange translation losses and $12.5 of letter of credit fees. The foreign exchange translation losses recognized into income were mainly due to a strong Canadian dollar during 2003. In 2002 the primary contribution to other income was a $41.5 gain on the termination of a power sales agreement.

                                 
2003 2002 $ Change % Change




(Benefit) for income taxes
  $ (0.1 )   $ (14.9 )   $ 14.8       (99.3 )%

      During 2003 the effective tax rate increased to (0.1)% from (38.6)% from 2002. This effective rate variance is due to the inclusion of significant permanent items in the calculation of the effective rate, which are fixed in amount and have a significant effect on the effective tax rates as such items become more material to net income.

                                 
2003 2002 $ Change % Change




Discontinued operations, net of tax
  $ (8.7 )   $ 64.9     $ (73.6 )     (113.4 )%

      The 2003 discontinued operations activity included the effects of an agreement to sell our 50% interest in the Lost Pines 1 Energy Center, the sale of our Alvin South Field oil and gas assets and the sale of our specialty data center engineering business, reflecting the soft market for data centers for the foreseeable future. The sale of the Lost Pines 1 Energy Center closed in January 2004. The 2002 discontinued operations activity included the Lost Pines 1 Energy Center, Alvin South Field oil and gas assets, our specialty data center engineering business, and the DePere Energy Center, as well as the Drakes Bay Field, British Columbia and Medicine River oil and gas assets. With the exception of the Lost Pines 1 Energy Center, Alvin South Field oil and gas assets and our specialty data center engineering business, the sales of these assets were completed by

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December 31, 2002; therefore, their results are not included in the 2003 activity. For more information about discontinued operations, see Note 10 of the Notes to Consolidated Financial Statements.
                                 
2003 2002 $ Change % Change




Cumulative effect of a change in accounting principle, net of tax
  $ 180.9     $     $ 180.9       100.0 %

      The gain from the cumulative effect of a change in accounting principle includes three items: (1) a gain of $181.9, net of tax effect, from the adoption of Derivatives Implementation Group (“DIG”) Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature;” (2) a loss of $1.5 associated with the adoption of FIN 46-R and the deconsolidation of the three Calpine Capital Trusts which issued the HIGH TIDES. The loss of $1.5 represents the reversal of a gain, net of tax effect, recognized prior to the adoption of FIN 46-R on our repurchase of $37.5 of the value of HIGH TIDES by issuing Calpine Corporation common stock valued at $35.0; and (3) a gain of $0.5, net of tax effect, from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.”

 
Net Income
                                 
2003 2002 $ Change % Change




Net income
  $ 282.0     $ 118.6     $ 163.4       137.8 %

      Our growing portfolio of operating power generation facilities contributed to a 13% increase in electric generation production for the year ended December 31, 2003, compared to the same period in 2002. Electric generation and marketing revenue increased 16.4% for the year ended December 31, 2003, as electricity and steam revenue increased by $1,473.5 or 45.7%, as a result of the higher production and higher electricity prices. This was partially offset by a decline in sales of purchased power for hedging and optimization. Operating results for the year ended December 31, 2003, reflect a decrease in average spark spreads per megawatt-hour compared with the same period in 2002. While we experienced an increase in realized electricity prices in 2003, this was more than offset by higher fuel expense. At the same time, higher realized oil and gas pricing resulted in an increase in oil and gas production margins compared to the prior period. In 2003 we recorded other revenue of $67.3 in connection with our settlement with Enron, primarily related to the termination of commodity contracts following the Enron bankruptcy.

      Plant operating expense, interest expense and depreciation were higher due to the additional plants in operation. Gross profit for the year ended December 31, 2003, decreased approximately 16.9%, compared to the same period in 2002. During 2003 overall financial results significantly benefited from $278.6 of net pre-tax gains recorded in connection with the repurchase of various issuances of debt and preferred securities at a discount, and a gain of $52.8 from the termination of the AMS power contract at the Acadia Energy Center, a gain of $57.0 from the termination of a power contract at the RockGen Energy Center, a gain of $62.2 from the sale of oil and gas assets to the Calpine Natural Gas Trust and an after-tax gain of $180.9 due to the cumulative effect of changes in accounting principle.

              Year Ended December 31, 2002, Compared to Year Ended December 31, 2001 (in millions, except for unit pricing information, percentages and MW volumes).

 
Revenue
                                 
2002 2001 $ Change % Change




Total revenue
  $ 7,391.9     $ 6,714.9     $ 677.0       10.1 %

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      The increase in total revenue is explained by category below.

                                   
2002 2001 $ Change % Change




Electricity and steam revenue
  $ 3,222.2     $ 2,385.3     $ 836.9       35.1 %
Sales of purchased power for hedging and optimization
    3,146.0       3,332.4       (186.4 )     (5.6 )%
     
     
     
         
 
Total electric generation and marketing revenue
  $ 6,368.2     $ 5,717.7     $ 650.5       11.4 %
     
     
     
         

      Electricity and steam revenue increased as we completed construction and brought into operation 11 new baseload power plants, 7 new peaker facilities and 3 project expansions in 2002. Average megawatts in operation of our consolidated plants increased by 84% to 14,346 MW while generation increased by 72%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 65% in 2002 from 70% in 2001 primarily because we operated fewer hours, especially in off-peak periods, than in 2001, due to the increased occurrence of unattractive market spark spreads in certain areas. The overall increase in generation was partially offset by lower average pricing, which dropped 21% as average realized electricity prices, before the effects of hedging, balancing and optimization, declined to $44.28/ MWh in 2002 from $56.27/ MWh in 2001.

      Sales of purchased power for hedging and optimization decreased during 2002, due to lower power prices and increased industry-wide credit restrictions on risk management activities in 2002.

                                   
2002 2001 $ Change % Change




Oil and gas sales
  $ 120.9     $ 286.2     $ (165.3 )     (57.8 )%
Sales of purchased gas for hedging and optimization
    870.5       526.5       344.0       65.3 %
     
     
     
         
 
Total oil and gas production and marketing revenue
  $ 991.4     $ 812.7     $ 178.7       22.0 %
     
     
     
         

      Oil and gas sales are net of internal consumption, which increased by $60.3 to $180.4 in 2002. Internal consumption is eliminated in consolidation. Additionally oil and gas sales were reduced by reclassification of $76.5 in 2002 and $136.4 in 2001 to discontinued operations for assets sold. Before inter-company eliminations and reclassifications to discontinued operations, oil and gas sales decreased by $164.9 due primarily to 31% lower average realized natural gas pricing in 2002.

      Sales of purchased gas for hedging and optimization increased during 2002 as we brought into operation new generation and the related level of physical gas optimization and balancing activity increased to support the new generation.

                                   
2002 2001 $ Change % Change




Realized gain on power and gas transactions, net
  $ 26.1     $ 29.1     $ (3.0 )     (10.3 )%
Unrealized gain (loss) on power and gas transactions, net
    (4.6 )     122.6       (127.2 )     (103.8 )%
     
     
     
         
 
Total mark-to-market activities, net
  $ 21.5     $ 151.7     $ (130.2 )     (85.8 )%
     
     
     
         

      Realized revenue on power and gas trading and other mark-to-market activity represents the portion of contracts actually settled.

      In the year ended December 31, 2001, we recognized a net unrealized mark-to-market gain of $68.5 from power contracts in a market area where we did not have generation assets and approximately $66 of gains from various other power and gas transactions. The shift from unrealized mark-to-market gain in 2001 to unrealized loss in 2002 reflects increased industry-wide credit and liquidity restrictions on risk management and trading activities, which caused us to greatly curtail trading activities so that our available capacity could be concentrated on hedging activities associated with our existing physical power and gas assets. Also, in 2002 we

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established liquidity reserves of approximately $6.7 against unrealized mark-to-market revenue to take into account reduced liquidity and the resulting increase in bid/ask spreads in the energy industry.
                                 
2002 2001 $ Change % Change




Other revenue
  $ 10.8     $ 32.7     $ (21.9 )     (67.0 )%

      The decrease in 2002 is due primarily to one-time license fee revenue of $10.6 recognized in 2001 by our wholly owned subsidiary PSM and due to $5.9 in commissioning services in 2001 related to an unconsolidated construction project.

 
Cost of Revenue
                                 
2002 2001 $ Change % Change




Total cost of revenue
  $ 6,385.2     $ 5,491.8     $ 893.4       16.3 %

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

                                   
2002 2001 $ Change % Change




Plant operating expense
  $ 506.0     $ 324.0     $ 182.0       56.2 %
Royalty expense
    17.6       27.5       (9.9 )     (36.0 )%
Purchased power expense for hedging and optimization
    2,618.4       2,986.6       (368.2 )     (12.3 )%
     
     
     
         
 
Total electrical generation and marketing expense
  $ 3,142.0     $ 3,338.1     $ (196.1 )     (5.9 )%
     
     
     
         

      Plant operating expense increased due to 11 new baseload power plants, 7 new peaker facilities and 3 expansion projects completed during 2002, but, expressed per MWh of generation, it decreased from $7.64/MWh to $6.95/MWh as economies of scale were realized due to the increase in the average size of our plants.

      Royalty expense decreased due to a decrease in revenue at The Geysers geothermal plants due to lower electricity prices.

      The decrease in purchased power expense for hedging and optimization was caused by lower power prices and by increased industry-wide credit restrictions on risk management activities in 2002.

                                     
2002 2001 $ Change % Change




Oil and gas production expense
  $ 84.4     $ 76.9     $ 7.5       9.8 %
Oil and gas exploration expense
    13.1       13.6       (0.5 )     (3.7 )%
     
     
     
         
 
Oil and gas operating expense
    97.5       90.5       7.0       7.7 %
Purchased gas expense for hedging and optimization
    821.1       492.6       328.5       66.7 %
     
     
     
         
   
Total oil and gas operating and marketing expense
  $ 918.6     $ 583.1     $ 335.5       57.5 %
     
     
     
         

      Oil and gas production expense increased primarily due to increases in gas treating and transportation costs coupled with higher lifting costs due to a 1% increase in equivalent volumes and due to inflation.

      Oil and gas exploration expense increased as we incurred $5.0 in dry hole drilling expenses in 2002 compared to $3.6 in 2001.

      Purchased gas expense for hedging and optimization increased during 2002 as we brought into operation new generation and the related level of physical gas optimization and balancing activity increased to support the new generation.

                                 
2002 2001 $ Change % Change




Fuel expense
  $ 1,752.9     $ 1,150.8     $ 602.1       52.3 %

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      Fuel expense increased in 2002 due to an 85% increase in gas-fired megawatt hours generated which was partially offset by significantly lower gas prices, increased usage of internally produced gas and an improved average heat rate of our generation portfolio in 2002.

                                 
2002 2001 $ Change % Change




Depreciation, depletion and amortization expense
  $ 453.4     $ 309.4     $ 144.0       46.5 %

      Depreciation, depletion and amortization expense increased primarily due to additional power facilities in consolidated operations during 2002 as compared to 2001.

                                 
2002 2001 $ Change % Change




Operating lease expense
  $ 111.0     $ 99.5     $ 11.5       11.6 %

      Operating lease expense increased due to the RockGen, Aidlin and South Point sale/leaseback transactions entered into during 2001.

                                 
2002 2001 $ Change % Change




Other cost of revenue
  $ 7.3     $ 10.9     $ (3.6 )     (33.0 )%

      The decrease is primarily due to $4.1 less expense at PSM, as combustion parts sales to third parties decreased in 2002.

 
(Income)/ Expense
                                 
2002 2001 $ Change % Change




(Income) from unconsolidated investments in power projects and oil and gas properties
  $ (16.6 )   $ (16.9 )   $ 0.3       (1.8 )%

      The modest decrease is primarily due to approximately $14.6 earned from our investment in the Acadia facility, which commenced operations in August 2002, being offset by $4.0 less revenue from our investment in Lockport, which we sold in the first quarter of 2002, losses at Androscoggin and Grays Ferry in 2002 due to lower spark spreads, and a $6.7 decrease in interest income from loans to power projects resulting from the extinguishment of a note from the Delta Energy Center, LLC after we acquired the remaining 50% interest in November 2001.

                                 
2002 2001 $ Change % Change




Equipment cancellation impairment cost
  $ 404.7     $     $ 404.7        

      The pre-tax charge of $404.7 in the year ended December 31, 2002, was a result of turbine and other equipment order cancellation charges and related write-offs as a result of our revised construction and development program. For further information, see Note 4 of the Notes to Consolidated Financial Statements.

                                 
2002 2001 $ Change % Change




Project development expense
  $ 67.0     $ 35.9     $ 31.1       86.6 %

      Project development expense increased primarily because we expensed $34.8 of previously capitalized costs due to the cancellation or indefinite suspension of certain development projects. Additionally, we stopped capitalizing costs on certain development projects placed on hold.

                                 
2002 2001 $ Change % Change




Sales, general and administrative expense
  $ 229.0     $ 150.5     $ 78.5       52.2 %

      The increase was attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations. In addition we incurred $13.7 of severance costs and the write off of excess office space due to the reduction of our work force during 2002. Sales, general and administrative expense expressed per MWh of generation decreased to $3.15/MWh in 2002 from $3.55/MWh in 2001.

                                 
2002 2001 $ Change % Change




Merger expense
  $     $ 41.6     $ (41.6 )      

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      The merger expense of $41.6 in the year ended December 31, 2001, was a result of the pooling-of-interests transaction with Encal Energy Ltd. that closed on April 19, 2001.

                                 
2002 2001 $ Change % Change




Interest expense
  $ 413.7     $ 196.6     $ 217.1       110.4 %

      Interest expense increased primarily due to the issuance of the 4% Convertible Senior Notes Due 2006 and additional senior notes issued in the second half of 2001 and due to the new plants entering commercial operations (at which point capitalization of interest expense ceases). Interest capitalized increased from $498.7 for the year ended December 31, 2001, to $575.5 for the year ended December 31, 2002, due to a larger construction portfolio during most of 2002. We expect that interest expense will continue to increase and the amount of interest capitalized will decrease in future periods as our plants in construction are completed, and, to a lesser extent, as a result of suspension of certain of our development projects and suspension of capitalization of interest thereon.

                                 
2002 2001 $ Change % Change




Interest (income)
  $ (43.1 )   $ (72.4 )   $ 29.3       (40.5 )%

      The decrease in interest income is due primarily to lower cash balances and lower interest rates in 2002.

                                 
2002 2001 $ Change % Change




(Income) from the repurchase of various issuances of debt
  $ (118.0 )   $ (11.9 )   $ (106.1 )     891.6 %

      In 2002 the primary contribution was the recognition of $114.8 of net pre-tax gain from the receipt of Senior Notes, which were trading at a discount to face value, as partial consideration for British Columbia asset sales. In 2001 the $11.9 represents the net pre-tax gain on extinguishment of debt from repurchasing $122.0 aggregate principal amount of our Zero Coupon Convertible Debentures Due 2021 at a discount.

                                 
2002 2001 $ Change % Change




Other (income)
  $ (34.2 )   $ (41.8 )   $ (7.6 )     18.2 %

      In 2002 the primary contribution to other income was a $41.5 gain on the termination of a power sales agreement. In 2001 other income resulted from contract settlements and gains from the sales of certain assets.

                                 
2002 2001 $ Change % Change




Provision (benefit) for income taxes
  $ (14.9 )   $ 297.6     $ (312.5 )     (105 )%

      The decrease is primarily due to the significant decrease in income from continuing operations from 2001 to 2002. In 2002 the income tax benefit was caused by a full year of permanent tax items arising out of our cross border financings in 2001. See Note 18 of the Notes to Consolidated Financial Statements for further discussions.

                                 
2002 2001 $ Change % Change




Discontinued operations, net of tax
  $ 64.9     $ 39.5     $ 25.4       64.3 %

      The increase in 2002 results reflects approximately $56.5 of gains relating to the sale of oil and gas assets and the DePere Energy Center, partially offset by lower earnings from these discontinued operations as they did not contribute to earnings for the full year in 2002 and due to higher gas prices in 2001. See Note 10 of the Notes to Consolidated Financial Statements for further discussion.

                                 
2002 2001 $ Change % Change




Cumulative effect of a change in accounting principle, net of tax
  $     $ 1.0     $ (1.0 )      

      In 2001 the $1.0 of additional income (net of tax of $0.7), is due to the adoption of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

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Net Income
                                 
2002 2001 $ Change % Change




Net income
  $ 118.6     $ 623.5     $ (504.9 )     (81.0 )%

      The decrease in net income reflects a $216.5 decrease in gross profit resulting primarily from lower spark spreads per MWh, which more than offset the positive effects of the increase in generation volume. It also reflects $130.2 lower mark-to-market revenue in 2002. Additionally, we recorded $404.7 in turbine cancellation and impairment charges in 2002, and interest expense increased by $217.1 as more plants entered commercial operations and interest ceased being capitalized on them at that time. Finally, we experienced $78.5 higher general and administrative expense in 2002 due to the dramatic growth in our operations. These factors were mitigated by a $312.5 reduction in income tax expense and a $114.8 net pre-tax gain from receipt of senior notes in consideration for an asset sale discussed above.

Liquidity and Capital Resources

      Our business is capital intensive. Our ability to capitalize on growth opportunities is dependent on the availability of capital on attractive terms. The availability of such capital in today’s environment is uncertain. To date, we have obtained cash from our operations; borrowings under our term loan and revolving credit facilities; issuance of debt, equity, trust preferred securities and convertible debentures; proceeds from sale/leaseback transactions; sale or partial sale of certain assets; contract monetizations and project financing. We have utilized this cash to fund our operations, service or prepay debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing, optimization and trading activities at CES, and meet our other cash and liquidity needs. Our strategy is also to reinvest our cash from operations into our business development and construction program or to use it to reduce debt, rather than to pay cash dividends. As discussed below, we have a liquidity-enhancing program underway to fund the completion of our current construction portfolio, for refinancing and for general corporate purposes.

      In May and June 2003 our $950 million in secured working capital revolving credit facilities matured and were extended, ultimately to July 16, 2003. On July 16, 2003, we closed a $3.3 billion term loan and second-priority senior secured notes offering (the “July 2003 offerings”), entered into agreements for a new $500 million working capital facility which is composed of a first-priority senior secured two-year, $300 million working capital revolver and a first-priority senior secured four-year, $200 million term loan and repaid the outstanding balance on the revolving credit facilities. We also repaid the $949.6 million in funded borrowings outstanding under our $1.0 billion secured term credit facility which was to mature in May 2004 with proceeds of the July 2003 offerings. We have also repurchased nearly $1.5 billion aggregate principal amount of our outstanding senior notes and HIGH TIDES in 2003 and 2004 primarily with proceeds of the July 2003 offerings and also through equity swaps.

      In November 2003 our $1.0 billion secured revolving construction financing facility through CCFC I was scheduled to mature. On August 14, 2003, CCFC I and another of our wholly owned subsidiaries, CCFC Finance Corp., closed on a $750.0 million institutional term loan and secured notes offering. On September 25, 2003, CCFC I and CCFC Finance Corp. closed on a $50.0 million secured notes offering, which represented an add-on to the secured notes offering completed on August 14, 2003. Net proceeds from these offerings were used to refinance the majority of the $880.1 million outstanding at the date the facility was repaid. The remainder of that facility was repaid from cash proceeds from the July 2003 offerings.

      In November 2004 our $2.5 billion secured revolving construction financing facility through our wholly owned subsidiary CCFC II (renamed “CalGen”) was scheduled to mature, requiring us to refinance this indebtedness. As of December 31, 2003, there was $2.3 billion outstanding under this facility including $53.2 million of letters of credit. On March 23, 2004, CalGen completed its offering of secured institutional term loans and secured notes, which refinanced the CalGen facility. We realized total proceeds from the offering in the amount of $2.4 billion, before transaction costs and fees. See Item 1. “Business — Recent Developments” for more information regarding this offering.

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      The holders of our 2006 Convertible Senior Notes have a right to require us to repurchase them at 100% of their principal amount plus any accrued and unpaid interest on December 26, 2004. We can effect such a repurchase with cash, shares of Calpine stock or a combination of the two. In 2003 and 2004 we repurchased in open market and privately negotiated transactions approximately $1,126.3 million of the outstanding principal amount of 2006 Convertible Senior Notes, primarily with proceeds of the July 2003 offerings and through equity swaps and with the proceeds of our 2023 Convertible Notes offering, and the February 9, 2004, tender offer, in which we initiated a cash tender offer for all of the outstanding 2006 Convertible Senior Notes for a price of par plus accrued interest. Approximately $409.4 million aggregate principal amount of the 2006 Convertible Senior Notes were tendered pursuant to the tender offer, which expired on March 9, 2004, for which we paid a total of $412.8 million, which included accrued interest of $3.4 million. Currently, 2006 Convertible Senior Notes in the aggregate principal amount of $73.7 million remain outstanding.

      On November 6, 2003, we priced our separate offerings of 2023 Convertible Notes and Second Priority Senior Secured Notes. The latter offering was for $400.0 million of 9.875% Second Priority Senior Secured Notes Due 2011, offered at 98.01% of par. This offering closed on November 18, 2003. We used the net proceeds from this offering to purchase outstanding senior notes. The other offering consisted of $650.0 million of 4.75% Contingent Convertible Senior Notes Due 2023, which included the exercise of $50.0 million of an option to purchase additional 2023 Convertible Notes granted to one of the initial purchasers. The 2023 Convertible Notes are convertible into cash and shares of Calpine common stock at an initial conversion price of $6.50 per share, which represents a 38% premium on the November 6, 2003 New York Stock Exchange closing price of $4.71 per Calpine common share. This offering closed on November 14, 2003. Net proceeds from this offering are being used to repurchase our outstanding 2006 Convertible Senior Notes. In addition, on January 9, 2004, we received funding on an additional $250.0 million aggregate principal amount of the 2023 Convertible Notes pursuant to the exercise in full by one of the initial purchasers of its remaining option to purchase additional 2023 Convertible Notes, the net proceeds of which will be used to repurchase our outstanding 2006 Convertible Senior Notes pursuant to the tender offer described above.

      In addition, $276.0 million of our outstanding HIGH TIDES are scheduled to be remarketed no later than November 1, 2004, $360.0 million of our HIGH TIDES are scheduled to be remarketed no later than February 1, 2005 and $517.5 million of our HIGH TIDES are scheduled to be remarketed no later than August 1, 2005. In the event of a failed remarketing, the relevant HIGH TIDES will remain outstanding as convertible securities at a term rate equal to the treasury rate plus 6% per annum and with a term conversion price equal to 105% of the average closing price of our common stock for the five consecutive trading days after the applicable final failed remarketing termination date. While a failed remarketing of our HIGH TIDES would not have a material effect on our liquidity position, it would impact our calculation of diluted earnings per share and increase our interest expense.

      We expect to have sufficient liquidity from cash flow from operations, borrowings available under lines of credit, access to sale/leaseback and project financing markets, sale or monetization of certain assets and cash balances to satisfy all obligations under our outstanding indebtedness, and to fund anticipated capital expenditures and working capital requirements for the next twelve months.

      Factors that could affect our liquidity and capital resources are also discussed in Item 1. “Business — Risk Factors.”

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

                           
Years Ended December 31,

2003 2002 2001



(In thousands)
Beginning cash and cash equivalents
  $ 579,486     $ 1,594,144     $ 664,722  
Net cash provided by:
                       
 
Operating activities
    290,559       1,068,466       423,569  
 
Investing activities
    (2,515,365 )     (3,837,827 )     (7,240,655 )
 
Financing activities
    2,623,986       1,757,396       7,750,177  
 
Effect of exchange rates changes on cash and cash equivalents
    13,140       (2,693 )     (3,669 )
     
     
     
 
 
Net increase (decrease) in cash and cash equivalents
    412,320       (1,014,658 )     929,422  
     
     
     
 
Ending cash and cash equivalents
  $ 991,806     $ 579,486     $ 1,594,144  
     
     
     
 

      Operating activities for the year ended December 31, 2003, provided net cash of $290.6 million, compared to $1,068.5 million for the same period in 2002. The decrease in operating cash flow between periods is primarily due to the working capital funding requirements. During the year ended December 31, 2003, operating assets and liabilities used approximately $609.8 million, as compared to having provided $480.2 million in the same period last year. The growth in short term assets such as margin deposits and accounts receivable accounted for the majority of this difference. At December 31, 2003, we had posted $188.0 million in net margin deposits as compared to $25.2 million at the end of 2002. The increase in such deposits, which serve as collateral for certain of our commodity transactions that are “out-of-the-money” on a mark-to-market basis, is reflective of movements in commodity prices and a higher mix of margin deposits posted relative to letters of credit (during 2003 the dollar value of letters of credit that we posted as collateral for commodity transactions decreased $91.6 million). In 2003 the increase in the posting of margin deposits constituted a use of funds of $162.8 million, which compares to a $320.3 million source of operating cash flow in 2002 as a result of the decrease in margin deposits during that year. The decrease in margin deposits in 2002 was primarily the result of increased gas prices, which allowed us to post less collateral on certain of our gas contracts.

      Accounts receivable grew by $221.2 million in 2003 from year-end 2002, representing a use of funds. Although average spark spreads were lower in 2003 than in 2002, higher electricity prices and increased electrical generation resulted in higher revenues, and consequently, higher receivables balances. However, in 2002 accounts receivable decreased by $229.2 million from year-end 2001, representing a source of funds as we collected from escrow approximately $222.3 million in 2002 for the PG&E past due pre-petition receivables that were sold to a third party in December 2001.

      Also, in 2003 we received $105.5 million from the Acadia joint venture, following the termination of the power purchase agreement with Aquila Merchant Services, Inc. and the restructuring of our interest in the joint venture, which is included in distributions from unconsolidated investments. See Note 7 of the Notes to Consolidated Financial Statements for further discussion.

      Investing activities for the year ended December 31, 2003, consumed net cash of $2,515.4 million, as compared to $3,837.8 million in the same period of 2002. In both periods capital expenditures represent the majority of investing cash outflows. The decrease between periods is due to the completion of construction on several facilities during 2002 and 2003, and due to our revised capital expenditure program, which reduced capital investments in 2003. Additionally, investing activities for 2003 include a use of $766.8 million for restricted cash, of which approximately $553.3 million is expected to be used to repay outstanding indebtedness within the next year.

      Financing activities for the year ended December 31, 2003, provided net cash $2,624.0 million, compared to $1,757.4 million in the prior year. Current year cash inflows are primarily the result of several financing

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transactions, including $3.9 billion from the issuance of senior notes, $802.2 million from the Power Contract Financing, L.L.C. (“PCF”) financing transaction, $785.5 million from the refinancing of our CCFC I credit facility, $301.7 million from the issuance of secured notes by our wholly owned subsidiary Gilroy Energy Center (“GEC”) LLC, $159.7 million from secondary trust unit offerings from our Canadian Income Trust, $82.8 million from the monetization of one of our power sales agreements, $82.0 million, $88.0 million, and $74.0 million, respectively, from the sales of preferred interests in the cash flows of our King City, Auburndale, and GEC Holdings, LLC facilities and additional borrowings under our revolvers. This was partially offset by financing costs and $5.0 billion in debt repayments and repurchases. We expect that the significant financing transactions will allow us to continue to retire short term debt and will also enable us to make further repurchases of other long term securities. In the same period of 2002 financing inflows were comprised of $751.8 million from the issuance of common stock, and $2.3 billion in debt financing, partially offset by the use of $869.7 million used to repay our Zero Coupon Convertible Debentures Due 2021, in addition to the repayment of $412.7 million of other indebtedness.

      Letter of Credit Facilities — At December 31, 2003 and 2002, we had approximately $410.8 million and $685.6 million, respectively, in letters of credit outstanding under various credit facilities to support CES risk management and other operational and construction activities. Of the total letters of credit outstanding, $272.1 million and $573.9 million, respectively, were in aggregate issued under the cash collateralized letter of credit facility and the corporate revolving credit facility at December 31, 2003 and 2002, respectively.

      CES Margin Deposits and Other Credit Support — As of December 31, 2003 and 2002, CES had deposited net amounts of $188.0 million and $25.2 million, respectively, in cash as margin deposits with third parties and had letters of credit outstanding of $14.5 million and $106.1 million, respectively. CES uses these margin deposits and letters of credit as credit support for the gas procurement and risk management activities it conducts on Calpine’s behalf. Future cash collateral requirements may increase based on the extent of our involvement in derivative activities and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market. While we believe that we have adequate liquidity to support CES’s operations at this time, it is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations.

      Working Capital — At December 31, 2002, we had a negative working capital balance of approximately $1.3 billion due primarily to the classification as a current liability of the outstanding CCFC I construction revolving credit facility balance of $970.1 million, which was successfully refinanced in August 2003.

      Revised Capital Expenditure Program — Following a comprehensive review of our power plant development program, we announced in January 2002 the adoption of a revised capital expenditure program which contemplated the completion of 27 power projects (representing 15,200 MW) then under construction. 22 of these facilities have subsequently achieved full or partial commercial operation as of December 31, 2003. Construction of advanced stage development projects is expected to proceed only when there is an established market need for additional generating resources at prices that will allow us to meet our investment criteria, and when capital may again become available to us on attractive terms. Further, our entire development and construction program is flexible and subject to continuing review and revision based upon such criteria.

      On March 12, 2002, we announced a new turbine program that reduced previously forecasted capital spending by approximately $1.2 billion in 2002 and $1.8 billion in 2003. The revision includes adjusted timing of turbine delivery and related payment schedules and also cancellation of some orders. As a result of these turbine cancellations and other equipment cancellations, we recorded a pre-tax charge of $168.5 million in the first quarter of 2002.

      On February 11, 2003, we announced a significant restructuring of its turbine agreements (see Note 4 of the Notes to Consolidated Financial Statements), which enables us to cancel up to 131 steam and gas turbines. We recorded a pre-tax charge of $207.4 million in the quarter ending December 31, 2002, in connection with fees paid to vendors to restructure these contracts. To date, 60 of these turbines have been canceled, leaving the disposition of 71 turbines still to be determined.

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      In July 2003 we completed a restructuring of our existing agreements for 20 gas and 2 steam turbines. The new agreement provides for later payment dates, which are in line with our construction program. The table in Note 24 of the Notes to Consolidated Financial Statements sets forth future turbine payments for construction and development projects, as well as for unassigned turbines. It includes previously delivered turbines, payments and delivery year for the remaining 5 turbines to be delivered as well as payment required for the potential cancellation costs of the remaining 71 gas and steam turbines. The table in Note 24 of the Notes to Consolidated Financial Statements does not include payments that would result if we were to release for manufacturing any of these remaining 71 turbines. See Note 24 of the Notes to Consolidated Financial Statements for more information regarding turbine restructuring agreements.

      In 2003 the pre-tax equipment cancellation and impairment charge was primarily a result of the cancellation costs related to three turbines and three heat recovery steam generators totaling $31.8 million, impairment charges related to four turbines totaling $27.4 million and storage and suspension costs for unassigned equipment.

      Uses and Sources of Funding — Our estimated uses of funds for 2004 are as follows: cash interest of $1.2 billion, committed capital expenditures of $0.3 billion, discretionary capital expenditures of $0.3 billion, turbine costs of $0.2 billion, maintenance capital of $0.4 billion, principal payments on operating leases and debt of $0.8 billion and working capital and other miscellaneous uses of $0.2 billion. These outflows will be funded primarily through cash on hand (cash and cash equivalents, the current portion of restricted cash and funds escrowed for the repurchase of outstanding debt and borrowing capacity under our various credit facilities) of $2.3 billion, estimated EBITDA, as adjusted of $1.7 billion and $0.4 billion of proceeds from financing transactions. Actual costs for the projected use of funds identified above, and net proceeds from the projected sources of funds identified above could vary from those estimates, potentially in material respects. In addition, the timing is difficult to predict and we may not be able to complete the financings or we may be able to complete them only on less favorable terms than currently anticipated. The above reflects the refinancing of the CCFC II revolving construction financing facility, expiring in 2004, which occurred on March 23, 2004. Factors that could affect the accuracy of these estimates include the factors identified at the beginning of this section and under “Risk Factors” in Item 1. “Business.”

      Capital Availability — Access to capital for many in the energy sector, including us, has been restricted since late 2001. While we have been able to access the capital and bank credit markets, in this new environment it has been on significantly different terms than in the past. In particular, our senior working capital facility and term loan financings and the majority of our debt securities offered and sold in this period, have been secured by certain of our assets and equity interests. While we believe we will be successful in refinancing all debt before maturity, the terms of financing available to us now and in the future may not be attractive to us and the timing of the availability of capital is uncertain and is dependent, in part, on market conditions that are difficult to predict and are outside of our control.

      At the beginning of 2003, Calpine launched a liquidity-enhancing and refinancing program, which resulted in us closing approximately $8.6 billion of transactions such as contract monetizations, sales of non-strategic assets, refinancings, and new corporate and project financings.

      To date, we have completed in excess of $2.7 billion of liquidity-enhancing transactions, exceeding our original $2.3 billion goal.

      Over the past several months (in 2003, unless otherwise noted), we:

  •  Completed the $250 million, non-recourse project financing facility to fund the construction of our 600-megawatt Rocky Mountain Energy Center (February 2004).
 
  •  Closed the $133 million monetization of a PG&E note receivable; and
 
  •  Received $36 million for the sale of our 50% interest in the 240-megawatt Gordonsville power plant.

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      Over the past twelve months, we completed over $8 billion of capital market transactions and successfully refinanced $6.6 billion of current maturities. We:

  •  Completed $3.8 billion of term loan and secured notes offerings — the largest high-yield financing in the capital markets in seven years;
 
  •  CalGen completed its offering of secured institutional term loans and secured notes, totaling $2.4 billion before transaction costs and fees (March 2004);
 
  •  Raised an additional $400.0 million through an add-on offering of our secured notes;
 
  •  Completed the $800.0 million CCFC I loan refinancing with a secured note and term loan issuance; and
 
  •  Issued $900.0 million of 4 3/4% Contingent Convertible Senior Notes Due 2023 to refinance the 2006 Convertible Senior Notes that can be put to Calpine in December 2004 ($250 million of the $900 million issued in 2004).

      Calpine used proceeds from these offerings to refinance the following:

  •  The $1 billion working capital revolver that matured in May 2003;
 
  •  The $1 billion CCFC I facility that was scheduled to mature in November 2003;
 
  •  The $1 billion in term loans under our senior working capital facility that were scheduled to mature in May 2004;
 
  •  The majority of the $1.2 billion 2006 Convertible Senior Notes, that can be put to Calpine in December 2004. At December 31, 2003, we had repurchased $539.9 million of these Notes. Subsequent to December 31, 2003, we repurchased approximately $177.0 million in principal amount of the 2006 Convertible Senior Notes in exchange for approximately $176.0 million in cash. Additionally, on February 9, 2004, we made a cash tender offer, which expired on March 9, 2004, for all of the outstanding 2006 Convertible Senior Notes at a price of par plus accrued interest. On March 10, 2004, we paid an aggregate amount of $412.8 million for the tendered 2006 Convertible Senior Notes which included accrued interest of $3.4 million. Currently, 2006 Convertible Senior Notes in the aggregate principal amount of $73.7 million remain outstanding, and
 
  •  The $2.5 billion CCFC II facility that was scheduled to mature in November 2004.

      In 2003 with the remaining proceeds from the offerings, we repurchased $2,035.9 million of the principal amount of our outstanding debt and preferred securities in exchange for $1,575.4 million in cash and 30 million shares of Calpine common stock valued at approximately $158.1 million. As a result, in 2003 we realized a net pre-tax gain on the repurchase of securities of $278.6 million, while reducing indebtedness by approximately $460.5 million.

      Asset Sales — As a result of the significant contraction in the availability of capital for participants in the energy sector, we have adopted a strategy of conserving our core strategic assets and disposing of certain less strategically important assets, which serves primarily to strengthen our balance sheet through repayment of debt. Set forth below are the completed asset disposals:

      On October 1, 2003, we sold select oil and gas properties located in Oklahoma to Loto Energy, LLC for approximately $1.2 million. As a result of the sale, we recognized a pre-tax gain of $0.3 million.

      On October 15, 2003, we sold select oil and natural gas properties located throughout the province of Alberta, Canada to Calpine Natural Gas Trust, owned 25% indirectly by Calpine, for net proceeds of $153.6 million. The assets represent approximately 83 billion cubic feet of natural gas equivalent net proved reserves, of which approximately 27 percent were crude oil and natural gas liquids. The properties included 74,916 net developed acres and 41,462 net undeveloped acres, with approximately 175 net producing wells.

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      On November 20, 2003, we completed the sale of our Alvin South Field oil and gas assets located near Alvin, Texas for approximately $0.06 million to Cornerstone Energy, Inc. As a result of the sale, we recognized a pre-tax loss of $0.2 million.

      On November 26, 2003, we completed the sale of our 50 percent interest in the Gordonsville Power Plant. Under the terms of the transaction, we received $36.2 million in cash. We recorded a pre-tax gain of $7.1 million on the sale.

      We believe that our completion of the financing and liquidity transactions described above in difficult conditions affecting the market, and our sector in general, demonstrate our probable ability to have access to the capital markets on acceptable terms in the future, although availability of capital has tightened significantly throughout the power generation industry and, therefore, there can be no assurance that we will have access to capital in the future as and when we may desire.

      Credit Considerations — On July 17, 2003, Standard & Poor’s placed our corporate rating (currently rated at B), our senior unsecured debt rating (currently at CCC+), our preferred stock rating (currently at CCC), our bank loan rating (currently at B), and our second priority senior secured debt rating (currently at B) under review for possible downgrade.

      On July 23, 2003, Fitch, Inc. downgraded our long-term senior unsecured debt rating from B+ to B- (with a stable outlook), our preferred stock rating from B- to CCC (with a stable outlook), and initiated coverage of our senior secured debt rating at BB- (with a stable outlook).

      On October 20, 2003, Moody’s downgraded the rating of our long-term senior unsecured debt from B1 to Caa1 (with a stable outlook) and our senior implied rating from Ba3 to B2 (with a stable outlook). The ratings on our senior unsecured debt, senior unsecured convertible debt and convertible preferred securities were also lowered (with a stable outlook) from B1 to Caa1, from B1 to Caa1 and from B2 to Caa3, respectively. The Moody’s downgrade did not impact our credit agreements, and we continue to conduct our business with our usual creditworthy counterparties.

      Many other issuers in the power generation sector have also been downgraded by one or more of the ratings agencies during this period. Such downgrades can have a negative impact on our liquidity by reducing attractive financing opportunities and increasing the amount of collateral required by trading counterparties.

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

      Off-Balance Sheet Commitments — In accordance with SFAS No. 13 and SFAS No. 98, “Accounting for Leases” our operating leases are not reflected on our balance sheet. All counterparties in these transactions are third parties that are unrelated to us. The sale/ leaseback transactions utilize special-purpose entities formed by the equity investors with the sole purpose of owning a power generation facility. Some of our operating leases contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance debt instruments. We guarantee $1.7 billion of the total future minimum lease payments of our consolidated subsidiaries related to our operating leases. We have no ownership or other interest in any of these special-purpose entities. See Note 24 of the Notes to Consolidated Financial Statements for the future minimum lease payments under our power plant operating leases.

      In accordance with Accounting Principles Board (“APB”) Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FASB Interpretation No. 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion

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No. 18),” the debt on the books of our unconsolidated investments in power projects is not reflected on our balance sheet (see Note 7 of the Notes to Consolidated Financial Statements). At December 31, 2003, investee debt was approximately $455.9 million. Based on our pro rata ownership share of each of the investments, our share would be approximately $145.0 million. However, all such debt is non-recourse to us. For the Aries Power Plant construction debt, Aquila Inc. and Calpine provided support arrangements until construction was completed to cover any cost overruns. See Note 7 of the Notes to Consolidated Financial Statements for additional information on our equity method investments in power projects and oil and gas properties.

      Commercial Commitments — Our primary commercial obligations as of December 31, 2003, are as follows (in thousands):

                                                         
Amounts of Commitment Expiration Per Period

Total
Amounts
Commercial Commitments 2004 2005 2006 2007 2008 Thereafter Committed








Guarantee of subsidiary debt
  $ 27,194     $ 17,531     $ 15,128     $ 171,621     $ 2,099,553     $ 658,876     $ 2,989,903  
Standby letters of credit
    320,580       75,756       10,666       3,401       400             410,803  
Surety bonds
    34,273                               36,207       70,480  
Guarantee of subsidiary operating lease payments
    96,688       83,169       81,772       82,487       115,604       1,277,760       1,737,480  
     
     
     
     
     
     
     
 
Total
  $ 478,735     $ 176,456     $ 107,566     $ 257,509     $ 2,215,557     $ 1,972,843     $ 5,208,666  
     
     
     
     
     
     
     
 

      Our commercial commitments primarily include guarantee of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantee of subsidiary operating lease payments. The debt guarantees consist of parent guarantees for the finance subsidiaries and project financing for the Broad River Energy Center and the Pasadena Power Plant. The debt guarantees and operating lease payments are also included in the contractual obligations table above. We also issue guarantees for normal course of business activities. The King City operating lease commitment is supported by collateral debt securities that mature serially in amounts equal to a portion of the semi-annual lease payment. See “Financial Market Risks — Collateral Debt Securities” for more information.

      We have guaranteed the principal payment of $2.4 billion and $2.7 billion, respectively, of senior notes as of December 31, 2003 and 2002, for two wholly owned finance subsidiaries of Calpine, Calpine Canada Energy Finance ULC and Calpine Canada Energy Finance II ULC. As of December 31, 2003, we have guaranteed $291.6 million and $214.1 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant and $301.0 million and $214.1 million, respectively, as of December 31, 2002, for these power plants. As of December 31, 2003 and 2002, we have also guaranteed $35.6 million and $38.0 million, respectively, of other miscellaneous debt. All of the guaranteed debt is recorded on our Consolidated Balance Sheet.

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      Contractual Obligations — Our contractual obligations as of December 31, 2003, are as follows (in thousands):

                                                             
2004 2005 2006 2007 2008 Thereafter Total







Other long-term liabilities reflected on the Consolidated Balance Sheet
  $ 130,593     $ 11,619     $ 11,565     $ 3,918     $ 3,519     $ 60,248     $ 221,462  
     
     
     
     
     
     
     
 
Total operating lease obligations(8)
  $ 291,764     $ 274,672     $ 260,564     $ 260,045     $ 257,570     $ 2,650,772     $ 3,995,387  
     
     
     
     
     
     
     
 
Debt:
                                                       
Unsecured Senior Notes(3)
  $  —     $ 224,679     $ 381,188     $ 380,240     $ 2,384,529     $ 2,124,583     $ 5,495,219  
Second Priority Senior Secured Notes(3)
    12,500       12,500       12,500       1,209,375             2,442,159       3,689,034  
First Priority Senior Secured Notes(3)
    2,000       2,000       2,000       193,500                   199,500  
     
     
     
     
     
     
     
 
 
Total Senior Notes
    14,500       239,179       395,688       1,783,115       2,384,529       4,566,742       9,383,753  
Convertible Senior Notes Due 2006 and 2023(3)(5)
                660,059                   650,000       1,310,059  
Notes payable and borrowings under lines of credit(2)(4)
    247,425       175,297       179,791       134,963       97,806       160,197       995,479  
Notes payable to Calpine Capital Trusts(3)
                                  1,153,500       1,153,500  
Preferred interests(2)
    11,220       18,712       17,679       16,231       18,073       161,717       243,632  
Capital lease obligation(2)
    4,008       4,407       5,499       5,980       8,369       169,486       197,749  
Construction/ project financing(2)(6)
    65,108       61,285       65,460       237,351       80,024       3,751,524       4,260,752  
     
     
     
     
     
     
     
 
   
Total debt(4)
  $ 342,261     $ 498,880     $ 1,324,176     $ 2,177,640     $ 2,588,801     $ 10,613,166     $ 17,544,924  
     
     
     
     
     
     
     
 
Purchase obligations:
                                                       
Turbine commitments
  $ 100,186     $ 18,641     $ 2,516     $     $  —     $     $ 121,343  
Commodity purchase obligations(1)
    1,145,714       624,664       561,546       502,903       508,546       2,629,699       5,973,072  
Land leases
    4,489       5,886       6,039       6,179       6,320       384,720       413,633  
Long-term service agreements
    111,173       59,491       85,807       133,531       104,830       934,653       1,429,485  
Costs to complete construction projects
    856,953       430,886       231,014       25,141                   1,543,994  
Other purchase obligations
    19,790       20,134       19,596       19,430       18,934       372,106       469,990  
     
     
     
     
     
     
     
 
   
Total purchase obligations(7)
  $ 2,238,305     $ 1,159,702     $ 906,518     $ 687,184     $ 638,630     $ 4,321,178     $ 9,951,517  
     
     
     
     
     
     
     
 


(1)  The amounts presented here include contracts for the purchase, transportation, or storage of commodities accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet. See Financial Market Risks for a discussion of our commodity derivative contracts recorded at fair value on our Consolidated Balance Sheet.
 
(2)  Structured as an obligation(s) of certain subsidiaries of Calpine Corporation without recourse to Calpine Corporation. However, default on these instruments could potentially trigger cross-default provisions in Calpine’s recourse financings.
 
(3)  An obligation of or with recourse to Calpine Corporation.
 
(4)  The note payable totaling $132.4 million associated with the sale of the PG&E note receivable to a third party, is excluded from notes payable and borrowings under lines of credit for this purpose as it is a non-cash liability. If the $132.4 million is summed with the $995.5 (total notes payable and borrowings under lines of credit) million from the table above, the total notes payable and borrowings under lines of credit would be $1,127.9 million, which agrees to the Consolidated Balance Sheet sum of the current and long-

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term notes payable and borrowings under lines of credit balances on the Consolidated Balance Sheet. See Note 8 of the Notes to Consolidated Financial Statements for more information concerning this note. Total debt of $17,544.9 million from the table above summed with the $132.4 million totals $17,677.3 million, which agrees to the total debt amount in Note 17 of the Notes to Consolidated Financial Statements.
 
(5)  See Note 27 of the Notes to Consolidated Financial Statements for information regarding our repurchases of our 2006 Convertible Senior Notes that occurred subsequent to December 31, 2003.
 
(6)  Included in the total are guaranteed amounts of $291.6 million and $289.1 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant. See Note 27 of the Notes to Consolidated Financial Statements for information regarding CalGen’s completed offering of secured institutional term loans and secured notes, which refinanced the CalGen facility. As a result of this refinancing, the $2.2 billion balance outstanding at December 31, 2003 on the refinanced Calgen revolving construction financing facility is shown in the table in the thereafter column.
 
(7)  The amounts included above for purchase obligations include the minimum requirements under contract. Agreements that we can cancel without significant cancellation fees are excluded.
 
(8)  Included in the total are future minimum payments for power plant operating leases, office and equipment leases and two tolling agreements with Acadia Energy Center accounted for as leases (See Note 24 of the Notes to Consolidated Financial Statements for more information).

      We also enter into derivative financial instruments to manage our exposure to commodity price fluctuations and to optimize the returns that we are able to achieve from our power and gas assets. See “Financial Market Risks” in this report and refer to Note 22 of the Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.

      Debt securities repurchased by Calpine during 2003 totaled $1,853.4 million in aggregate outstanding principal amount at a repurchase price of $1,575.3 million plus accrued interest. We recorded a pre-tax gain on these transactions in the amount of $278.1 million, which was $256.9 million, net of write-offs of $18.9 million of unamortized deferred financing costs and $2.3 million of unamortized premiums or discounts. The following table summarizes the total debt securities repurchased during the year ended December 31, 2003 (in millions):

                 
Principal Amount
Debt Security Amount Repurchased



2006 Convertible Senior Notes
  $ 474.9     $ 458.8  
8 1/4% Senior Notes Due 2005
    25.0       24.5  
10 1/2% Senior Notes Due 2006
    5.2       5.1  
7 5/8% Senior Notes Due 2006
    35.3       32.5  
8 3/4% Senior Notes Due 2007
    48.9       45.0  
7 7/8% Senior Notes Due 2008
    74.8       58.3  
8 1/2% Senior Notes Due 2008
    48.3       42.3  
8 3/8% Senior Notes Due 2008
    59.2       46.6  
7 3/4% Senior Notes Due 2009
    97.2       75.9  
8 5/8% Senior Notes Due 2010
    210.4       170.7  
8 1/2% Senior Notes Due 2011
    648.4       521.3  
8 7/8% Senior Notes Due 2011
    125.8       94.3  
     
     
 
    $ 1,853.4     $ 1,575.3  
     
     
 

      Debt securities, exchanged for 23.5 million shares of Calpine common stock in privately negotiated transactions during 2003, totaled $145.0 million in aggregate outstanding principal amount plus accrued interest. We recorded a pre-tax gain on these transactions in the amount of $20.2 million, net of write-offs of unamortized deferred financing costs and the unamortized premiums or discounts. Additionally, during 2003,

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we exchanged 6.5 million shares of Calpine common stock in privately negotiated transactions for approximately $37.5 million par value of HIGH TIDES I. These repurchased HIGH TIDES I are reflected on the balance sheet as an asset, versus being netted against the balance outstanding, due to the deconsolidation of the Calpine Capital Trusts, which issued the HIGH TIDES, upon the adoption of FIN 46-R. The following table summarizes the total debt securities and HIGH TIDES I exchanged for common stock during the year ended December 31, 2003 (in millions):
                 
Common
Principal Stock
Debt Securities and HIGH TIDES Amount Issued



2006 Convertible Senior Notes
  $ 65.0       12.0  
8 1/2% Senior Notes Due 2008
    55.0       8.1  
8 1/2% Senior Notes Due 2011
    25.0       3.4  
HIGH TIDES I
    37.5       6.5  
     
     
 
    $ 182.5       30.0  
     
     
 

      Our senior notes indentures and our credit facilities contain financial and other restrictive covenants. Any failure to comply could give holders of debt under the relevant instrument the right to accelerate the maturity of all debt outstanding thereunder if the default was not cured or waived. In addition, holders of debt under other instruments typically would have cross-acceleration provisions, which would permit them also to elect to accelerate the maturity of their debt if another debt instrument was accelerated upon the occurrence of such an uncured event of default.

      See Note 24 of the Notes to Consolidated Financial Statements for information regarding the restructuring of certain turbine agreements.

      We own a 32.3% interest in the unconsolidated equity method investee Androscoggin Energy LLC (“AELLC”). AELLC owns the 160-MW Androscoggin Energy Center located in Maine and has construction debt of $60.8 million outstanding as of December 31, 2003. The debt is non-recourse to Calpine Corporation (the “AELLC Non-Recourse Financing”). On December 31, 2003, our investment balance was $11.8 million and our notes receivable balance due from AELLC was $13.3 million. On and after August 8, 2003, AELLC received letters from the lenders claiming that certain events of default have occurred under the credit agreement for the AELLC Non-Recourse Financing, including, among other things, that the project has been and remains in default under its debt agreement because the lending syndication had declined to extend the dates for the conversion of the construction loan to a term loan by a certain date. AELLC disputes the purported defaults. Also, the steam host for the AELLC project, International Paper Company (“IP”), filed a complaint against AELLC in October 2000, which is discussed in Note 24 of the Notes to Consolidated Condensed Financial Statements. IP’s complaint has been a complicating factor in converting the construction debt to long term financing. As a result of these events, we have reviewed our investment and notes receivable balances and believe that the assets are not impaired. We further believe that AELLC will be able to convert the construction loan to a term loan.

      We also own a 50% interest in the unconsolidated equity method investee Merchant Energy Partners Pleasant Hill, LLC (“Aries”). Currently, we are finalizing the purchase of the 50% interest in Aries that is held by Aquila, Inc. Following the purchase, we will have a 100% interest in Aries. Aries owns the 591-MW Aries Power Project located in Pleasant Hill, Missouri, and is in default on its construction debt of $190.0 million as of December 31, 2003, that was due on June 26, 2003. Due to this payment default, the partners were required to contribute their proportionate share of $75 million in additional equity. During the second quarter of 2003, we drew down $37.5 million under our working capital revolver to fund our equity contribution. In conjunction with the Aquila, Inc. buyout negotiations, we are in negotiation with the lenders on a term loan for the project. The project is technically in default of its debt agreement until the new term loan is completed. We believe that the project will be able to obtain long-term project financing at commercially reasonable terms. As a result of this event, we have reviewed our $58.2 million investment in the Aries project and believe that the investment is not impaired.

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      We are a party to a Letter of Credit and Reimbursement Agreement dated as of December 19, 2000, with Credit Suisse First Boston (“CSFB”), pursuant to which CSFB issued a letter of credit with a maximum face amount of $78.3 million for our account. CSFB previously advised us that CSFB believed that we may have failed to comply with certain covenants under the Letter of Credit and Reimbursement Agreement related to our ability to incur indebtedness and grant liens. We disputed the purported non-compliance. This dispute with CSFB has now been resolved and we are in the process of completing an amendment to the Letter of Credit and Reimbursement Agreement.

      On May 15, 2003, our wholly owned indirect subsidiary, Calpine Northbrook Energy Marketing, LLC (“CNEM”), completed an offering of $82.8 million secured by an existing power sales agreement with the Bonneville Power Administration (“BPA”). CNEM borrowed $82.8 million secured by the BPA contract, a spot market power purchase agreement, a fixed price swap agreement and the equity interest in CNEM. CNEM was established as an entity with its existence separate from Calpine and our other subsidiaries, and the $82.8 million loan is recourse only to CNEM’s assets and the equity interest in CNEM and is not guaranteed by us. CNEM was determined to be a VIE in which we were the primary beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into our accounts as of June 30, 2003.

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

      The following table sets forth selected financial information of CNEM at December 31, 2003 (in thousands):

         
CNEM

Assets
  $ 106,904  
     
 
Liabilities
    82,397  
     
 
Total revenue(1)
    1,827  
     
 
Total cost of revenue
    184  
     
 
Interest expense
    5,921  
     
 
Net loss
    (2,870 )
     
 


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

      See Note 11 of the Notes to Consolidated Financial Statements for further information.

      On June 13, 2003, Power Contract Financing, L.L.C. (“PCF”), a wholly owned stand-alone subsidiary of CES, completed an offering of two tranches of Senior Secured Notes due 2006 and 2010 (collectively called the “PCF Notes”), totaling $802.2 million. To facilitate the transaction, we formed PCF as an entity with its existence separate from Calpine and our other subsidiaries, with assets and liabilities consisting of cash, the transferred power purchase and sales contracts and the PCF Notes. PCF was determined to be a VIE in which we were the primary beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into our accounts as of June 30, 2003.

      Pursuant to the applicable transaction agreements, PCF has been established as an entity with its existence separate from Calpine and our other subsidiaries. In accordance with FIN 46 we consolidate this

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entity. See Note 2 of the Notes to Consolidated Financial Statements for more information on FIN 46. The above mentioned power sales and power purchase agreements, which have been acquired by PCF from CES, and the PCF Notes are assets and liabilities of PCF, separate from the assets and liabilities of Calpine and our other subsidiaries. The proceeds of the Senior Secured Notes were primarily used by PCF to purchase the power sales and power purchase agreements. The following table sets forth selected financial information of PCF at December 31, 2003 (in thousands):
         
PCF

Assets
  $ 1,046,213  
Liabilities
    1,150,625  
Total revenue
    180,896  
Total cost of revenue
    165,043  
Interest expense
    39,396  
Net loss
    (15,022 )

      See Note 11 of the Notes to Consolidated Financial Statements for further information.

      On September 30, 2003, Gilroy Energy Center, LLC (“GEC”), a wholly owned subsidiary of our indirect subsidiary GEC Holdings, LLC, completed an offering of $301.7 million of 4% Senior Secured Notes Due 2011 (see Note 16 of the Notes to Consolidated Financial Statements for more information on this secured financing). In connection with this secured notes borrowing, we received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, due to certain preferential distributions to the third party. The preferential distributions are due bi-annually beginning in March 2004 through September 2011 and total approximately $113.3 million over the eight-year period. As of December 31, 2003, there was $74.0 million outstanding under the preferred interest. The effective interest rate, after amortization of deferred financing charges, was 11.3% per annum at December 31, 2003.

      Pursuant to the applicable transaction agreements, GEC has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate these entities. The long-term power sales agreement with the State of California Department of Water Resources has been acquired by GEC by means of a series of capital contributions by CES and certain of its affiliates and is an asset of GEC, and the Senior Secured Notes and preferred interest are liabilities of GEC, separate from the assets and liabilities of Calpine and our other subsidiaries. Aside from seven peaker power plants owned directly and the power sales agreement, GEC’s assets include cash and a 100% equity interest in each of Creed Energy Center, LLC (“Creed”) and Goose Haven Energy Center, LLC (“Goose Haven”) each of which is a wholly owned subsidiary of GEC. Each of Creed and Goose Haven has been established as an entity with its existence separate from Calpine and our other subsidiaries of the Company. GEC consolidates these entities. Creed and Goose Haven each have assets consisting of various power plants and other assets. The following table sets forth selected financial information of GEC at December 31, 2003 (in thousands):

         
GEC

Assets
  $ 662,811  
Liabilities
    333,404  
Total revenue
    109,831  
Total cost of revenue
    59,569  
Interest expense
    37,277  
Net income
    8,172  

      See Note 8 of the Notes to Consolidated Financial Statements for further information.

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      On April 29, 2003, we sold a preferred interest in a subsidiary that leases and operates the 115-MW King City Power Plant to GE Structured Finance for $82.0 million. The preferred interest holder will receive approximately 60% of future cash flow distributions based on current projections. We will continue to provide O&M services. As of December 31, 2003, there was $82.0 million outstanding under the preferred interest. The effective interest rate, after amortization of deferred financing charges, was 12.8% per annum at December 31, 2003.

      Pursuant to the applicable transaction agreements, each of Calpine King City Cogen LLC, Calpine Securities Company, L.P., a parent company of Calpine King City Cogen LLC, and Calpine King City, LLC, an indirect parent company of Calpine Securities Company, L.P., has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate these entities. The following table sets forth certain financial information relating to these three entities as of December 31, 2003 (in thousands):

         
Assets
  $ 157,598  
Liabilities
  $ 60,785  

      On December 4, 2003, we announced that we had sold to a group of institutional investors our right to receive payments from PG&E under the Agreement between PG&E and Calpine Gilroy Cogen, L.P. (“Gilroy”), a California Limited Partnership (PG&E Log No. 08C002) For Termination and Buy-Out of Standard Offer 4 Power Purchase Agreement, executed by PG&E on July 1, 1999 (the “Gilroy Receivable”) under the Gilroy notes receivable from PG&E for $133.4 million in cash. Because the transaction did not satisfy the criteria for sales treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities — a Replacement of FASB Statement No. 125,” it is reflected in the Consolidated Financial Statements as a secured financing, with a note payable of $133.4 million. The receivable balance and note payable balance are both reduced as PG&E makes payments to the buyer of the Gilroy Receivable. The $24.1 million difference between the $157.5 million book value of the Gilroy Receivable at the transaction date and the cash received will be recognized as additional interest expense over the repayment term. We will continue to book interest income over the repayment term and interest expense will be accreted on the amortizing note payable balance.

      Pursuant to the applicable transaction agreements, each of Gilroy and Calpine Gilroy 1, Inc., the general partner of Gilroy, has been established as an entity with its existence separate from Calpine and our other subsidiaries. We consolidate these entities. The following table sets forth the assets and liabilities of Gilroy as of December 31, 2003 (in thousands):

         
Assets
  $ 468,624  
Liabilities
  $ 134,170  

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Capital Spending — Development and Construction

      Construction and development costs in process consisted of the following at December 31, 2003 (dollars in thousands):

                                           
Equipment Project
# of Included in Development Unassigned
Projects CIP(2) CIP Costs Equipment





Projects in active construction
    14 (1)   $ 4,538,093     $ 1,572,708     $     $  
Projects in advanced development
    12       711,779       599,512       122,248        
Projects in suspended development
    5       466,350       204,873       8,753        
Projects in early development
    3                   8,952        
Other capital projects
    NA       45,910                    
Unassigned equipment
    NA                         71,361  
             
     
     
     
 
 
Total construction and development costs
          $ 5,762,132     $ 2,377,093     $ 139,953     $ 71,361  
             
     
     
     
 


(1)  12 gas-fired projects and 2 project expansions. Includes expansion of the Morgan Energy Center, which entered commercial operation in January 2004.
 
(2)  Construction in Progress (“CIP”).

      Projects in Active Construction — The 14 projects in active construction are estimated to come on line from January 2004 to June 2007. These projects will bring on line approximately 6,742 MW of base load (8,004 MW base load with peaking capacity). Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized. At December 31, 2003, the estimated funding requirements to complete these projects, net of expected project financing proceeds, is approximately $1.2 billion. We plan to spend $0.6 billion, $0.4 billion, and $0.2 billion in 2004, 2005, and 2006, respectively, net of project financing.

      Projects in Advanced Development — There are 12 projects in advanced development. These projects will bring on line approximately 5,709 MW of base load (6,835 MW base load with peaking capacity). Interest and other costs related to the development activities necessary to bring these projects to their intended use are being capitalized. However, the capitalization of interest has been suspended on two projects for which development activities are substantially complete but construction will not commence until a power purchase agreement and financing are obtained. The estimated cost to complete the 12 projects in advanced development is approximately $3.7 billion. Our current plan is to project finance these costs as power purchase agreements are arranged.

      Suspended Development Projects — Due to current electric market conditions, we have ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met indicating that it is again highly probable that the costs will be recovered through future operations. As is true for all projects, the suspended projects are reviewed for impairment whenever there is an indication of potential reduction in a project’s fair value. Further, if it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value. These projects would bring on line approximately 2,569 MW of base load (3,029 MW base load with peaking capacity). The estimated cost to complete these projects is approximately $1.5 billion.

      Projects in Early Development — Costs for projects that are in early stages of development are capitalized only when it is highly probable that such costs are ultimately recoverable and significant project milestones are achieved. Until then, all costs, including interest costs, are expensed. The projects in early development with capitalized costs relate to 3 projects and include geothermal drilling costs and equipment purchases.

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      Other Capital Projects — Other capital projects primarily consist of enhancements to operating power plants, oil and gas and geothermal resource and facilities development as well as software developed for internal use.

      Unassigned Equipment — As of December 31, 2003, we had made progress payments on 4 turbines, 1 heat recovery steam generator, and other equipment with an aggregate carrying value of $71.4 million. This unassigned equipment is classified on the balance sheet as other assets, because it is not assigned to specific development and construction projects. We are holding this equipment for potential use on future projects. It is possible that some of this unassigned equipment may eventually be sold, potentially in combination with our engineering and construction services. For equipment that is not assigned to development or construction projects, interest is not capitalized.

      Impairment Evaluation — All construction and development projects and unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in fair value. Equipment assigned to such projects is not evaluated for impairment separately, as it is integral to the assumed future operations of the project to which it is assigned. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value in accordance with the provisions of SFAS No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets.” We review our unassigned equipment for potential impairment based on probability-weighted alternatives of utilizing it for future projects versus selling it. Utilizing this methodology, we do not believe that the equipment not committed to sale is impaired. However, during year ended December 31, 2003, we recorded approximately $27.4 million in losses in connection with the sale of four turbines, and we may incur further losses should we decide to sell more unassigned equipment in the future.

Performance Metrics

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

  •  Total deliveries of power. We both generate power that we sell to third parties and purchase power for sale to third parties in hedging, balancing and optimization (“HBO”) transactions. The former sales are recorded as electricity and steam revenue and the latter sales are recorded as sales of purchased power for hedging and optimization. The volumes in MWh for each are key indicators of our respective levels of generation and HBO activity and the sum of the two, our total deliveries of power, is relevant because there are occasions where we can either generate or purchase power to fulfill contractual sales commitments. Prospectively beginning October 1, 2003, in accordance with EITF 03-11, certain sales of purchased power for hedging and optimization are shown net of purchased power expense for hedging and optimization in our consolidated statement of operations. Accordingly, we have also netted HBO volumes on the same basis as of October 1, 2003, in the table below.
 
  •  Average availability and average baseload capacity factor or operating rate. 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, sometimes called operating rate, 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

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  which we adjust the fuel consumption in Btu’s down by the equivalent heat content in steam or other thermal energy exported to a third party, such as to steam hosts for our cogeneration facilities. Our goal is to have the lowest average heat rate in the industry.
 
  •  Average all-in realized electric price expressed in dollars per MWh generated. Our risk management and optimization activities are integral to our power generation business and directly impact our total realized revenues from generation. Accordingly, we calculate the all-in realized electric price per MWh generated by dividing (a) adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues and the spread on sales of purchased electricity for hedging, balancing, and optimization activity, by (b) total generated MWh’s in the period.
 
  •  Average cost of natural gas expressed in dollars per millions of Btu’s of fuel consumed. Our risk management and optimization activities related to fuel procurement directly impact our total fuel expense. The fuel costs for our gas-fired power plants are a function of the price we pay for fuel purchased and the results of the fuel hedging, balancing, and optimization activities by CES. Accordingly, we calculate the cost of natural gas per millions of Btu’s of fuel consumed in our power plants by dividing (a) adjusted fuel expense which includes the cost of fuel consumed by our plants (adding back cost of intercompany “equity” gas from Calpine Natural Gas, which is eliminated in consolidation), and the spread on sales of purchased gas for hedging, balancing, and optimization activity by (b) the heat content in millions of Btu’s of the fuel we consumed in our power plants for the period.
 
  •  Average spark spread expressed in dollars per MWh generated. Our risk management activities focus on managing the spark spread for our portfolio of power plants, the spread between the sales price for electricity generated and the cost of fuel. We calculate the spark spread per MWh generated by subtracting (a) adjusted fuel expense from (b) adjusted E&S revenue and dividing the difference by (c) total generated MWh in the period.
 
  •  Average plant operating expense per normalized MWh. To assess trends in electric power plant operating expense (“POX”) per MWh, we normalize the results from period to period by assuming a constant 70% total company-wide capacity factor (including both baseload and peaker capacity) in deriving normalized MWh’s. 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.

      The table below shows the operating performance metrics discussed above.

                             
Years Ended December 31,

2003 2002 2001



(In thousands)
Operating Performance Metrics;
                       
 
Total deliveries of power:
                       
   
MWh generated
    82,423       72,767       42,394  
   
HBO and trading MWh sold
    74,837       75,740       54,810  
     
     
     
 
   
MWh delivered
    157,260       148,507       97,204  
     
     
     
 
 
Average availability
    91 %     92 %     93 %
 
Average baseload capacity factor:
                       
   
Average total MW in operation
    20,092       14,346       7,805  
   
Less: Average MW of pure peakers
    2,672       1,708       976  
     
     
     
 
   
Average baseload MW in operation
    17,420       12,638       6,829  
   
Hours in the period
    8,760       8,760       8,760  
   
Potential baseload generation
    152,599       110,709       59,822  
   
Actual total generation
    82,423       72,767       42,394  
   
Less: Actual pure peakers’ generation
    1,077       979       542  
     
     
     
 

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Years Ended December 31,

2003 2002 2001



(In thousands)
 
Actual baseload generation
    81,346       71,788       41,852  
 
Average baseload capacity factor
    53 %     65 %     70 %
Average heat rate for gas-fired power plants (excluding peakers) (Btu’s/ KWh):
                       
 
Not steam adjusted
    8,007       7,928       8,203  
 
Steam adjusted
    7,253       7,239       7,398  
Average all-in realized electric price:
                       
 
Electricity and steam revenue
  $ 4,695,744     $ 3,222,202     $ 2,385,324  
 
Spread on sales of purchased power for hedging and optimization
    24,118       527,546       345,834  
     
     
     
 
 
Adjusted electricity and steam revenue (in thousands)
  $ 4,719,862     $ 3,749,748     $ 2,731,158  
 
MWh generated (in thousands)
    82,423       72,767       42,394  
 
Average all-in realized electric price per MWh
  $ 57.26     $ 51.53     $ 64.42  
Average cost of natural gas:
                       
 
Cost of oil and natural gas burned by power plants (in thousands)
  $ 2,523,408     $ 1,703,499     $ 1,116,857  
 
Fuel cost elimination
    374,298       180,375       99,854  
     
     
     
 
 
Adjusted fuel expense
  $ 2,897,706     $ 1,883,874     $ 1,216,711  
 
Million Btu’s (“MMBtu”) of fuel consumed by generating plants (in thousands)
    560,508       511,354       288,549  
 
Average cost of natural gas per MMBtu
  $ 5.17     $ 3.68     $ 4.22  
 
MWh generated (in thousands)
    82,423       72,767       42,394  
 
Average cost of adjusted fuel expense per MWh
  $ 35.16     $ 25.89     $ 28.70  
Average spark spread:
                       
 
Adjusted electricity and steam revenue (in thousands)
  $ 4,719,862     $ 3,749,748     $ 2,731,158  
 
Less: Adjusted fuel expense (in thousands)
    2,897,706       1,883,874       1,216,711  
     
     
     
 
   
Spark spread (in thousands)
  $ 1,822,156     $ 1,865,874     $ 1,514,447  
 
MWh generated (in thousands)
    82,423       72,767       42,394  
 
Average spark spread per MWh
  $ 22.11     $ 25.64     $ 35.72  
 
Add: Equity gas contribution(1)
  $ 202,454     $ 57,114     $ 199,196  
 
Spark spread with equity gas benefits (in thousands)
  $ 2,024,610     $ 1,922,988     $ 1,713,643  
 
Average spark spread with equity gas benefits per MWh
  $ 24.56     $ 26.43     $ 40.42  
Average plant operating expense (“POX”) per normalized MWh:
                       
 
Average total consolidated MW in operations
    20,092       14,346       7,805  
 
Hours per year
    8,760       8,760       8,760  
 
Total potential MWh
    176,006       125,671       68,372  
 
Normalized MWh (at 70% capacity factor)
    123,204       87,970       47,860  
 
Plant operating expense (POX)
  $ 679,031     $ 505,971     $ 324,029  
 
POX per normalized MWh
  $ 5.51     $ 5.75     $ 6.77  

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(1)  Equity gas contribution margin:
                           
Years Ended December 31,

2003 2002 2001



(In thousands)
Oil and gas sales
  $ 107,662     $ 120,930     $ 286,241  
Add: Fuel cost eliminated in consolidation
    374,298       180,375       99,854  
     
     
     
 
 
Subtotal
  $ 481,960     $ 301,305     $ 386,095  
Less: Oil and gas operating expense
    106,244       97,501       90,492  
Less: Depletion, depreciation and amortization
    173,262       146,690       96,407  
     
     
     
 
Equity gas contribution margin
  $ 202,454     $ 57,114     $ 199,196  
MWh generated (in thousands)
    82,423       72,767       42,394  
Equity gas contribution margin per MWh
  $ 2.46     $ 0.78     $ 4.70  

      The table below provides additional detail of total mark-to-market activity. For the years ended December 31, 2003, 2002 and 2001, mark-to-market activity, net consisted of (dollars in thousands):

                               
Years Ended December 31,

2003 2002 2001



(In thousands)
Mark-to-market activity, net
                       
Realized:
                       
 
Power activity
                       
   
“Trading Activity” as defined in EITF No. 02-03
  $ 52,559     $ 12,175     $ 9,926  
   
Ineffectiveness related to cash flow hedges
                 
   
Other mark-to-market activity(1)
    (26,059 )            
     
     
     
 
     
Total realized power activity
  $ 26,500     $ 12,175     $ 9,926  
     
     
     
 
 
Gas activity
                       
   
“Trading Activity” as defined in EITF No. 02-03
  $ (2,166 )   $ 13,915     $ 19,219  
   
Ineffectiveness related to cash flow hedges
                 
   
Other mark-to-market activity(1)
                 
     
     
     
 
     
Total realized gas activity
  $ (2,166 )   $ 13,915     $ 19,219  
     
     
     
 
Total realized activity:
                       
 
“Trading Activity” as defined in EITF No. 02-03
  $ 50,393     $ 26,090     $ 29,145  
 
Ineffectiveness related to cash flow hedges
                 
 
Other mark-to-market activity(1)
    (26,059 )            
     
     
     
 
     
Total realized activity
  $ 24,334     $ 26,090     $ 29,145  
     
     
     
 
Unrealized:
                       
 
Power activity
                       
   
“Trading Activity” as defined in EITF No. 02-03
  $ (55,450 )   $ 12,974     $ 96,402  
   
Ineffectiveness related to cash flow hedges
    (5,001 )     (4,934 )     1,866  
   
Other mark-to-market activity(1)
    (1,243 )            
     
     
     
 
     
Total unrealized power activity
  $ (61,694 )   $ 8,040     $ 98,268  
     
     
     
 

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Years Ended December 31,

2003 2002 2001



(In thousands)
 
Gas activity
                       
   
“Trading Activity” as defined in EITF No. 02-03
  $ 7,768     $ (14,792 )   $ 30,113  
   
Ineffectiveness related to cash flow hedges
    3,153       2,147       (5,788 )
   
Other mark-to-market activity(1)
                 
     
     
     
 
     
Total unrealized gas activity
  $ 10,921     $ (12,645 )   $ 24,325  
     
     
     
 
Total Unrealized activity:
                       
 
“Trading Activity” as defined in EITF No. 02-03
  $ (47,682 )   $ (1,818 )   $ 126,515  
 
Ineffectiveness related to cash flow hedges
    (1,848 )     (2,787 )     (3,922 )
 
Other mark-to-market activity(1)
    (1,243 )            
     
     
     
 
     
Total unrealized activity
  $ (50,773 )   $ (4,605 )   $ 122,593  
     
     
     
 
Total mark-to-market activity:
                       
 
“Trading Activity” as defined in EITF No. 02-03
  $ 2,711     $ 24,272     $ 155,660  
 
Ineffectiveness related to cash flow hedges
    (1,848 )     (2,787 )     (3,922 )
 
Other mark-to-market activity(1)
    (27,302 )            
     
     
     
 
     
Total mark-to-market activity
  $ (26,439 )   $ 21,485     $ 151,738  
     
     
     
 


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

Strategy

      For a discussion of our strategy and management’s outlook, see “Item 1 — Business — Strategy.”

Financial Market Risks

      As we are primarily focused on generation of electricity using gas-fired turbines, our natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, we enter into derivative commodity instruments as discussed in Item 6. “Business — Marketing, Hedging, Optimization and Trading Activities.”

      The change in fair value of outstanding commodity derivative instruments from January 1, 2003, through December 31, 2003, is summarized in the table below (in thousands):

         
Fair value of contracts outstanding at January 1, 2003
  $ 150,627  
Gains recognized or otherwise settled during the period(1)
    (153,673 )
Changes in fair value attributable to changes in valuation techniques and assumptions(2)
    (12,673 )
Changes in fair value attributable to new contracts
    60,752  
Changes in fair value attributable to price movements
    87,666  
Terminated derivatives(3)
    (56,158 )
     
 
Fair value of contracts outstanding at December 31, 2003(4)
  $ 76,541  
     
 


(1)  Recognized gains from commodity cash flow hedges of $129.4 million, (represents realized value of cash flow hedge activity of $(38.5) million as disclosed in Note 22 of the Notes to Consolidated Financial Statements, net of terminated derivatives of $(167.9)) and $24.3 million realized gain on mark-to-

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market activity, which is reported in the Consolidated Statements of Operations under mark-to-market activities, net.
 
(2)  Relates to changes in the valuation technique used by Calpine to extrapolate price curves beyond periods where external price quotes are observable. See discussion of the change in valuation technique under the “Fair Value of Energy Marketing and Risk Management Contracts and Derivatives” subsection to the critical accounting policies.
 
(3)  Includes the value of derivatives terminated or settled before their scheduled maturity.
 
(4)  Net commodity derivative assets reported in Note 22 of the Notes to Consolidated Financial Statements included in this filing.

      The fair value of outstanding derivative commodity instruments at December 31, 2003, based on price source and the period during which the instruments will mature, are summarized in the table below (in thousands):

                                         
Fair Value Source 2004 2005-2006 2007-2008 After 2008 Total






Prices actively quoted
  $ 52,180     $ 16,724     $     $  —     $ 68,904  
Prices provided by other external sources
    (13,062 )     40,485       6,382       (21,792 )     12,013  
Prices based on models and other valuation methods
          1,017       1,110       (6,503 )     (4,376 )
     
     
     
     
     
 
Total fair value
  $ 39,118     $ 58,226     $ 7,492     $ (28,295 )   $ 76,541  
     
     
     
     
     
 

      Our risk managers maintain fair value price information derived from various sources in our risk management systems. The propriety of that information is validated by our Risk Control group. Prices actively quoted include validation with prices sourced from commodities exchanges (e.g., New York Mercantile Exchange). Prices provided by other external sources include quotes from commodity brokers and electronic trading platforms. Prices based on models and other valuation methods are validated using quantitative methods. See Critical Accounting Policies for a discussion of valuation estimates used where external prices are unavailable.

      The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at December 31, 2003, and the period during which the instruments will mature are summarized in the table below (in thousands):

                                         
Credit Quality (based on Standard & Poor’s Ratings as
of January 7, 2004) 2004 2005-2006 2007-2008 After 2008 Total






Investment grade
  $ 5,767     $ 46,770     $ 8,412     $ (27,788 )   $ 33,161  
Non-investment grade
    39,044       12,019       (633 )     (507 )     49,923  
No external ratings
    (5,693 )     (563 )     (287 )           (6,543 )
     
     
     
     
     
 
Total fair value
  $ 39,118     $ 58,226     $ 7,492     $ (28,295 )   $ 76,541  
     
     
     
     
     
 

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

                     
Fair
Value After
10% Adverse
Fair Value Price Change


               
 
Electricity
  $ (6,085 )   $ (157,116 )
 
Natural gas
    82,626       9,505  
     
     
 
   
Total
  $ 76,541     $ (147,611 )
     
     
 

      Derivative commodity instruments included in the table are those included in Note 22 of the Notes to Consolidated Financial Statements. The fair value of derivative commodity instruments included in the table is based on present value adjusted quoted market prices of comparable contracts. The fair value of electricity derivative commodity instruments after a 10% adverse price change includes the effect of increased power prices versus our derivative forward commitments. Conversely, the fair value of the natural gas derivatives after a 10% adverse price change reflects a general decline in gas prices versus our derivative forward commitments. Derivative commodity instruments offset the price risk exposure of our physical assets. None of the offsetting physical positions are included in the table above.

      Price changes were calculated by assuming an across-the-board ten percent adverse price change regardless of term or historical relationship between the contract price of an instrument and the underlying commodity price. In the event of an actual ten percent change in prices, the fair value of our derivative portfolio would typically change by more than ten percent for earlier forward months and less than ten percent for later forward months because of the higher volatilities in the near term and the effects of discounting expected future cash flows.

      The primary factors affecting the fair value of our derivatives at any point in time are (1) the volume of open derivative positions (MMBtu and MWh), and (2) changing commodity market prices, principally for electricity and natural gas. The total volume of open gas derivative positions decreased 70% from December 31, 2002, to December 31, 2003, while the total volume of open power derivative positions decreased 12% for the same period. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in Other Comprehensive Income (“OCI”), net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of December 31, 2003, the majority of the balance in accumulated OCI represented the unrealized net loss associated with commodity cash flow hedging transactions. As noted above, there is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and our results during the year ended December 31, 2003, have reflected this. See Note 22 of the Notes to Consolidated Financial Statements for additional information on derivative activity.

      Collateral Debt Securities — The King City operating lease commitment is supported by collateral debt securities that mature serially in amounts equal to a portion of the semi-annual lease payment. We have the ability and intent to hold these securities to maturity, and as a result, we do not expect a sudden change in market interest rates to have a material affect on the value of the securities at the maturity date. The securities are recorded at an amortized cost of $82.6 million at December 31, 2003. See Note 3 of the Notes to

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Consolidated Financial Statements. The following tables present our different classes of collateral debt securities by expected maturity date and fair market value as of December 31, 2003, (dollars in thousands):
                                                                   
Weighted
Average
Interest Rate 2004 2005 2006 2007 2008 Thereafter Total








Corporate Debt Securities
    7.3 %   $ 6,050     $ 7,825     $     $     $     $     $ 13,875  
U.S. Treasury Notes
    6.5 %           1,975                               1,975  
U.S. Treasury Securities (non- interest bearing)
                      9,700       9,100       9,050       87,100       114,950  
             
     
     
     
     
     
     
 
 
Total
          $ 6,050     $ 9,800     $ 9,700     $ 9,100     $ 9,050     $ 87,100     $ 130,800  
             
     
     
     
     
     
     
 
           
Fair Market
Value

Corporate Debt Securities
  $ 14,475  
U.S. Treasury Notes
    2,130  
U.S. Treasury Securities (non-interest bearing)
    81,775  
     
 
 
Total
  $ 98,380  
     
 

      Interest Rate Swaps and Cross Currency Swaps — From time to time, we use interest rate swap and cross currency swap agreements to mitigate our exposure to interest rate and currency fluctuations associated with certain of our debt instruments. We do not use interest rate swap and currency swap agreements for speculative or trading purposes. The following tables summarize the fair market values of our existing interest rate swap and currency swap agreements as of December 31, 2003 (dollars in thousands):

 
Variable to Fixed Swaps
                                   
Weighted Average Weighted Average
Notional Interest Rate Interest Rate Fair Market
Maturity Date Principal Amount (Pay) (Receive) Value





2007
  $ 38,000       3.8 %   3-month US$ LIBOR     $ (564 )
2007
    38,333       3.8 %   3-month US$ LIBOR       (569 )
2007
    38,667       3.8 %   3-month US$ LIBOR       (574 )
2011
    43,013       6.9 %   3-month US$ LIBOR       (5,838 )
2012
    111,384       6.5 %   3-month US$ LIBOR       (15,192 )
2014
    59,331       6.7 %   3-month US$ LIBOR       (7,893 )
     
                     
 
 
Total
  $ 328,728       5.6 %           $ (30,630 )
     
                     
 
 
Fixed to Variable Swaps
                                   
Weighted Average
Notional Weighted Average Interest Interest Rate Fair Market
Maturity Date Principal Amount Rate (Pay) (Receive) Value





2011
  $ 100,000     6-month US$ LIBOR       8.5 %   $ (7,193 )
2011
    100,000     6-month US$ LIBOR       8.5 %     (5,369 )
2011
    200,000     6-month US$ LIBOR       8.5 %     (11,179 )
     
                     
 
 
Total
  $ 400,000               8.5 %   $ (23,741 )
     
                     
 

      Debt Financing — Because of the significant capital requirements within our industry, debt financing is often needed to fund our growth. Certain debt instruments may affect us adversely because of changes in market conditions. We have used two primary forms of debt which are subject to market risk: (1) Variable rate construction/project financing and (2) Other variable-rate instruments. Significant LIBOR increases could have a negative impact on our future interest expense. Our variable-rate construction/project financing

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is primarily through CCFC II (renamed CalGen). Borrowings under this credit agreement are used exclusively to fund the construction of our power plants. Other variable-rate instruments consist primarily of our revolving credit and term loan facilities, which are used for general corporate purposes. Both our variable-rate construction/project financing and other variable-rate instruments are indexed to base rates, generally LIBOR, as shown below.

      The following table summarizes our variable-rate debt exposed to interest rate risk as of December 31, 2003. All outstanding balances and fair market values are shown net of applicable premium or discount, if any (dollars in thousands):

                               
Outstanding Fair Market
Balance Interest Rate Basis(4) Value



Variable-rate construction/project financing and other variable-rate instruments:
                       
Short-term
                       
 
First Priority Senior Secured Term Loan B Notes Due 2007
  $ 2,000     3-month US$ LIBOR     $ 2,000  
 
First Priority Secured Institutional Term Loan Due 2009 (CCFC I)
    3,208       (1 )     3,208  
 
Second Priority Senior Secured Term Loan B Notes Due 2007
    7,500       (2 )     7,500  
 
Second Priority Senior Secured Floating Rate Notes Due 2007
    5,000       (3 )     5,000  
     
             
 
   
Total short-term
  $ 17,708             $ 17,708  
     
             
 
Long-term
                       
 
Blue Spruce Energy Center Project Financing
  $ 140,000       (3 )   $ 140,000  
 
Riverside Energy Center Project Financing
    165,347     1-month US$ LIBOR       165,347  
 
First Priority Secured Institutional Term Loan Due 2009 (CCFC I)
    378,182       (1 )     378,182  
 
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I)
    407,598       (1 )     407,598  
 
Corporate revolving line of credit
        1-month US$ LIBOR        
 
Thomassen revolving line of credit
    609     1-month US$ LIBOR       609  
 
First Priority Senior Secured Term Loan B Notes Due 2007
    197,500     3-month US$ LIBOR       197,500  
 
Second Priority Senior Secured Floating Rate Notes Due 2007
    493,750       (3 )     493,750  
 
Second Priority Senior Secured Term Loan B Notes Due 2007
    740,625       (2 )     740,625  
 
Calpine Construction Finance Company II, LLC (CCFC II)
    2,200,358     1-month US$ LIBOR       2,200,358  
     
             
 
   
Total long-term
  $ 4,723,969             $ 4,723,969  
     
             
 
     
Total variable-rate construction/project financing and other variable-rate instruments
  $ 4,741,677             $ 4,741,677  
     
             
 


(1)  British Bankers Association LIBOR Rate for deposit in US dollars for a period of six months.
 
(2)  U.S. prime rate in combination with the Federal Funds Effective Rate.
 
(3)  British Bankers Association LIBOR Rate for deposit in US dollars for a period of three months.

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(4)  Actual interest rates include a spread over the basis amount.

      Construction/project financing facilities — In November 2004 the $2.5 billion secured construction financing revolving facility for our wholly owned subsidiary CCFC II (or CalGen) was scheduled to mature. On March 23, 2004, CalGen completed its offering of secured institutional term loans and secured notes, which refinanced the CalGen facility. We realized total proceeds from the offering in the amount of $2.4 billion, before transaction costs and fees. See Item 1. “Business — Recent Developments” for more information regarding this offering.

      On August 14, 2003, our wholly owned subsidiaries, CCFC I and CCFC Finance Corp., closed their $750 million institutional term loans and secured notes offerings, proceeds from which were utilized to repay the majority of CCFC I’s indebtedness which would have matured in the fourth quarter of 2003. The offering included $385 million of First Priority Secured Institutional Term Loans Due 2009 offered at 98% of par and priced at LIBOR plus 600 basis points, with a LIBOR floor of 150 basis points, and $365 million of Second Priority Senior Secured Floating Rate Notes Due 2011 offered at 98.01% of par and priced at LIBOR plus 850 basis points, with a LIBOR floor of 125 basis points. S&P has assigned a B corporate credit rating to CCFC I. S&P also assigned a B+ rating (with a negative outlook) to the First Priority Secured Institutional Term Loans Due 2009 and a B- rating (with a negative outlook) to the Second Priority Secured Floating Rate Notes Due 2011. The noteholders’ recourse is limited to seven of CCFC I’s natural gas-fired electric generating facilities (as adjusted for approved dispositions and acquisitions, such as the completed sale of Lost Pines Power Project and the pending acquisition of the Brazos Valley Power Plant) located in various power markets in the United States, and related assets and contracts. See Note 14 of the Notes to Consolidated Financial Statements for more information.

      On September 25, 2003, our wholly owned subsidiaries, CCFC I and CCFC Finance Corp., closed on a $50 million add-on financing to the $385 million secured notes offering completed on August 14, 2003. See Note 14 of the Notes to Consolidated Financial Statements for more information.

      Revolving credit and term loan facilities — On July 16, 2003, we closed our $3.3 billion term loan and second-priority senior secured notes offering (the “July 2003 offerings”). The term loan and senior notes are secured by substantially all of the assets owned directly by Calpine Corporation, including natural gas and power plant assets and the stock of Calpine Energy Services and other subsidiaries. The July 2003 offerings were comprised of two tranches of floating rate term loans and senior notes and two tranches of fixed rate securities. The floating rate term loans and senior notes included a $750 million, four-year term loan and $500 million of Second-Priority Senior Secured Floating Rate Notes Due 2007. The fixed rate securities included $1.15 billion of 8.5% Second Priority Senior Secured Notes Due 2010 and $900 million of 8.75% Second Priority Senior Secured Notes Due 2013. See Notes 11 and 16 of the Notes to Consolidated Financial Statements for more information.

      Concurrent with the July 2003 offerings, on July 16, 2003, we entered into agreements for a new $500 million working capital facility. The new first-priority senior secured facility consists of a two-year, $300 million working capital revolver and a four-year, $200 million term loan that together provide up to $500 million in combined cash borrowing and letter of credit capacity. The new facility replaced our prior working capital facilities and is secured by a first-priority lien on the same assets that collateralize the July 2003 offerings described above. See Notes 11 and 16 of the Notes to Consolidated Financial Statements for more information.

Application of Critical Accounting Policies

      Our financial statements reflect the selection and application of accounting policies which require management to make significant estimates and judgments. See Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies.” We believe that the following reflect the more critical accounting policies that currently affect our financial condition and results of operations.

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Fair Value of Energy Marketing and Risk Management Contracts and Derivatives

      GAAP requires us to account for certain derivative contracts at fair value. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us. As a result, we are required to rely on internally developed price estimates when external price quotes are unavailable. Our estimates regarding future prices involve a level of uncertainty, and prices actually realized in the future could differ from our estimates.

      We derive our future price estimates, during periods where external price quotes are unavailable, based on an extrapolation of prices from periods where external price quotes are available. We perform this extrapolation using liquid and observable market prices and extending those prices to an internally generated long-term price forecast based on a generalized equilibrium model. We adopted this approach December 31, 2003, for purposes of valuing our commodity derivative instruments. This valuation technique differs from our historical approach. Historically we had extrapolated forward price curves by extrapolating liquid and observable market prices into future periods based on observed year-over-year spreads. While our historical approach was reasonable, we believe the new approach is superior because it incorporates expectations about long-range market fundamentals into the extrapolation. The change did not affect the valuation of the majority of our commodity derivative instruments because of the relative short tenor of those instruments and the fact that the liquid and observable curves under both valuation techniques are the same. The effect of the change on our longer dated derivative commodity instruments resulted in a $12.7 million reduction in the value of our derivative assets, $(13.1) million of which was recognized as a charge to mark-to-market income and $0.4 million of which was recognized as a gain in other comprehensive income.

 
Credit Reserves

      In estimating the fair value of our derivatives, we must take into account the credit risk that our counterparties will not have the financial wherewithal to honor their contract commitments.

      In establishing credit risk reserves we take into account historical default rate data published by the rating agencies based on the credit rating of each counterparty where we have realization exposure, as well as other published data and information.

 
Liquidity Reserves

      We value our forward positions at the mid-market price, or the price in the middle of the bid-ask spread. This creates a risk that the value reported by us as the fair value of our derivative positions will not represent the realizable value or probable loss exposure of our derivative positions if we are unable to liquidate those positions at the mid-market price. Adjusting for this liquidity risk states our derivative assets and liabilities at their most probable value. We use a two-step quantitative and qualitative analysis to determine our liquidity reserve.

      In the first step we quantitatively derive an initial liquidity reserve assessment applying the following assumptions in calculating the initial liquidity reserve assessment: (1) where we have the capability to cover physical positions with our own assets, we assume no liquidity reserve is necessary because we will not have to cross the bid-ask spread in covering the position; (2) we record no reserve against our hedge positions because a high likelihood exists that we will hold our hedge positions to maturity or cover them with our own assets; and (3) where reserves are necessary, we base the reserves on the spreads observed using broker quotes as a starting point.

      Using these assumptions, we calculate the net notional volume exposure at each location by commodity and multiply the result by one half of the bid-ask spread.

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

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Presentation of Revenue Under EITF No. 03-11

      During 2003 the Emerging Issues Task Force (“the Task Force”) discussed EITF Issue No. 03-11. In EITF Issue No. 02-3 the Task Force reached a consensus that companies should present all gains and losses on derivative instruments held for trading purposes net in the income statement, whether or not settled physically. EITF Issue No. 03-11 addresses income statement classification of derivative instruments held for other than trading purposes. At the July 31, 2003, EITF meeting, the Task Force reached a consensus that determining whether realized gains and losses on derivative contracts not ‘held for trading purposes’ should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. The Task Force ratified this consensus at its August 13, 2003, meeting, and it is effective beginning October 1, 2003. The Task Force did not prescribe specific effective date or transition guidance for this Issue. We determined that under the provisions of EITF Issue No. 03-11, transactions which are not physically settled should be reported net for purposes of the Consolidated Statements of Operations. Accordingly, transactions with either of the following characteristics are presented net in our financial statements: (1) transactions executed in a back-to-back buy and sale pair, primarily because of market protocols; and (2) physical power purchase and sale transactions where our power schedulers net the physical flow of the power purchase against the physical flow of the power sale (“book out” the physical power flows) as a matter of scheduling convenience to eliminate the need to schedule actual power deliveries. These book out transactions may occur with the same counterparty or between different counterparties where we have equal but offsetting physical purchase and delivery commitments.

      Based on guidance in EITF Topic No. D-1 “Implications and Implementation of an EITF Consensus” and because EITF Issue No. 03-11 is silent with respect to transition provisions, we have adopted EITF No. 03-11 on a prospective basis effective October 1, 2003. While adoption of EITF No. 03-11 had no effect on our gross profit or net income, it reduced our 2003 sales of purchased power for hedging and optimization and purchased power expense for hedging and optimization by approximately $256.6 million.

 
Accounting for Long-Lived Assets
 
Plant Useful Lives

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

 
Impairment of Long-Lived Assets, Including Intangibles

      We evaluate long-lived assets, such as property, plant and equipment, equity method investments, patents, and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Factors which could trigger an impairment include significant underperformance relative to historical or projected future operating results; significant changes in the manner of our use of the acquired assets or the strategy for our overall business; and significant negative industry or economic trends. Certain of our generating assets are located in regions with depressed demands and market spark spreads. Our forecasts assume that spark spreads will increase in future years in these regions as the supply and demand relationships improve.

      The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. The significant assumptions that we use in our undiscounted future cash flow estimates include the future supply and demand relationships for electricity and natural gas, and the expected pricing for those commodities and the resultant spark spreads in the various regions where we generate. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the fair value of the assets and recording a loss if the fair value was less than the book value. For equity method investments and assets identified as held for sale, the book value is compared to the estimated fair value to determine if an impairment loss is required. For equity method investments, we would record a loss when the decline in value is other than temporary.

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      Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors of our businesses. Our review of factors present and the resulting appropriate carrying value of our intangibles, and other long-lived assets are subject to judgments and estimates that management is required to make. Future events could cause us to conclude that impairment indicators exist and that our intangibles, and other long-lived assets might be impaired.

 
Turbine Impairment Charges

      A significant portion of our overall cost of constructing a power plant is the cost of the gas turbine-generators (GTGs), steam turbine-generators (STGs) and related equipment (collectively the “turbines”). The turbines are ordered primarily from three large manufacturers under long-term, build to order contracts. Payments are generally made over a two to four year period for each turbine. The turbine prepayments are included as a component of construction-in-progress if the turbines are assigned to specific projects probable of being built, and interest is capitalized on such costs. Turbines assigned to specific projects are not evaluated for impairment separately from the project as a whole. Prepayments for turbines that are not assigned to specific projects that are probable of being built are carried in other assets, and interest is not capitalized on such costs. Additionally, our commitments relating to future turbine payments are discussed in Note 24 of the Notes to Consolidated Financial Statements.

      To the extent that there are more turbines on order than are allocated to specific construction projects, we determine the probability that new projects will be initiated to utilize the turbines or that the turbines will be resold to third parties. The completion of in progress projects and the initiation of new projects are dependent on our overall liquidity and the availability of funds for capital expenditures.

      In assessing the impairment of turbines, we must determine both the realizability of the progress payments to date that have been capitalized, as well as the probability that at future decision dates, we will cancel the turbines, forfeiting the prepayment and incurring the cancellation payment, or will proceed and pay the remaining progress payments in accordance with the original payment schedule.

      We apply SFAS No. 5, “Accounting for Contingencies” to evaluate potential future cancellation obligations. We apply SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” to evaluate turbine progress payments made to date and the carrying value of delivered turbines not assigned to projects. At the reporting date, if we believe that it is probable that we will elect the cancellation provisions relating to future decision dates, then the expected future termination payment is also expensed.

 
Oil and Gas Property Valuations

      Successful Efforts Method of Accounting. We follow the successful efforts method of accounting for oil and natural gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated, or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful.

      The successful efforts method of accounting relies on management’s judgment in the designation of wells as either exploratory or developmental, which determines the proper accounting treatment of costs incurred. During 2003 we drilled 186 (net 65.4) development wells and 28 (net 19.5) exploratory wells, of which 178 (net 61.0) development and 18 (net 14.3) exploration were successful. Our operational results may be significantly impacted if we decide to drill in a new exploratory area, which will result in increased seismic costs and potentially increased dry hole costs if the wells are determined to be not successful.

      Successful Efforts Method of Accounting v. Full Cost Method of Accounting. Under the successful efforts method, unsuccessful exploration well cost, geological and geophysical costs, delay rentals, and general and administrative expenses directly allocable to acquisition, exploration, and development activities are

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charged to exploration expense as incurred; whereas, under the full cost method these costs are capitalized and amortized over the life of the reserves.

      A significant sale would have to occur before a gain or loss would be recognized under the full cost method but, when an entire cost center (generally a field) is sold under successful efforts method, a gain or loss is recognized.

      For impairment evaluation purposes, successful efforts requires that individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows, which are generally on a field-by-field basis. Under full cost impairment review, all properties in the depreciation, depletion and amortization pools are assessed against a ceiling based on discounted cash flows, with certain adjustments.

      Though successful efforts and full cost methods are both acceptable under GAAP, historically successful efforts is used by most major companies due to such method being more reflective of current operating results due to expensing of certain exploration activities.

      Impairment of Oil and Gas Properties. We review our oil and gas properties periodically to determine if impairment of such properties is necessary. Property impairments may occur if a field discovers lower than anticipated reserves or if commodity prices fall below a level that significantly affects anticipated future cash flows on the property. Proved oil and gas property values are reviewed when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the current period. During 2003 we recorded approximately $18 million primarily in proved property impairments.

      Oil and Gas Reserves. The process of estimating quantities of proved developed and proved undeveloped crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. Estimates of economically recoverable oil and gas reserves and future net cash flows depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of governmental regulations, operating and workover costs, severance taxes and development costs, all of which may vary considerably from actual results. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such properties.

      We based our estimates of proved developed and proved undeveloped reserves as of December 31, 2003, on estimates made by Netherland, Sewell & Associates, Inc. for reserves in the United States; and Gilbert Laustsen Jung Associates Ltd. for reserves in Canada, both independent petroleum consultants.

 
Capitalized Interest

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

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Accounting for Income Taxes

      To arrive at our worldwide income tax provision significant judgment is required. In the ordinary course of a global business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Some of these uncertainties arise as a consequence of the treatment of capital assets, financing transactions, multistate taxation of operations and segregation of foreign and domestic income and expense to avoid double taxation. Although we believe that our estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our historical income tax provisions and accruals. Such differences could have a material impact on our income tax provision and net income in the period in which such determination is made.

      We record a valuation allowance to reduce our deferred tax assets to the amount of future tax benefit that is more likely than not to be realized. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance, there is no assurance that the valuation allowance would not need to be increased to cover additional deferred tax assets that may not be realizable. Any increase in the valuation allowance could have a material adverse impact on our income tax provision and net income in the period in which such determination is made.

      We provide for United States income taxes on the earnings of foreign subsidiaries unless they are considered permanently invested outside the United States. At December 31, 2003, we had no cumulative undistributed earnings of foreign subsidiaries.

      Our effective income tax rates were (0.1)%, (38.6)% and 33.8% in fiscal 2003, 2002 and 2001, respectively. The effective tax rate in all periods is the result of profits Calpine Corporation and its subsidiaries earned in various tax jurisdictions, both foreign and domestic, that apply a broad range of income tax rates. The provision for income taxes differs from the tax computed at the federal statutory income tax rate due primarily to state taxes and earnings considered as permanently reinvested in foreign operations and the effect of the treatment by foreign jurisdictions of cross border financings. Future effective tax rates could be adversely affected if earnings are lower than anticipated in countries where we have lower statutory rates, if unfavorable changes in tax laws and regulations occur, or if we experience future adverse determinations by taxing authorities after any related litigation. For calendar year 2003 the state tax rate increased over prior years due to a one-time adjustment increasing our deferred state taxes and receiving no benefit for foreign losses in our state tax filings. Our foreign taxes at rates other than statutory include the benefit of cross border financings as well as withholding taxes and foreign valuation allowance. Additionally, our 2003 effective rate was adversely impacted by the recognition of undistributed foreign income (Subpart F) in our U.S. tax return.

      Under SFAS No. 109, “Accounting for Income Taxes,” deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities, and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. SFAS No. 109 provides for the recognition of deferred tax assets if realization of such assets is more likely than not. Based on the weight of available evidence, we have provided a valuation allowance against certain deferred tax assets. The valuation allowance was based on the historical earnings patterns within individual tax jurisdictions that make it uncertain that we will have sufficient income in the appropriate jurisdictions to realize the full value of the assets. We will continue to evaluate the realizability of the deferred tax assets on a quarterly basis.

      At December 31, 2003, we had credit carryforwards, resulting in a $8.1 million tax benefit, which originated from acceleration of deductions on capital assets. We expect to utilize all of the credit carryforwards. We also had federal and state net operating loss carryforwards of $364.8 million, which expire between 2004 and 2023. The federal and state net operating loss carryforwards available are subject to limitations on annual usage. In addition, we had loss carryforwards in certain foreign subsidiaries, resulting in a tax benefit of $113.3 million, the majority of which expire by 2008. It is expected that they will be fully utilized before expiring. The deferred tax asset for the federal and state losses, foreign losses, and other prepaid taxes has been offset by a valuation allowance of $19.3 million.

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Variable Interest Entities and Primary Beneficiary

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

      Significant judgment was required in making our assessment of whether or not a VIE was a special purpose entity (“SPE”) for purposes of applying FIN 46-R as of October 1, 2003. Entities that meet the definition of a business outlined in FIN 46-R and that satisfy other formation and involvement criteria are not subject to the FIN 46-R consolidation guidelines. The definitional characteristics of a business include having: inputs such as long-lived assets; the ability to obtain access to necessary materials and employees; processes such as strategic management, operational process and resource management; and the ability to obtain access to the customers that purchase the outputs of the entity. Since the current accounting literature does not provide a definition of an SPE, our assessment was primarily based on the degree to which a VIE aligned with the definition of a business. Based on this assessment, we determined that three VIEs, Calpine Capital Trusts I, II and III, were SPEs and subject to FIN 46-R as of October 1, 2003. Consequently as discussed in Notes 2 and 11 of the Notes to Consolidated Financial Statements, we deconsolidated these entities.

Initial Adoption of New Accounting Standards in 2003

 
SFAS No. 123 — “Accounting for Stock-Based Compensation” and SFAS No. 148 “Accounting for Stock-Based Compensation — Transition and Disclosure”

      Prior to 2003 we accounted for qualified stock compensation under APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Under APB 25, we were required to recognize stock compensation as expense only to the extent that there is a difference in value between the market price of the stock being offered to employees and the price those employees must pay to acquire the stock. The expense measurement methodology provided by APB 25 is commonly referred to as the “intrinsic value based method.” To date, our stock compensation program has been based primarily on stock options whose exercise prices are equal to the market price of Calpine stock on the date of the stock option grant; consequently, under APB25 we had historically incurred minimal stock compensation expense. On January 1, 2003, we prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”) as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (SFAS No. 148”). SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for companies that voluntarily change their accounting for stock-based compensation from the less preferred intrinsic value based method to the more preferred fair value based method. Prior to its amendment, SFAS No. 123 required that companies enacting a voluntary change in accounting principle from the intrinsic value methodology provided by APB 25 could only do so on a prospective basis; no adoption or transition provisions were established to allow for a restatement of prior period financial statements. SFAS No. 148 provides two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We elected to adopt the provisions of SFAS No. 123 on a prospective

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basis; consequently, we are required to provide a pro-forma disclosure of net income and earnings per share as if SFAS No. 123 accounting had been applied to all prior periods presented within our financial statements.

      Under SFAS No. 123, the fair value of a stock option or its equivalent is estimated on the date of grant by using an option-pricing model, such as the Black-Scholes model or a binomial model. The option-pricing model selected should take into account, as of the stock option’s grant date, the exercise price and expected life of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock, and the risk-free interest rate for the expected term of the stock option.

      The fair value calculated by this model is then recognized as compensation expense over the period in which the related employee services are rendered. Unless specifically defined within the provisions of the stock option granted, the service period is presumed to begin on the grant date and end when the stock option is fully vested. Depending on the vesting structure of the stock option and other variables that are built into the option-pricing model, the fair value of the stock option is recognized over the service period using either a straight-line method (the single option approach) or a more conservative, accelerated method (the multiple option approach). For consistency, we have chosen the multiple option approach, which we have used historically for pro-forma disclosure purposes. The multiple option approach views one four-year option grant as four separate sub-grants, each representing 25% of the total number of stock options granted. The first sub-grant vests over one year, the second sub-grant vests over two years, the third sub-grant vests over three years, and the fourth sub-grant vests over four years. Under this scenario, over 50% of the total fair value of the stock option grant is recognized during the first year of the vesting period, and nearly 80% of the total fair value of the stock option grant is recognized by the end of the second year of the vesting period. By contrast, if we were to apply the single option approach, only 25% and 50% of the total fair value of the stock option grant would be recognized as compensation expense by the end of the first and second years of the vesting period, respectively.

      We have selected the Black-Scholes model, primarily because it is the most commonly recognized options-pricing model among U.S.-based corporations. Nonetheless, we believe this model tends to overstate the true fair value of our employee stock options in that our options cannot be freely traded, have vesting requirements, and are subject to blackout periods during which, even if vested, they cannot be traded. We will monitor valuation trends and techniques as more companies adopt SFAS No. 123 and as additional guidance is provided by FASB and review our choices as appropriate in the future. The key assumption in our Black-Scholes model is the expected life of the stock option, because it is this figure that drives our expected volatility calculation, as well as our risk-free interest rate. The expected life of the option relies on two factors — the option’s vesting period and the expected term that an employee holds the option once it has vested. There is no single method described by SFAS No. 123 for predicting future events such as how long an employee holds on to an option or what the expected volatility of a company’s stock price will be; the facts and circumstances are unique to different companies and depend on factors such as historical employee stock option exercise patterns, significant changes in the market place that could create a material impact on a company’s stock price in the future, and changes in a company’s stock-based compensation structure.

      We base our expected option terms on historical employee exercise patterns. We have segregated our employees into four different categories based on the fact that different groups of employees within our company have exhibited different stock exercise patterns in the past, usually based on employee rank and income levels. Therefore, we have concluded that we will perform separate Black-Scholes calculations for four employee groups — executive officers, senior vice presidents, vice presidents, and all other employees.

      We compute our expected stock price volatility based on our stock’s historical movements. For each employee group, we measure the volatility of our stock over a period that equals the expected term of the option. In the case of our executive officers, this means we measure our stock price volatility dating back to our public inception in 1996, because these employees are expected to hold their options for over 7 years after the options have fully vested. In the case of other employees, volatility is only measured dating back 4 years. In the short run, this causes other employees to generate a higher volatility figure than the other company employee groups because our stock price has fluctuated significantly in the past four years. As of December 31, 2003, the volatility for our employee groups ranged from 70%-113%.

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      See Note 2 of the Notes to Consolidated Financial Statements for additional information related to the January 1, 2003, adoption of SFAS Nos. 123 and 148 and the pro-forma impact that they would have had on our net income for the years ended December 31, 2003, 2002 and 2001.

 
SFAS No. 143 — “Accounting for Asset Retirement Obligations”

      In June 2001 FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 applies to fiscal years beginning after June 15, 2002 and amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” This standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the assets and requires that a liability for an asset retirement obligation be recognized when incurred, recorded at fair value and classified as a liability in the balance sheet. When the liability is initially recorded, the entity will capitalize the cost and increase the carrying value of the related long-lived asset. Asset retirement obligations represent future liabilities, and, as a result, accretion expense will be accrued on this liability until the obligation is satisfied. At the same time, the capitalized cost will be depreciated over the estimated useful life of the related asset. At the settlement date, the entity will settle the obligation for its recorded amount or recognize a gain or loss upon settlement.

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

 
FIN 45 — “Guarantors Accounting and Disclosure for Guarantees, Including Indirect Guarantees of Indebtedness of Others”

      In November 2002 FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 elaborates on the existing disclosure requirements for most guarantees. FIN 45 also clarifies that at the time a company issues a guarantee, it must recognize an initial liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that specified triggering events or conditions occur. The initial recognition and initial measurement provisions apply on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements for FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002, and have been incorporated into our December 31, 2003, disclosures of guarantees in the Notes to Consolidated Financial Statements. Adoption of this Interpretation did not have a material impact on our Consolidated Financial Statements. See “Commercial Commitments” in the Liquidity and Capital Resources section and Note 24 of the Notes to Consolidated Financial Statements for the disclosures.

 
FIN 46 — “Consolidation of Variable Interest Entities, An Interpretation of ARB 51”

      See “Variable Interest Entities (“VIE”) and Primary Beneficiary” above for a discussion of the judgment involved in FIN 46.

 
Derivatives Implementation Group Issue No. C20

      In June 2003 FASB issued Derivatives Implementation Group (“DIG”) Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” DIG Issue No. C20 superseded DIG Issue No. C11

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“Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception,” and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 is effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for us) with early application permitted. In conjunction with initially applying the implementation guidance, DIG Issue No. C20 requires the recognition of a special transition adjustment for certain contracts containing a price adjustment feature based on a broad market index for which the normal purchases and normal sales scope exception had been previously elected. In those circumstances, the derivative contract should be recognized at fair value as of the date of the initial application with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle. It should then be applied prospectively for all existing contracts as of the effective date and for all future transactions.

      Two of our power sales contracts, which meet the definition of a derivative and for which we previously elected the normal purchases and normal sales scope exception, use a CPI or similar index to escalate the Operations and Maintenance (“O&M”) charges. Adoption of DIG Issue No. C20 required us to recognize a special transition accounting adjustment for the estimated future economic benefits of these contracts. We based the transition adjustment on the nature and extent of the key price adjustment features in the contracts and estimated future market conditions on the date of adoption, such as the forward price of power and natural gas and the expected rate of inflation. We will realize the actual future economic benefits of these contracts over the remaining lives of these contracts which extend through 2013 and 2023 as actual power deliveries occur, although DIG Issue No. C20 required us to account for the estimated future economic benefits currently. We will amortize the corresponding asset recorded upon adoption of DIG Issue No. C20 through a charge to earnings in future periods. Accordingly on October 1, 2003, the date we adopted DIG Issue No. C20, we recorded other current assets and other assets of approximately $33.5 million and 259.9 million, respectively, and a cumulative effect of a change in accounting principle of approximately $181.9 million, net of $111.5 million of tax. For all periods subsequent to October 1, 2003, we will account for the contracts as normal purchases and sales under the provisions of DIG Issue No. C20.

EITF Issue No. 01-08 — “Determining Whether an Arrangement Contains a Lease”

      In May 2003 the EITF reached consensus in EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. Prior to adopting EITF Issue No. 01-08, we had accounted for certain contractual arrangements as leases under existing industry practices, and the adoption of EITF Issue No. 01-08 did not materially change accounting for previous arrangements that had been accounted for as leases prior to the adoption of EITF Issue No. 01-08. Currently the income to us under these arrangements is immaterial; however, we may, in the future, structure additional power purchase agreements as leases. For income statement presentation purposes, income from arrangements accounted for as leases is classified within electricity and steam revenue in our consolidated statements of operations.

Impact of Recent Accounting Pronouncements

 
SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities”

      FASB in recent years has issued numerous new accounting standards that have already taken effect or will soon impact us. In Note 2 of our Notes to Consolidated Financial Statements we invite your attention to a discussion of several new standards, emerging issues and interpretations under the section entitled “New Accounting Pronouncements.”

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      Below is a detailed discussion of how we apply SFAS No. 133 since this accounting standard has a profound impact on how we account for our energy contracts and transactions.

      On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133 — an Amendment of FASB Statement No. 133,” and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an Amendment of FASB Statement No. 133.” We currently hold six classes of derivative instruments that are impacted by the new pronouncement — foreign currency swaps, interest rate swaps, forward interest rate agreements, commodity financial instruments, commodity contracts, and physical options.

      Consistent with the requirements of SFAS No. 133, we evaluate all of our contracts to determine whether or not they qualify as derivatives under the accounting pronouncement. For a given contract, there are typically three steps we use to determine its proper accounting treatment. First, based on the terms and conditions of the contract, as well as the applicable guidelines established by SFAS No. 133, we identify the contract as being either a derivative or non-derivative contract. Second, if the contract is not a derivative, we further identify its specific classification (e.g. whether or not it qualifies as a lease) and apply the appropriate non-derivative accounting treatment. Alternatively, if the contract does qualify as a derivative under the guidance of SFAS No. 133, we evaluate whether or not it qualifies for the “normal” purchases and sales exception (as described below). If the contract qualifies for the exception, we apply the traditional accrual accounting treatment. Finally, if the contract qualifies as a derivative and does not qualify for the “normal” purchases and sales exception, we apply the accounting treatment required by SFAS No. 133, which is outlined below in further detail. The diagram below illustrates the process we use for the purposes of identifying the classification and subsequent accounting treatment of our contracts:

Classification Flow Chart

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      As an independent power producer primarily focused on generation of electricity using gas-fired turbines, our natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power capacity (i.e., electricity seller). Additionally, we also have a natural “long” crude position due to our petroleum reserves. To manage forward exposure to price fluctuation, we execute commodity derivative contracts as defined by SFAS No. 133. As we apply SFAS No. 133, derivatives can receive one of four treatments depending on associated circumstances: 1. exemption from SFAS No. 133 accounting treatment if these contracts qualify as “normal” purchases and sales contracts; 2. fair value hedges; 3. cash flow hedges; or 4. undesignated derivatives.

 
Normal Purchases and Sales

      Normal purchases and sales, as defined by paragraph 10b. of SFAS No. 133 and amended by SFAS No. 138, are exempt from SFAS No. 133 accounting treatment. As a result, these contracts are not required to be recorded on the balance sheet at their fair values and any fluctuations in these values are not required to be reported within earnings. Probability of physical delivery from our generation plants, in the case of electricity sales, and to our generation plants, in the case of natural gas contracts, is required over the life of the contract within reasonable tolerances.

      On June 27, 2001, FASB cleared SFAS No. 133 Implementation Issue No. C15 dealing with a proposed electric industry normal purchases and sales exception for capacity sales transactions (“The Eligibility of Option Contracts in Electricity for the Normal Purchases and Normal Sales Exception”). On December 19, 2001, FASB revised the criteria for qualifying for the “normal” exception. As a result of Issue No. C15, as revised, certain power purchase and/or sale agreements that are structured as capacity sales contracts are now eligible to qualify for the normal purchases and sales exception. Because we are “long” power capacity, we often enter into capacity sales contracts as a means to recover the costs incurred from maintaining and operating our power plants as well as the costs directly associated with the generation and sale of electricity to our customers. Under Issue No. C15, a capacity sales contract qualifies for the normal purchases and sales exception subject to certain conditions. A majority of our capacity sales contracts qualify for the normal purchases and sales exception.

 
Cash Flow Hedges and Fair Value Hedges

      Within the energy industry, cash flow and fair value hedge transactions typically use the same types of standard transactions (i.e., offered for purchase/ sale in over-the-counter markets or commodity exchanges).

 
Fair Value Hedges

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

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Cash Flow Hedges

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

Cash Flow Hedges Flow Chart

      Certain contracts could either qualify for exemption from SFAS No. 133 accounting as normal purchases or sales or be designated as effective hedges. Our marketing and sales and fuels groups generally transact with load serving entities and other end-users of electricity and with fuel suppliers, respectively, in physical contracts where delivery is expected. These transactions are structured as normal purchases and sales, when possible, and if the normal exception is not allowed, we seek to structure the transactions as cash flow hedges. Conversely, our CES risk management desks generally transact in over-the-counter or exchange traded contracts, in hedging transactions. These transactions are designated as hedges when possible, notwithstanding the fact that some might qualify as normal purchases or sales.

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Undesignated Derivatives

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

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

      Accumulated other comprehensive income (“AOCI”) includes the following components: (i) unrealized pre-tax gains/losses, net of reclassification-to-earnings adjustments, from effective cash flow hedges as designated pursuant to SFAS No. 133, (see Note 22 of the Notes to Consolidated Financial Statements); (ii) unrealized pre-tax gains/losses that result from the translation of foreign subsidiaries’ balance sheets from the foreign functional currency to our consolidated reporting currency (US $); (iii) other comprehensive income from equity method investees; and (iv) the taxes associated with the unrealized gains/losses from items (i) and (iii). See Note 20 of the Notes to Consolidated Financial Statements for further information.

      One result of our adoption on January 1, 2001, of SFAS No. 133 has been volatility in the AOCI component of Stockholders’ Equity on the balance sheet. As explained in Notes 20 and 22 of the Notes to Consolidated Financial Statements, our AOCI balances are primarily related to our cash flow hedging and currency translation activity. The quarterly balances for 2003 in AOCI related to cash flow hedging activity are summarized in the table below (in thousands).

                                 
Quarter Ended

December 31 September 30 June 30 March 31




AOCI balances related to cash flow hedging
  $ (130,419 )   $ (129,387 )   $ (162,762 )   $ (193,265 )

      Note that the amounts above represent AOCI from cash flow hedging activity only. For further information on other components of our total AOCI balance at December 31, 2003, see Note 20 of the Notes to Consolidated Financial Statements.

 
Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

 
Item 8. Financial Statements and Supplementary Data

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

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

      On April 10, 2003, we and our former auditors, Deloitte & Touche LLP (“Deloitte”), ceased our client auditor relationship. On that date, the following events occurred:

  (1) Deloitte notified the Chairman of the Audit Committee of our Board of Directors that Deloitte resigned its audit relationship with us.
 
  (2) Our Audit Committee and Board of Directors determined to no longer utilize the audit services of Deloitte and approved the appointment of PricewaterhouseCoopers LLP to serve as our independent public accountants for the fiscal year ended December 31, 2003.

      Deloitte has not included, in any report on our financial statements, an adverse opinion or a disclaimer of opinion, or a qualification or modification as to uncertainty, audit scope, or accounting principles with respect to our financial statements.

      During our prior fiscal year ended December 31, 2002, and the subsequent interim period through April 10, 2003, (i) other than described in the paragraph immediately following this paragraph, there were no disagreements between us and Deloitte on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to Deloitte’s satisfaction, would have caused Deloitte to make reference to the subject matter of the disagreement in connection with its reports of our financial statements, and (ii) there were no “reportable events” (as that term is defined in Item 304(a)(1)(v) of Regulation S-K).

      We had a disagreement with Deloitte, which was satisfactorily resolved, related to the interpretation of certain provisions of power sales agreements associated with two power plants for which we had utilized sale-leaseback transactions. We had previously accounted for these sale-leaseback transactions as qualifying for operating lease accounting treatment. Deloitte concluded that the provisions of the power sales agreements precluded operating lease accounting treatment. Our Audit Committee and Board of Directors discussed the subject matter of the disagreement with Deloitte. We recorded adjustments related to these matters in the 2000 and 2001 consolidated financial statements and adjusted the previously announced unaudited financial statements for 2002.

      We have authorized Deloitte to respond fully to the inquiries of PricewaterhouseCoopers LLP concerning the subject matter of the foregoing disagreement.

      During our two most recent fiscal years, and the subsequent interim period through April 10, 2003, neither we nor anyone on our behalf consulted PricewaterhouseCoopers LLP regarding the application of accounting principles to a specified transaction, either completed or proposed, regarding the type of audit opinion that might be rendered on our financial statements or regarding “disagreements” (as that term is defined in Item 304(a)(1)(iv) of Regulation S-K, including the disagreements noted herein) or any “reportable events” (as that term is defined in Item 304(a)(1)(v) of Regulation S-K).

 
Item 9A. Controls and Procedures

      The Company’s Chief Executive Officer and Chief Financial Officer, based on the evaluation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities and Exchange Act of 1934, as amended) required by paragraph (b) of Rule 13a-15 or Rule 15d-15, as of December 31, 2003, have concluded that the Company’s disclosure controls and procedures were effective to ensure the timely collection, evaluation and disclosure of information relating to the Company that would potentially be subject to disclosure under the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder with the exception of the deficiencies noted below.

      In connection with the audit of our financial statements for the fiscal year ended December 31, 2003, our independent auditors reviewed our information systems control framework and identified to us certain significant deficiencies in the design of such systems. These design deficiencies generally related to the number of persons having access to certain of our information systems databases, as well as the segregation of duties of persons with such access. The Company has concluded that, in the aggregate, these deficiencies constituted a

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material control weakness, and the Company has performed substantial analytical and post-closing procedures as a result of these design deficiencies. Based on the Company’s compensating controls and testing, we have concluded that these design deficiencies did not result in any material errors in our financial statements. Additionally, we have completed the process of correcting these design deficiencies and are in the process of testing the effectiveness of these changes. Other than correcting the material control weakness identified above, there were no other changes in the Company’s internal controls over financial reporting identified in connection with the evaluation required by paragraph (d) of the Rule 13a-15 or Rule 15d-15 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

PART III

 
Item 10. Directors and Executive Officers of the Registrant

      Incorporated by reference to Proxy Statement relating to the 2004 Annual Meeting of Stockholders to be filed.

 
Item 11. Executive Compensation

      Incorporated by reference to Proxy Statement relating to the 2004 Annual Meeting of Stockholders to be filed.

 
Item 12. Security Ownership of Certain Beneficial Owners and Management

      Incorporated by reference to Proxy Statement relating to the 2004 Annual Meeting of Stockholders to be filed.

Equity Compensation Plan Information

      The following table provides certain information, as of December 31, 2003, concerning certain compensation plans under which our equity securities are authorized for issuance.

                             
Number of Securities Weighted Average Number of Securities Remaining
to be Issued Upon Exercise Price of Available for Future Issuance
Exercise of Outstanding Under Equity Compensation
Outstanding Options, Options, Warrants Plans (Excluding Securities
Plan Category Warrants, and Rights and Rights Reflected in Column (a))




Equity compensation plans approved by security holders
                       
 
Calpine Corporation 1992 Stock Incentive Plan(1)
    4,996,798     $ 0.784        
 
Encal Energy Ltd. Stock Option Plan(2)
    126,219       34.693        
 
Calpine Corporation 1996 Stock Incentive Plan
    28,715,414       9.427       5,816,080  
 
Calpine Corporation 2000 Employee Stock Purchase Plan
                    4,405,560  
 
Equity compensation plans not approved by security holders
                 
     
     
     
 
   
Total
    33,838,431     $ 8.245       10,221,640  
     
     
     
 


(1)  The Calpine Corporation 1992 Stock Incentive Plan was approved in 1992 by the Company’s sole security holder at the time, Electrowatt Ltd.
 
(2)  In connection with the merger with Encal Energy Ltd., which closed in 2001, we assumed the Encal Energy Fifth Amended and Restated Stock Option Plan. 126,219 shares of our common stock are subject

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to issuance upon exercise of options granted pursuant to this plan at a weighted average exercise price of $34.693. Other than the shares reserved for future issuance upon the exercise of these options, there are no securities available for future issuance under this Plan.
 
Item 13. Certain Relationships and Related Transactions

      Incorporated by reference to Proxy Statement relating to the 2004 Annual Meeting of Stockholders to be filed.

 
Item 14. Principal Accounting Fees and Services

      Incorporated by reference to Proxy Statement relating to the 2004 Annual Meeting of Stockholders to be filed.

PART IV

 
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

      (a)-1. Financial Statements and Other Information

      The following items appear in Appendix F of this report:

  Reports of Independent Auditors
  Consolidated Balance Sheets, December 31, 2003 and 2002
  Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002, and 2001
  Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002,
     and 2001
  Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002, and 2001
  Notes to Consolidated Financial Statements for the Years Ended December 31, 2003, 2002, and 2001

      (a)-2. Financial Statement Schedules

      Schedule II — Valuation and Qualifying Accounts

      (b) Reports on Form 8-K

      The registrant filed the following reports on Form 8-K during the quarter ended December 31, 2003:

                 
Date of Report Date Filed or Furnished Item Reported



10/1/03
    10/1/03       5  
10/3/03
    10/8/03       5  
10/6/03
    10/8/03       5  
10/15/03
    10/16/03       5  
10/21/03
    10/22/03       5  
12/31/02
    10/23/03       5,7  
11/5/03
    11/6/03       12  
11/6/03
    11/6/03       5  
11/6/03
    11/7/03       5  
11/11/03
    11/12/03       5  
11/17/03
    11/17/03       5  
11/20/03
    11/20/03       5  
11/26/03
    11/26/03       5  
12/4/03
    12/5/03       5  
12/15/03
    12/15/03       5  

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  (c)  Exhibits

      The following exhibits are filed herewith unless otherwise indicated:

         
Exhibit
Number Description


  3.1.1     Amended and Restated Certificate of Incorporation of Calpine Corporation.(a)
  3.1.2     Certificate of Correction of Calpine Corporation.(b)
  3.1.3     Certificate of Amendment of Amended and Restated Certificate of Incorporation of Calpine Corporation.(c)
  3.1.4     Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation.(b)
  3.1.5     Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation.(b)
  3.1.6     Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation.(c)
  3.1.7     Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation.(d)
  3.1.8     Certificate of Ownership and Merger Merging Calpine Natural Gas GP, Inc. into Calpine Corporation.(e)
  3.1.9     Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation.(e)
  3.1.10     Amended and Restated By-laws of Calpine Corporation.(f)
  4.1.1     Indenture dated as of May 16, 1996, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(g)
  4.1.2     First Supplemental Indenture dated as of August 1, 2000, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(b)
  4.2.1     Indenture dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(h)
  4.2.2     Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(i)
  4.2.3     Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(b)
  4.3.1     Indenture dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(j)
  4.3.2     Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(j)
  4.3.3     Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(b)
  4.4.1     Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(k)
  4.4.2     First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(b)
  4.5.1     Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(k)
  4.5.2     First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(b)
  4.6.1     Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(l)
  4.6.2     First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(b)
  4.7     Indenture, dated as of April 30, 2001, between the Company and Wilmington Trust Company, as Trustee.(m)

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Exhibit
Number Description


  4.8.1     Amended and Restated Indenture dated as of October 16, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee.(n)
  4.8.2     Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(o)
  4.8.3     First Amendment, dated as of October 16, 2001, to Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(n)
  4.9.1     Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(n)
  4.9.2     First Supplemental Indenture, dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(n)
  4.9.3     Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(n)
  4.9.4     First Amendment, dated as of October 18, 2001, to Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(n)
  4.10     Indenture, dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(p)
  4.11     Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(p)
  4.12     Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(p)
  4.13     Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(p)
  4.14.1     Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee, including form of Notes.(q)
  4.14.2     Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q)
  4.14.3     Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(*)
  4.14.4     Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(*)
  4.15     Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy Center, as Guarantors, and Wilmington Trust Company, as Trustee and Collateral Agent, including form of Notes.(q)
  4.16     Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(*)
  4.17.1     Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(*)
  4.17.2     Registration Rights Agreement, dated as of November 14, 2003, between the Company and Deutsche Bank Securities, Inc., as Representative of the Initial Purchasers.(*)
  4.18     Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(r)
  4.19     First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(*)

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Exhibit
Number Description


  4.20     Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(*)
  4.21     Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(*)
  4.22     HIGH TIDES I.
  4.22.1     Certificate of Trust of Calpine Capital Trust, a Delaware statutory trust, dated September 29, 1999.(s)
  4.22.2     Corrected Certificate of Certificate of Trust of Calpine Capital Trust, a Delaware statutory trust, filed October 4, 1999.(s)
  4.22.3     Declaration of Trust of Calpine Capital Trust, dated as of October 4, 1999, among Calpine Corporation, as Depositor, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee, and the Administrative Trustees named therein.(s)
  4.22.4     Indenture, dated as of November 2, 1999, between Calpine Corporation and The Bank of New York, as Trustee, including form of Debenture.(s)
  4.22.5     Remarketing Agreement, dated November 2, 1999, among Calpine Corporation, Calpine Capital Trust, The Bank of New York, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(s)
  4.22.6     Amended and Restated Declaration of Trust of Calpine Capital Trust, dated as of November 2, 1999, among Calpine Corporation, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, and The Bank of New York, as Property Trustee, and the Administrative Trustees named therein, including form of Preferred Security and form of Common Security.(s)
  4.22.7     Preferred Securities Guarantee Agreement, dated as of November 2, 1999, between Calpine Corporation and The Bank of New York, as Guarantee Trustee.(s)
  4.23     HIGH TIDES II.
  4.23.1     Certificate of Trust of Calpine Capital Trust II, a Delaware statutory trust, filed January 25, 2000.(t)
  4.23.2     Declaration of Trust of Calpine Capital Trust II, dated as of January 24, 2000, among Calpine Corporation, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee, and the Administrative Trustees named therein.(t)
  4.23.3     Indenture, dated as of January 31, 2000, between Calpine Corporation and The Bank of New York, as Trustee, including form of Debenture.(t)
  4.23.4     Remarketing Agreement, dated as of January 31, 2000, among Calpine Corporation, Calpine Capital Trust II, The Bank of New York, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(t)
  4.23.5     Registration Rights Agreement, dated January 31, 2000, among Calpine Corporation, Calpine Capital Trust II, Credit Suisse First Boston Corporation and ING Barings LLC.(t)
  4.23.6     Amended and Restated Declaration of Trust of Calpine Capital Trust II, dated as of January 31, 2000, among Calpine Corporation, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee, and the Administrative Trustees named therein, including form of Preferred Security and form of Common Security.(t)
  4.23.7     Preferred Securities Guarantee Agreement, dated as of January 31, 2000, between Calpine Corporation and The Bank of New York, as Guarantee Trustee.(t)
  4.24     HIGH TIDES III.
  4.24.1     Amended and Restated Certificate of Trust of Calpine Capital Trust III, a Delaware statutory trust, filed July 19, 2000.(u)

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Exhibit
Number Description


  4.24.2     Declaration of Trust of Calpine Capital Trust III dated June 28, 2000, among the Company, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee and the Administrative Trustees named therein.(u)
  4.24.3     Amendment No. 1 to the Declaration of Trust of Calpine Capital Trust III dated July 19, 2000, among the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein.(u)
  4.24.4     Indenture dated as of August 9, 2000, between the Company and Wilmington Trust Company, as Trustee.(u)
  4.24.5     Remarketing Agreement dated as of August 9, 2000, among the Company, Calpine Capital Trust III, Wilmington Trust Company, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(u)
  4.24.6     Registration Rights Agreement dated as August 9, 2000, between the Company, Calpine Capital Trust III, Credit Suisse First Boston Corporation, ING Barings LLC and CIBC World Markets Corp.(u)
  4.24.7     Amended and Restated Declaration of Trust of Calpine Capital Trust III dated as of August 9, 2000, the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein, including the form of Preferred Security and form of Common Security.(u)
  4.24.8     Preferred Securities Guarantee Agreement dated as of August 9, 2000, between the Company, as Guarantor, and Wilmington Trust Company, as Guarantee Trustee.(u)
  4.25     PASS THROUGH CERTIFICATES (TIVERTON AND RUMFORD).
  4.25.1     Pass Through Trust Agreement dated as of December 19, 2000, among Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of Certificate.(b)
  4.25.2     Participation Agreement dated as of December 19, 2000, among the Company, Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership, PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee.(b)
  4.25.3     Appendix A — Definitions and Rules of Interpretation.(b)
  4.25.4     Indenture of Trust, Mortgage and Security Agreement, dated as of December 19, 2000, between PMCC Calpine New England Investment LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, including the forms of Lessor Notes.(b)
  4.25.5     Calpine Guaranty and Payment Agreement (Tiverton) dated as of December 19, 2000, by Calpine, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(b)
  4.25.6     Calpine Guaranty and Payment Agreement (Rumford) dated as of December 19, 2000, by Calpine, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(b)
  4.26     PASS THROUGH CERTIFICATES (SOUTH POINT, BROAD RIVER AND ROCKGEN).
  4.26.1     Pass Through Trust Agreement A dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 8.400% Pass Through Certificate, Series A.(f)

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  4.26.2     Pass Through Trust Agreement B dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 9.825% Pass Through Certificate, Series B.(f)
  4.26.3     Participation Agreement (SP-1) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.4     Participation Agreement (SP-2) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.5     Participation Agreement (SP-3) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.6     Participation Agreement (SP-4) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.7     Participation Agreement (BR-1) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.8     Participation Agreement (BR-2) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.9     Participation Agreement (BR-3) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.10     Participation Agreement (BR-4) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)

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Exhibit
Number Description


  4.26.11     Participation Agreement (RG-1) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.12     Participation Agreement (RG-2) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.13     Participation Agreement (RG-3) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.14     Participation Agreement (RG-4) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.15     Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)
  4.26.16     Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)
  4.26.17     Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)
  4.26.18     Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)
  4.26.19     Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)
  4.26.20     Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)
  4.26.21     Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)

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Exhibit
Number Description


  4.26.22     Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)
  4.26.23     Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)
  4.26.24     Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)
  4.26.25     Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)
  4.26.26     Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)
  4.26.27     Calpine Guaranty and Payment Agreement (South Point SP-1) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.28     Calpine Guaranty and Payment Agreement (South Point SP-2) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.29     Calpine Guaranty and Payment Agreement (South Point SP-3) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.30     Calpine Guaranty and Payment Agreement (South Point SP-4) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.31     Calpine Guaranty and Payment Agreement (Broad River BR-1) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.32     Calpine Guaranty and Payment Agreement (Broad River BR-2) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.33     Calpine Guaranty and Payment Agreement (Broad River BR-3) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.34     Calpine Guaranty and Payment Agreement (Broad River BR-4) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)

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Exhibit
Number Description


  4.26.35     Calpine Guaranty and Payment Agreement (RockGen RG-1) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.36     Calpine Guaranty and Payment Agreement (RockGen RG-2) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.37     Calpine Guaranty and Payment Agreement (RockGen RG-3) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.38     Calpine Guaranty and Payment Agreement (RockGen RG-4) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  10.1     Financing Agreements.
  10.1.1.1     Calpine Construction Finance Company Financing Agreement (“CCFC II”), dated as of October 16, 2000.(b)(v)
  10.1.1.2     Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(*)
  10.1.2.1     Amended and Restated Credit Agreement, dated as of July 16, 2003 (“Amended and Restated Credit Agreement”), among the Company, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, Funding Agent, Lead Arranger and Bookrunner, Bayerische Landesbank, Cayman Islands Branch, as Lead Arranger, as Co-Bookrunner and Documentation Agent, and ING Capital LLC and Toronto Dominion (Texas) Inc., as Lead Arrangers, Co-Bookrunners and Syndication Agents.(p)
  10.1.2.2     First Amendment to Amended and Restated Credit Agreement, dated as of August 7, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(p)
  10.1.2.3     Amendment and Waiver to Amended and Restated Credit Agreement, dated as of August 28, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(q)
  10.1.2.4     Letter Agreement regarding Technical Correction to Amendment and Waiver to Amended and Restated Credit Agreement, dated as of September 5, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(q)
  10.1.2.5     Third Amendment to Amended and Restated Credit Agreement, dated as of November 6, 2003, among the Company, each of Quintana Minerals (USA) Inc., JOQ Canada, Inc., and Quintana Canada Holdings, LLC, as a Guarantor, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(q)
  10.1.2.6     Fourth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of November 19, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(*)
  10.1.2.7     Fifth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of December 30, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(*)

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Exhibit
Number Description


  10.1.2.8     Technical Correction to Fifth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of December 31, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(*)
  10.1.2.9     Waiver to Amended and Restated Credit Agreement, dated as of March 5, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(*)
  10.1.3     Letter of Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent.(p)
  10.1.4     Guarantee and Collateral Agreement, dated as of July 16, 2003, made by Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.5     First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.6     First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.7.1     Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.7.2     Amendment No. 1 to the Second Amendment Pledge Agreement (Stock Interests), dated as of November 18, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(*)
  10.1.8.1     Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.8.2     Amendment No. 1 to the Second Amendment Pledge Agreement (Membership Interests), dated as of November 18, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(*)
  10.1.9     First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.10. 1   Collateral Trust Agreement, dated as of July 16, 2003, among Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(p)
  10.1.10. 2   First Amendment to the Collateral Trust Agreement, dated as of November 18, 2003, among Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(*)
  10.1.11     Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from Calpine Corporation to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee.(p)
  10.1.12     Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(p)
  10.1.13     Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(p)

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Exhibit
Number Description


  10.1.14     Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(p)
  10.1.15     Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee.(p)
  10.1.16     Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee.(p)
  10.1.17     Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee.(p)
  10.1.18     Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee.(p)
  10.1.19     Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from Calpine Corporation to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.20     Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.21     Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.22     Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee.(p)
  10.1.23     Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.24     Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.25     Designated Asset Sale Proceeds Account Control Agreement, dated as of July 16, 2003, among Calpine Corporation, Union Bank of California, N.A., and The Bank of New York, as Collateral Agent.(*)
  10.2     Term Loan Agreements.
  10.2.1     Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents.(p)
  10.2.2.1     Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q)
  10.2.2.2     Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q)

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Exhibit
Number Description


  10.2.2.3     Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)
  10.2.2.4     Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)
  10.2.3     Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(*)
  10.2.4     Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(*)
  10.3     Management Contracts or Compensatory Plans or Arrangements.
  10.3.1     Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(*)(w)
  10.3.2     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Mr. Peter Cartwright.(t)(w)
  10.3.3     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Ms. Ann B. Curtis.(f)(w)
  10.3.4     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Mr. Ron A. Walter.(f)(w)
  10.3.5     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Mr. Robert D. Kelly.(f)(w)
  10.3.6     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Mr. Thomas R. Mason.(f)(w)
  10.3.7     Consulting Contract, dated as of January 1, 2004, between Calpine Corporation and Mr. George J. Stathakis. (*)(w)
  10.3.8     Calpine Corporation Annual Management Incentive Plan.(x)(w)
  10.3.9     $500,000 Promissory Note Secured by Deed of Trust made by Thomas R. Mason and Debra J. Mason in favor of Calpine Corporation.(x)(w)
  10.3.10     2000 Employee Stock Purchase Plan (y)(w)
  10.3.11     Form of Indemnification Agreement for directors and officers.(z)(w)
  10.3.12     Form of Indemnification Agreement for directors and officers.(f)(w)
  12.1     Statement on Computation of Ratio of Earnings to Fixed Charges.(*)
  21.1     Subsidiaries of the Company.(*)
  23.1     Consent of Deloitte & Touche LLP, Independent Public Accountants.(*)
  23.2     Consent of PricewaterhouseCoopers LLP, Independent Public Accountants.(*)
  23.3     Consent of Netherland, Sewell & Associates, Inc., independent engineer.(*)
  23.4     Consent of Gilbert Laustsen Jung Associates, Ltd., independent engineer.(*)
  24.1     Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this report).(*)
  31.1     Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)

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Exhibit
Number Description


  31.2     Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
  32.1     Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*)
  99.1     Acadia Power Partners, LLC and Subsidiary, Consolidated Financial Statements, December 31, 2003, 2002 and 2001.(*)
  99.2     Consent of PricewaterhouseCoopers LLP, Independent Public Accountants.(*)


 
(*) Filed herewith.
 
(a) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-40652) filed with the SEC on June 30, 2000.
 
(b) Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.
 
(c) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-66078) filed with the SEC on July 27, 2001.
 
(d) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.
 
(e) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2002, filed with the SEC on May 15, 2002.
 
(f) Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2001, filed with the SEC on March 29, 2002.
 
(g) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-06259) filed with the SEC on June 19, 1996.
 
(h) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.
 
(i) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-41261) filed with the SEC on November 28, 1997.
 
(j) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-61047) filed with the SEC on August 10, 1998.
 
(k) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-72583) filed with the SEC on March 8, 1999.
 
(l) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17, 2002.
 
(m) Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001.
 
(n) Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001.
 
(o) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-57338) filed with the SEC on April 19, 2001.
 
(p) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
 
(q) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003.
 
(r) Incorporated by reference to Calpine Corporation’s Registration Statement on Form 8-A/ A (Registration No. 001-12079) filed with the SEC on September 28, 2001.
 
(s) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-87427) filed with the SEC on October 26, 1999.

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(t) Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, filed with the SEC on February 29, 2000.
 
(u) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration Statement No. 333-47068) filed with the SEC on September 29, 2000.
 
(v) Approximately 71 pages of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.
 
(w) Management contract or compensatory plan or arrangement.
 
(x) Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated March 30, 2000, filed with the SEC on April 3, 2000.
 
(y) Incorporated by reference to Calpine Corporation’s Definitive Proxy Statement on Schedule 14A dated April 13, 2000, filed with the SEC on April 13, 2000.
 
(z) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-1/ A (Registration Statement No. 333-07497) filed with the SEC on August 22, 1996.

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SIGNATURES

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

  CALPINE CORPORATION

  By:  /s/ ROBERT D. KELLY
 
  Robert D. Kelly
  Executive Vice President and
  Chief Financial Officer

Date: March 24, 2004

POWER OF ATTORNEY

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

      IN WITNESS WHEREOF, each of the undersigned has executed this Power of Attorney as of the date indicated opposite the name.

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

             
Signature Title Date



 
/s/ PETER CARTWRIGHT

Peter Cartwright
  Chairman, President,
Chief Executive and Director
(Principal Executive Officer)
  March 24, 2004
 
/s/ ANN B. CURTIS

Ann B. Curtis
  Executive Vice President,
Vice Chairman and Director
  March 24, 2004
 
/s/ ROBERT D. KELLY

Robert D. Kelly
  Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
  March 24, 2004
 
/s/ CHARLES B. CLARK, JR.

Charles B. Clark, Jr.
  Senior Vice President and
Corporate Controller
(Principal Accounting Officer)
  March 24, 2004

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Signature Title Date



 
/s/ KENNETH T. DERR

Kenneth T. Derr
  Director   March 24, 2004
 
/s/ JEFFREY E. GARTEN

Jeffrey E. Garten
  Director   March 24, 2004
 


Gerald Greenwald
  Director    
 
/s/ SUSAN C. SCHWAB

Susan C. Schwab
  Director   March 24, 2004
 
/s/ GEORGE J. STATHAKIS

George J. Stathakis
  Director   March 24, 2004
 
/s/ SUSAN WANG

Susan Wang
  Director   March 24, 2004
 
/s/ JOHN O. WILSON

John O. Wilson
  Director   March 24, 2004

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CALPINE CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003
         
Reports of Independent Auditors
    F-2  
Consolidated Balance Sheets December 31, 2003 and 2002
    F-4  
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002, and 2001
    F-6  
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001
    F-8  
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002, and 2001
    F-9  
Notes to Consolidated Financial Statements for the Years Ended December 31, 2003, 2002, and 2001
    F-11  

F-1



Table of Contents

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors

and Stockholders of Calpine Corporation:

      In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Calpine Corporation and its subsidiaries (the “Company”) at December 31, 2003, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The financial statements of the Company as of December 31, 2002 and for the two years then ended were audited by other auditors whose report dated March 10, 2003, except as to paragraph two of note 10 as to which the date is October 21, 2003, and except as to paragraph six and eight of note 10 as to which the date is March 22, 2004, expressed an unqualified opinion on those statements and included emphasis paragraphs relating to the adoption of new accounting standards and the reclassification of certain discontinued operations.

      As discussed in Note 2 to the consolidated financial statements, the Company; changed the manner in which they account for asset retirement costs and stock based compensation as of January 1, 2003, changed the manner in which they account for certain financial instruments with characteristics of both liabilities and equity, effective July 1, 2003, changed the manner in which they report gains and losses on certain derivative instruments not held for trading purposes and account for certain derivative contracts with a price adjustment feature, effective October 1, 2003 and adopted certain provisions of Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities — an interpretation of ARB 51 (revised December 2003),” as of December 31, 2003.

  /s/ PRICEWATERHOUSECOOPERS LLP

Los Angeles, California

March 23, 2004

F-2



Table of Contents

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors

and Stockholders of Calpine Corporation:

      We have audited the consolidated balance sheet of Calpine Corporation and subsidiaries (the “Company”) as of December 31, 2002 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2002 and 2001. Our audits also included the 2002 and 2001 consolidated financial statement schedules listed in the Index at Item 15(a)-2. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.

      We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, based on our audits, such consolidated financial statements present fairly, in all material respects, the consolidated financial position of Calpine Corporation and subsidiaries as of December 31, 2002, and the consolidated results of their operations and their cash flows for the years ended 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2002 and 2001 consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

      As discussed in Note 2 of the Notes to the Consolidated Financial Statements, in 2002, the Company adopted new accounting standards to account for the impairment of long-lived assets, discontinued operations, gains and losses on debt extinguishments and certain derivative contracts. Additionally, in 2002, the Company changed its method of reporting gains and losses associated with energy trading contracts from the gross to the net method and retroactively reclassified the consolidated statement of operations for 2001. In 2001, as discussed in Note 2 of the Notes to the Consolidated Financial Statements, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and certain interpretations issued by the Derivative Implementation Group of the Financial Accounting Standards Board.

      As discussed in Note 10 of the Notes to the Consolidated Financial Statements, in June 2003, the Company approved the divestiture of its specialty data center engineering business; in November 2003, the Company completed the divestiture of certain oil and gas assets; and in December 2003, the Company committed to the divestiture of its fifty percent ownership interest in a power project.

  /s/ DELOITTE & TOUCHE LLP

San Jose, California

March 10, 2003
(October 21, 2003 as to paragraph two of Note 10
and March 22, 2004 as to paragraphs six and eight of Note 10)

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Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2003 and 2002
                     
2003 2002


(In thousands, except share
and per share amounts)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 991,806     $ 579,486  
 
Accounts receivable, net of allowance of $7,614 and $5,955
    988,947       745,312  
 
Margin deposits and other prepaid expense
    385,348       152,413  
 
Inventories
    139,654       105,872  
 
Restricted cash
    383,788       176,716  
 
Current derivative assets
    496,967       330,244  
 
Current assets held for sale
    651       2,669  
 
Other current assets
    89,593       143,318  
     
     
 
   
Total current assets
    3,476,754       2,236,030  
     
     
 
Restricted cash, net of current portion
    575,027       9,203  
Notes receivable, net of current portion
    213,629       195,398  
Project development costs
    139,953       116,795  
Investments in power projects and oil and gas properties
    472,749       421,402  
Deferred financing costs
    400,732       185,026  
Prepaid lease, net of current portion
    414,058       301,603  
Property, plant and equipment, net
    20,081,052       18,730,847  
Goodwill, net
    45,160       29,165  
Other intangible assets, net
    89,924       93,066  
Long-term derivative assets
    673,979       496,028  
Long-term assets held for sale
    112,148       127,363  
Other assets
    608,767       285,066  
     
     
 
   
Total assets
  $ 27,303,932     $ 23,226,992  
     
     
 

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

F-4



Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2003 and 2002 —(Continued)
                     
2003 2002


(In thousands, except share
and per share amounts)
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
               
 
Accounts payable
  $ 938,644     $ 1,237,261  
 
Accrued payroll and related expense
    96,693       47,978  
 
Accrued interest payable
    321,176       189,336  
 
Income taxes payable
    18,026       3,640  
 
Notes payable and borrowings under lines of credit, current portion
    254,292       340,703  
 
Preferred interests, current portion
    11,220        
 
Capital lease obligation, current portion
    4,008       3,454  
 
Construction/project financing, current portion
    65,108       1,307,291  
 
Senior notes, current portion
    14,500        
 
Current derivative liabilities
    456,688       189,356  
 
Current liabilities held for sale
          1,962  
 
Other current liabilities
    319,339       246,150  
     
     
 
   
Total current liabilities
    2,499,694       3,567,131  
     
     
 
Term loan
          949,565  
Notes payable and borrowings under lines of credit, net of current portion
    873,572       8,249  
Notes payable to Calpine Capital Trusts
    1,153,500        
Preferred interests, net of current portion
    232,412        
Capital lease obligation, net of current portion
    193,741       197,653  
Construction/project financing, net of current portion
    4,195,644       3,212,022  
Convertible Senior Notes Due 2006
    660,059       1,200,000  
Convertible Senior Notes Due 2023
    650,000        
Senior notes, net of current portion
    9,369,253       6,894,801  
Deferred income taxes, net
    1,326,044       1,123,729  
Deferred lease incentive
    50,228       53,732  
Deferred revenue
    116,001       154,969  
Long-term derivative liabilities
    692,088       528,400  
Long-term liabilities held for sale
    161       19  
Other liabilities
    259,390       175,636  
     
     
 
   
Total liabilities
    22,271,787       18,065,906  
     
     
 
Commitments and contingencies (see Note 24)
               
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts
          1,123,969  
Minority interests
    410,892       185,203  
     
     
 
Stockholders’ equity:
               
 
Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2003 and one share in 2002
           
 
Common stock, $.001 par value per share; authorized 1,000,000,000 shares; issued and outstanding 415,010,125 shares in 2003 and 380,816,132 shares in 2002
    415       381  
 
Additional paid-in capital
    2,995,735       2,802,503  
 
Retained earnings
    1,568,509       1,286,487  
 
Accumulated other comprehensive income (loss)
    56,594       (237,457 )
     
     
 
   
Total stockholders’ equity
    4,621,253       3,851,914  
     
     
 
   
Total liabilities and stockholders’ equity
  $ 27,303,932     $ 23,226,992  
     
     
 

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

F-5



Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

                                 
For the Years Ended December 31,

2003 2002 2001



(In thousands, except
per share amounts)
Revenue:
                       
 
Electric generation and marketing revenue
                       
   
Electricity and steam revenue
  $ 4,695,744     $ 3,222,202     $ 2,385,324  
   
Sales of purchased power for hedging and optimization
    2,714,187       3,145,991       3,332,412  
     
     
     
 
     
Total electric generation and marketing revenue
    7,409,931       6,368,193       5,717,736  
 
Oil and gas production and marketing revenue
                       
   
Oil and gas sales
    107,662       120,930       286,241  
   
Sales of purchased gas for hedging and optimization
    1,320,902       870,466       526,517  
     
     
     
 
     
Total oil and gas production and marketing revenue
    1,428,564       991,396       812,758  
 
Mark-to-market activities, net
    (26,439 )     21,485       151,738  
 
Other revenue
    107,483       10,787       32,697  
     
     
     
 
     
Total revenue
    8,919,539       7,391,861       6,714,929  
     
     
     
 
Cost of revenue:
                       
 
Electric generation and marketing expense
                       
   
Plant operating expense
    679,031       505,971       324,029  
   
Royalty expense
    24,932       17,615       27,493  
   
Purchased power expense for hedging and optimization
    2,690,069       2,618,445       2,986,578  
     
     
     
 
     
Total electric generation and marketing expense
    3,394,032       3,142,031       3,338,100  
 
Oil and gas operating and marketing expense
                       
   
Oil and gas operating expense
    106,244       97,499       90,492  
   
Purchased gas expense for hedging and optimization
    1,279,568       821,065       492,587  
     
     
     
 
     
Total oil and gas operating and marketing expense
    1,385,812       918,564       583,079  
 
Fuel expense
    2,564,742       1,752,901       1,150,786  
 
Depreciation, depletion and amortization expense
    583,912       453,411       309,373  
 
Operating lease expense
    112,070       111,022       99,519  
 
Other cost of revenue
    42,270       7,279       10,943  
     
     
     
 
     
Total cost of revenue
    8,082,838       6,385,208       5,491,800  
     
     
     
 
       
Gross profit
    836,701       1,006,653       1,223,129  
(Income) from unconsolidated investments in power projects and oil and gas properties
    (76,703 )     (16,552 )     (16,946 )
Equipment cancellation and impairment cost
    64,384       404,737        
Long-term service agreement cancellation charge
    16,355              
Project development expense
    21,804       66,981       35,879  
Sales, general and administrative expense
    265,653       229,011       150,453  
Merger expense
                41,627  
     
     
     
 
 
Income from operations
    545,208       322,476       1,012,116  
Interest expense
    726,103       413,690       196,621  
Distributions on trust preferred securities
    46,610       62,632       62,412  

F-6



Table of Contents

                             
For the Years Ended December 31,

2003 2002 2001



(In thousands, except
per share amounts)
Interest (income)
    (39,716 )     (43,087 )     (72,448 )
Minority interest expense (income)
    27,330       2,716       (1,344 )
(Income) from repurchase of various issuances of debt
    (278,612 )     (118,020 )     (11,919 )
Other (income)
    (46,126 )     (34,200 )     (41,786 )
     
     
     
 
 
Income before provision (benefit) for income taxes
    109,619       38,745       880,580  
Provision (benefit) for income taxes
    (134 )     (14,945 )     297,614  
     
     
     
 
 
Income before discontinued operations and cumulative effect of a change in accounting principle
    109,753       53,690       582,966  
Discontinued operations, net of tax provision of $5,819, $42,884 and $37,899
    (8,674 )     64,928       39,490  
Cumulative effect of a change in accounting principle, net of tax provision of $110,913, $ — , and $699
    180,943             1,036  
     
     
     
 
   
Net income
  $ 282,022     $ 118,618     $ 623,492  
     
     
     
 
Basic earnings per common share:
                       
 
Weighted average shares of common stock outstanding
    390,772       354,822       303,522  
 
Income before discontinued operations and cumulative effect of a change in accounting principle
  $ 0.28     $ 0.15     $ 1.92  
 
Discontinued operations, net of tax
  $ (0.02 )   $ 0.18     $ 0.13  
 
Cumulative effect of a change in accounting principle, net of tax
  $ 0.46     $     $  
     
     
     
 
   
Net income
  $ 0.72     $ 0.33     $ 2.05  
     
     
     
 
Diluted earnings per common share:
                       
 
Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities
    396,219       362,533       317,919  
 
Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle
  $ 0.28     $ 0.15     $ 1.83  
 
Dilutive effect of certain convertible securities(1)
  $     $  —     $ (0.14 )
     
     
     
 
 
Income before discontinued operations and cumulative effect of a change in accounting principle
  $ 0.28     $ 0.15     $ 1.69  
 
Discontinued operations, net of tax
  $ (0.02 )   $ 0.18     $ 0.11  
 
Cumulative effect of a change in accounting principle, net of tax
  $ 0.45     $     $  
     
     
     
 
   
Net income
  $ 0.71     $ 0.33     $ 1.80  
     
     
     
 


(1)  See Note 23 of the Notes to Consolidated Financial Statements for further information.

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

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Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2003, 2002, and 2001
                                                   
Accumulated
Additional Other Total
Common Paid-in Retained Comprehensive Stockholders’ Comprehensive
Stock Capital Earnings Income (Loss) Equity Income






(In thousands, except share amounts)
Balance, January 1, 2001
  $ 300     $ 1,896,987     $ 544,377     $ (25,363 )   $ 2,416,301          
 
Issuance of 6,833,497 shares of common stock, net of issuance costs
    7       72,459                   72,466          
 
Issuance of 151,176 shares of common stock for acquisitions
          7,500                   7,500          
 
Tax benefit from stock options exercised and other
          63,887                   63,887          
Comprehensive income:
                                               
 
Net income
                623,492             623,492     $ 623,492  
 
Other comprehensive loss
                            (215,517 )     (215,517 )     (215,517 )
                                             
 
 
Total comprehensive income
                                $ 407,975  
     
     
     
     
     
     
 
    307       2,040,833       1,167,869       (240,880 )     2,968,129          
     
     
     
     
     
         
 
Issuance of 73,757,381 shares of common stock, net of issuance costs
    74       751,721                     751,795          
 
Tax benefit from stock options exercised and other
          9,949                       9,949          
Comprehensive income:
                                               
 
Net income
                118,618             118,618     $ 118,618  
 
Other comprehensive income
                            3,423       3,423       3,423  
                                             
 
 
Total comprehensive income
                                    $ 122,041  
     
     
     
     
     
     
 
    381       2,802,503       1,286,487       (237,457 )     3,851,914          
     
     
     
     
     
         
 
Issuance of 34,194,063 shares of common stock, net of issuance costs
    34       175,063                   175,097          
 
Tax benefit from stock options exercised and other
          2,097                   2,097          
 
Stock compensation expense
          16,072                   16,072          
Comprehensive income:
                                               
 
Net income
                282,022             282,022     $ 282,022  
 
Other comprehensive income
                            294,051       294,051       294,051  
                                             
 
 
Total comprehensive income
                                $ 576,073  
     
     
     
     
     
     
 
  $ 415     $ 2,995,735     $ 1,568,509     $ 56,594     $ 4,621,253          
     
     
     
     
     
         

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

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CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2003, 2002, and 2001
                                 
2003 2002 2001



(In thousands)
Cash flows from operating activities:
                       
 
Net income
  $ 282,022     $ 118,618     $ 623,492  
   
Adjustments to reconcile net income to net cash provided by operating activities:
                       
   
Depreciation, depletion and amortization(1)
    735,341       542,176       364,056  
   
Equipment cancellation and asset impairment cost
    53,058       404,737        
   
Development cost write off
    3,400       56,427        
   
Deferred income taxes, net
    150,323       23,206       82,410  
   
Gain on sale of assets
    (65,351 )     (97,377 )     (38,258 )
   
Foreign currency translation loss (gain)
    33,346       (986 )     2,930  
   
Cumulative change in accounting principle
    (180,943 )            
   
Gain on retirement of debt
    (278,612 )     (118,020 )     (9,600 )
   
Minority interests
    27,330       2,716       1,345  
   
Change in net derivative liability
    59,490       (340,851 )     (239,716 )
   
Income from unconsolidated investments in power projects and oil and gas properties
    (76,704 )     (16,490 )     (9,433 )
   
Distributions from unconsolidated investments in power projects and oil and gas properties
    141,627       14,117       5,983  
   
Stock compensation expense
    16,072              
   
Change in operating assets and liabilities, net of effects of acquisitions:
                       
     
Accounts receivable
    (221,243 )     229,187       (230,400 )
     
Other current assets
    (160,672 )     405,515       (527,296 )
     
Other assets
    (143,654 )     (305,908 )     (120,310 )
     
Accounts payable and accrued expense
    (111,901 )     (48,804 )     449,369  
     
Other liabilities
    27,630       200,203       68,997  
     
     
     
 
       
Net cash provided by operating activities
    290,559       1,068,466       423,569  
     
     
     
 
Cash flows from investing activities:
                       
 
Purchases of property, plant and equipment
    (1,886,013 )     (4,036,254 )     (5,832,874 )
 
Disposals of property, plant and equipment
    206,804       400,349       49,120  
 
Acquisitions, net of cash acquired
    (6,818 )           (1,608,840 )
 
Proceeds from sale leasebacks
                517,081  
 
Advances to joint ventures
    (54,024 )     (68,088 )     (177,917 )
 
Project development costs
    (35,778 )     (105,182 )     (147,520 )
 
Cash flows from derivatives not designated as hedges
    42,342       26,091       29,145  
 
(Increase) decrease in restricted cash
    (766,841 )     (73,848 )     (45,642 )
 
(Increase) decrease in notes receivable
    (21,135 )     8,926       (40,273 )
 
Other
    6,098       10,179       17,065  
     
     
     
 
       
Net cash used in investing activities
    (2,515,365 )     (3,837,827 )     (7,240,655 )
     
     
     
 

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Table of Contents

                             
2003 2002 2001



(In thousands)
Cash flows from financing activities:
                       
 
Proceeds from issuance of Zero-Coupon Convertible Debentures Due 2021
                1,000,000  
 
Repurchase of Zero-Coupon Convertible Debentures Due 2021
          (869,736 )     (110,100 )
 
Borrowings from notes payable and lines of credit
    1,672,871       1,348,798       148,863  
 
Repayments of notes payable and lines of credit
    (1,769,072 )     (126,404 )     (962,873 )
 
Borrowings from project financing
    1,548,601       725,111       3,869,391  
 
Repayments of project financing
    (1,638,519 )     (286,293 )     (1,712,292 )
 
Proceeds from issuance of Convertible Senior Notes
    650,000       100,000       1,100,000  
 
Repurchases of Convertible Senior Notes Due 2006
    (455,447 )            
 
Repurchases of senior notes
    (1,139,812 )           (106,300 )
 
Proceeds from issuance of senior notes
    3,892,040             4,596,039  
 
Proceeds from issuance of common stock
    15,951       751,795       72,465  
 
Proceeds from income trust offerings
    159,727       169,677        
 
Financing costs
    (323,167 )     (42,783 )     (144,746 )
 
Other
    10,813       (12,769 )     (270 )
     
     
     
 
   
Net cash provided by financing activities
    2,623,986       1,757,396       7,750,177  
     
     
     
 
Effect of exchange rate changes on cash and cash equivalents
    13,140       (2,693 )     (3,669 )
Net increase (decrease) in cash and cash equivalents
    412,320       (1,014,658 )     929,422  
Cash and cash equivalents, beginning of period
    579,486       1,594,144       664,722  
     
     
     
 
Cash and cash equivalents, end of period
  $ 991,806     $ 579,486     $ 1,594,144  
     
     
     
 
Cash paid during the period for:
                       
 
Interest, net of amounts capitalized
  $ 462,714     $ 325,334     $ 42,883  
 
Income taxes
  $ 18,415     $ 15,451     $ 271,973  


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

      Schedule of non cash investing and financing activities:

  —  2003 issuance of 30 million shares of common stock in exchange for $182.5 million of debt, convertible debt and preferred securities
 
  —  2002 non-cash consideration of $88.4 million in tendered Company debt received upon the sale of its British Columbia oil and gas properties
 
  —  2001 equity investment in a power project for $17.5 million note receivable

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

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Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2003, 2002, and 2001
 
1. Organization and Operations of the Company

      Calpine Corporation (“Calpine” or the Company), a Delaware corporation, and subsidiaries, (collectively, also referred to as the “Company”) are engaged in the generation of electricity in the United States of America, Canada and the United Kingdom. The Company is involved in the development, construction, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. The Company has ownership interests in, and operates, gas-fired power generation and cogeneration facilities, gas fields, gathering systems and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States of America. In Canada, the Company owns oil and gas operations and has ownership interests in, and operates, power facilities. In the United Kingdom, the Company owns and operates a gas-fired power cogeneration facility. Each of the generation facilities produces and markets electricity for sale to utilities and other third party purchasers. Thermal energy produced by the gas-fired power cogeneration facilities is primarily sold to industrial users. Gas produced, and not physically delivered to the Company’s generating plants, is sold to third parties.

 
2. Summary of Significant Accounting Policies

      Principles of Consolidation — The accompanying consolidated financial statements as of December 31, 2002, and for the three years ended December 31, 2003, include accounts of the Company and its wholly owned and majority-owned subsidiaries. The consolidated financial statements as of December 31, 2003, include the accounts of the Company and its majority-owned subsidiaries that are not considered Variable Interest Entities (“VIE”) and all special purpose VIEs for which the Company is the Primary Beneficiary. Certain less-than-majority-owned subsidiaries are accounted for using the equity method. For equity method investments, the Company’s share of income is calculated according to the Company’s equity ownership or according to the terms of the appropriate partnership agreement (see Note 7). All intercompany accounts and transactions are eliminated in consolidation.

      Reclassifications — Certain prior years’ amounts in the Consolidated Financial Statements have been reclassified to conform to the 2003 presentation.

      Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to useful lives and carrying values of assets (including the carrying value of projects in development, construction retirement and operation), provision for income taxes, fair value calculations of derivative instruments and associated reserves, capitalization of interest, primary beneficiary determination for our investments in variable interest entities, the outcome of pending litigation and estimates of oil and gas reserves used to calculate depletion, depreciation and impairment of natural gas and petroleum property and equipment.

      Operational data (including, but not limited to, megawatts (“MW”), megawatt hours (“MWh”), billions cubic feet equivalent (“Bcfe”) and thousand barrels (“MBbl”), throughout this Form-10K is unaudited.

      Foreign Currency Translation — Assets and liabilities of non-U.S. subsidiaries that operate in a local currency environment and gains and losses on foreign currency transactions treated as economic hedges of a net investment in a foreign entity and intercompany foreign currency transactions which are of a long-term investment nature are translated to U.S. dollars at exchange rates in effect at the balance sheet date with the

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Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

resulting translation adjustments recorded in other comprehensive income. Income and expense accounts are translated at average exchange rates during the year.

      Fair Value of Financial Instruments — The carrying value of accounts receivable, marketable securities, accounts and other payables approximate their respective fair values due to their short maturities. See Note 16 for disclosures regarding the fair value of the senior notes.

      Cash and Cash Equivalents — The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The carrying amount of these instruments approximates fair value because of their short maturity.

      The Company has certain project debt agreements which establish working capital accounts which limit the use of certain cash balances to the operations of the respective plants. At December 31, 2003 and 2002, $342.5 million and $189.0 million, respectively, of the cash and cash equivalents balance was subject to such project debt agreements.

      Accounts Receivable and Accounts Payable — Accounts receivable and payable represent amounts due from customers and owed to vendors. These balances also include settled but unpaid amounts relating to hedging, balancing, optimization and trading activities of Calpine Energy Services, L.P. (“CES”). Some of these receivables and payables with individual counterparties are subject to master netting agreements whereby the Company legally has a right of offset and the Company settles the balances net. However, for balance sheet presentation purposes and to be consistent with the way the Company presents the majority of amounts related to hedging, balancing and optimization activities in its statements of operations under Staff Accounting Bulletin (“SAB”) No. 101 “Revenue Recognition in Financial Statements,” as amended by SAB No. 104 “Revenue Recognition” (collectively “SAB No. 101”), and EITF Issue No. 99-19 “Reporting Revenue Gross as a Principal Versus Net as an Agent,” the Company presents its receivables and payables on a gross basis.

      Inventories — The Company’s inventories primarily include spare parts, work-in-process and stored gas. Operating supplies are valued at the lower of cost or market. Cost for large replacement parts estimated to be used within one year is determined using the specific identification method. For the remaining supplies and spare parts, cost is generally determined using the weighted average cost method. Stored gas is valued at the lower of weighted average cost or market. Work-in-process represents the value of manufactured goods during the manufacturing process. The inventory balance at December 31, 2003, was $139.7 million. This balance is comprised of $90.3 million of spare parts, $43.5 million of stored gas and $5.9 million of work-in-process. The inventory balance at December 31, 2002, was $105.9 million. This balance is comprised of $72.1 million of spare parts, $31.4 million of stored gas and $2.4 million of work-in-process.

      Margin Deposits — As of December 31, 2003 and 2002, as credit support for the gas procurement as well as risk management activities it conducts on the Company’s behalf, CES had deposited net amounts of $188.0 million and $25.2 million, respectively, in cash as margin deposits.

      Collateral Debt Securities — The Company classifies all short-term and long-term debt securities as held-to-maturity because the Company has the intent and ability to hold the securities to maturity. The securities act as collateral to support the King City operating lease and mature serially in amounts equal to a portion of the semi-annual lease payments. Held-to-maturity securities are stated at amortized cost, adjusted for amortization of premiums and accretion discounts to maturity.

      Property, Plant and Equipment, Net — See Note 4 for a discussion of the Company’s accounting policies for its property, plant and equipment.

      Project Development Costs — The Company capitalizes project development costs once it is determined that it is probable that such costs will be realized through the ultimate construction of a power plant. These costs include professional services, salaries, permits and other costs directly related to the development of a

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Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

new project. Upon commencement of construction, these costs are transferred to construction in progress, a component of property, plant and equipment. Upon the start-up of plant operations, these construction costs are reclassified as buildings, machinery and equipment, also a component of property, plant and equipment, and are amortized as a component of the total cost of the plant over its estimated useful life. Capitalized project costs are charged to expense if the Company determines that the project is no longer probable or to the extent it is impaired. Outside services and other third party costs are capitalized for acquisition projects.

      Investments in Power Projects and Oil and Gas Properties — The Company uses the equity method to recognize its pro rata share of the net income or loss of an unconsolidated investment until such time, if applicable, that the Company’s investment is reduced to zero, at which time losses are only recognized if there is a legal requirement to fund such losses. Once an investment is written down to zero equity income is generally recognized only upon receipt of cash distributions from the investee.

      Restricted Cash — The Company is required to maintain cash balances that are restricted by provisions of its debt agreements, lease agreements and regulatory agencies. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent service, major maintenance and debt repurchases. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is invested in accounts earning market rates; therefore the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents in the consolidated statement of cash flows. Of the Company’s restricted cash, $157.6 million, $4.6 million and $60.7 million are the assets of Power Contract Financing, L.L.C. (“PCF”), Calpine Northbrook Energy Marketing, LLC (“CNEM”), and Gilroy Energy Center, LLC (“GEC”), respectively, each an entity with its existence separate from the Company and other subsidiaries of the Company.

      Notes Receivable — See Note 8 for a discussion of the Company’s accounting policies for its notes receivable.

      Deferred Financing Costs — The deferred financing costs related to the Company’s Senior Notes and the Convertible Senior Notes are amortized over the life of the related debt, ranging from 4 to 20 years, using the effective interest rate method (see Note 16). The deferred financing costs associated with the Calpine Construction Finance Company II, LLC (“CCFC II”) facility are amortized over the 4-year facility life using the effective interest rate method (see Note 14). The deferred financing costs related to the Zero-Coupon Debentures Due 2021 were amortized over 1 year due to the put option that was exercised by the holders in 2002. Costs incurred in connection with obtaining other financing are deferred and amortized over the life of the related debt.

      Long-Lived Assets — In accordance with Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets and for Long-Lived Assets to be Disposed of,” the Company evaluates the impairment of long-lived assets, including construction and development projects, based on the projection of undiscounted pre-interest expense and pre-tax expense cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. The significant assumptions that the Company uses in its undiscounted future cash flow estimates include the future supply and demand relationships for electricity and natural gas, and the expected pricing for those commodities and the resultant spark spreads in the various regions where the Company generates. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values (see Note 4). Certain of the Company’s generating assets are located in regions with depressed demands and market spark spreads. The Company’s forecasts assume that spark spreads will increase in future years in these regions as the supply and demand relationships improve.

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Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Concentrations of Credit Risk — Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of cash, accounts receivable, notes receivable, and commodity contracts. The Company’s cash accounts are generally held in FDIC insured banks. The Company’s accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the United States (see Notes 8 and 21). The Company generally does not require collateral for accounts receivable from end-user customers, but evaluates the net accounts receivable, accounts payable, and fair value of commodity contracts with trading companies and may require security deposits or letters of credit to be posted if exposure reaches a certain level.

      Deferred Revenue — The Company’s deferred revenue consists primarily of deferred gains for the sale/leaseback transactions as well as deferred revenue for long-term power supply contracts.

      Trust Preferred Securities — Prior to the adoption of FASB Interpretation No. 46 (Revised 2003) “Consolidation of Variable Interest Entities — An Interpretation of ARB No. 51” (“FIN 46-R”) on October 1, 2003, the Company’s trust preferred securities were accounted for as a minority interest in the balance sheet and reflected as “Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts.” The distributions were reflected in the statements of operations as “distributions on trust preferred securities” through the third quarter of 2003. Financing costs related to these issuances are netted with the principal amounts and were accreted as minority interest expense over the securities’ 30-year maturity using the straight-line method which approximated the effective interest rate method. Upon the adoption of FIN 46-R, the Company deconsolidated the Calpine Capital Trusts, which had issued the Trust Preferred Securities. Consequently, the Trust Preferred Securities are no longer on the Company’s Consolidated Balance Sheet and were replaced with the debentures issued by the Company to the Calpine Capital Trusts. The interest payments on the debentures are now reflected in the statements of operations as “interest expense.” (See Note 11).

      Revenue Recognition — The Company is primarily an electric generation company, operating a portfolio of mostly wholly owned plants but also some plants in which its ownership interest is 50% or less or the Company is not the Primary Beneficiary under FIN 46-R and which are accounted for under the equity method. In conjunction with its electric generation business, the Company also produces, as a by-product, thermal energy for sale to customers, principally steam hosts at the Company’s cogeneration sites. In addition, the Company acquires and produces natural gas for its own consumption and sells the balance and oil produced to third parties. Where applicable, revenues are recognized under EITF No. 91-6, “Revenue Recognition of Long Term Power Sales Contracts,” ratably over the terms of the related contracts. To protect and enhance the profit potential of its electric generation plants, the Company, through its subsidiary, CES, enters into electric and gas hedging, balancing, and optimization transactions, subject to market conditions, and CES has also, from time to time, entered into contracts considered energy trading contracts under EITF Issue No. 02-3. CES executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, CES generally acts as a principal, takes title to the commodities, and assumes the risks and rewards of ownership. Therefore, when CES does not hold these contracts for trading purposes and, in accordance with SAB No. 101, and EITF Issue No. 99-19, the Company records settlement of the majority of its non-trading physical forward contracts on a gross basis. On October 1, 2003, the Company adopted EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes’ As Defined in EITF Issue No. 02-3: “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 03-11”) and, accordingly, has begun netting certain types of hedging, balancing and optimization transactions. See discussion of the impacts of adopting EITF Issue No. 03-11 under the New Accounting Pronouncements Section of this Note. The Company settles its financial swap and option transactions net and does not take title to the underlying commodity. Accordingly,

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Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the Company records gains and losses from settlement of financial swaps and options net within net income. Managed risks typically include commodity price risk associated with fuel purchases and power sales.

      The Company, through its wholly owned subsidiary, Power Systems Mfg., LLC (“PSM”), designs and manufactures certain spare parts for gas turbines. The Company in the past has also generated revenue by occasionally loaning funds to power projects, by providing operation and maintenance (“O&M”) services to third parties and to certain unconsolidated power projects. The Company also sells engineering and construction services to third parties for power projects. Further details of the Company’s revenue recognition policy for each type of revenue transaction are provided below:

      Electric Generation and Marketing Revenue — This includes electricity and steam sales and sales of purchased power for hedging, balancing and optimization. Subject to market and other conditions, the Company manages the revenue stream for its portfolio of electric generating facilities. The Company markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties, through hedging, balancing and optimization transactions. CES performs a market-based allocation of total electric generation and marketing revenue to electricity and steam sales (based on electricity delivered by the Company’s electric generating facilities) and the balance is allocated to sales of purchased power.

      Oil and Gas Production and Marketing Revenue — This includes sales to third parties of oil, gas and related products that are produced by the Company’s Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and, subject to market and other conditions, sales of purchased gas arising from hedging, balancing and optimization transactions. Oil and gas sales for produced products are recognized pursuant to the sales method, net of royalties. If the Company has recorded gas sales on a particular well or field in excess of its share of remaining estimated reserves, then the excessive gas sale imbalance is recognized as a liability. If the Company is under-produced on a particular well or field, and it is determined that an over-produced partner’s share of remaining reserves is insufficient to settle the gas imbalance, the Company will recognize a receivable, to the extent collectible, from the over-produced partner.

      Mark-to-Market Activity, Net — This includes realized settlements of and unrealized mark-to-market gains and losses on both power and gas derivative instruments undesignated as cash flow hedges, including those held for trading purposes. Gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses. Trading activity is presented net in accordance with EITF Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”). See New Accounting Pronouncements discussed in this Note.

      Other Revenue — This includes O&M contract revenue, PSM and TTS revenue from sales to third parties, engineering and construction revenue and miscellaneous revenue, including amounts associated with the Company’s Enron Settlement (see Note 21).

      Plant Operating Expense — This primarily includes employee expenses, repairs and maintenance, insurance, transmission cost and property taxes.

      Purchased Power and Purchased Gas Expense — The cost of power purchased from third parties for hedging, balancing and optimization activities is recorded as purchased power expense, a component of electric generation and marketing expense. The Company records the cost of gas purchased from third parties for the purposes of consumption in its power plants as fuel expense, while gas purchased from third parties for hedging, balancing, and optimization activities is recorded as purchased gas expense, a component of oil and gas production and marketing expense. Certain hedging, balance and optimization activity is presented net in accordance with EITF Issue No. 03-11. See New Accounting Pronouncements discussed in this Note.

      Provision (Benefit) for Income Taxes — Deferred income taxes are based on the differences between the financial reporting and tax bases of assets and liabilities. The deferred income tax provision represents the

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changes during the reporting period in the deferred tax assets and deferred tax liabilities, net of the effect of acquisitions and dispositions. Deferred tax assets include tax losses and tax credit carryforwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Additionally, with respect to income taxes, the Company assumes the deductibility of certain costs in its income tax filings and estimates the future recovery of deferred tax assets.

      Insurance Program — CPN Insurance Corporation, a wholly owned captive insurance subsidiary, charges the Company competitive premium rates to insure casualty lines (workers’ compensation, automobile liability, and general liability) as well as all risk property insurance including business interruption. Accruals for claims under the captive insurance program pertaining to property, including business interruption claims, are recorded on a claims-incurred basis. Accruals for casualty claims under the captive insurance program are recorded on a monthly basis, and are based upon the estimate of the total cost of claims incurred during the policy period. The captive insures limits up to $25 million per occurrence for property claims, including business interruption, and up to $500,000 per occurrence for casualty claims.

      Derivative Instruments — SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

      The Company is required by GAAP to account for certain derivative contracts at fair value. Accounting for derivatives at fair value requires the Company to make estimates about future prices during periods for which price quotes are not available from sources external to the Company. As a result, the Company is required to rely on internally developed price estimates when external price quotes are unavailable. The Company derives its future price estimates, during periods where external price quotes are unavailable, based on an extrapolation of prices from periods where external price quotes are available. The Company performs this extrapolation using liquid and observable market prices and extending those prices to an internally generated long-term price forecast based on a generalized equilibrium model.

      SFAS No. 133 sets forth the accounting requirements for cash flow and fair value hedges. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS No. 133 provides that the changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment be recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. Additionally, if the underlying transaction being hedged is disposed of or otherwise terminated, the gain or loss associated with the hedge instrument is recognized currently. If the hedging instrument is terminated prior to the occurrence of the hedged transaction, the gain or loss associated with the hedge instrument remains deferred.

      Where the Company’s derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation (“FIN”) 39 “Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10 and SFAS No. 105)” are met, the Company presents its derivative assets and liabilities on a net basis in its balance sheet. The Company has chosen this method of presentation because it is

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consistent with the way related mark-to-market gains and losses on derivatives are recorded in its Consolidated Statements of Operations and within Other Comprehensive Income (“OCI”).

 
New Accounting Pronouncements

      In June 2001 FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 applies to fiscal years beginning after June 15, 2002 and amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” This standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the assets and requires that a liability for an asset retirement obligation be recognized when incurred, recorded at fair value and classified as a liability in the balance sheet. When the liability is initially recorded, the entity will capitalize the cost and increase the carrying value of the related long-lived asset. Asset retirement obligations represent future liabilities, and, as a result, accretion expense will be accrued on this liability until the obligation is satisfied. At the same time, the capitalized cost will be depreciated over the estimated useful life of the related asset. At the settlement date, the entity will settle the obligation for its recorded amount or recognize a gain or loss upon settlement.

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

      Based on current information and assumptions, the Company recorded, as of January 1, 2003, an additional long-term liability of $25.9 million, an additional asset within property, plant and equipment, net of accumulated depreciation, of $26.9 million, and a pre-tax gain to income due to the cumulative effect of a change in accounting principle of $1.0 million. These entries include the effects of the reversal of site dismantlement and restoration costs previously expensed in accordance with SFAS No. 19.

      The table below details the change during 2003 in the Company’s asset retirement obligation (in thousands):

         
Asset retirement obligation at January 1, 2003
  $ 47,274  
Liabilities incurred in 2003
    4,368  
Liabilities settled in 2003
    (2,012 )
Accretion expense
    5,688  
Revisions in the estimated cash flows
    1,799  
Other (primarily foreign currency translation)
    (3,782 )
     
 
Asset retirement obligation at December 31, 2003
  $ 53,335  
     
 

      If SFAS No. 143 had been applied for the year ended December 31, 2001, the asset retirement obligation at December 31, 2001, would have been $31.2 million.

      In November 2002 FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”).” This Interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. In addition, the Interpretation clarifies the requirements

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related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations that the guarantor has undertaken in issuing the guarantee. The Company adopted the disclosure requirements of FIN 45 for the fiscal year ended December 31, 2002, and the recognition provisions on January 1, 2003. Adoption of this Interpretation did not have a material impact on the Company’s Consolidated Financial Statements.

      On January 1, 2003, the Company prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for companies that voluntarily change their accounting for stock-based compensation from the less preferred intrinsic value based method to the more preferred fair value based method. Prior to its amendment, SFAS No. 123 required that companies enacting a voluntary change in accounting principle from the intrinsic value methodology provided by Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” could only do so on a prospective basis; no adoption or transition provisions were established to allow for a restatement of prior period financial statements. SFAS No. 148 provides two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company has elected to adopt the provisions of SFAS No. 123 on a prospective basis; consequently, the Company is required to provide a pro-forma disclosure of net income and earnings per share as if SFAS No. 123 accounting had been applied to all prior periods presented within its financial statements. As shown below, the adoption of SFAS No. 123 has had a material impact on the Company’s financial statements. The table below reflects the pro forma impact of stock-based compensation on the Company’s net income and earnings per share for the years ended December 31, 2003, 2002 and 2001, had the Company applied the accounting provisions of SFAS No. 123 to its prior years’ financial statements (in thousands, except per share amounts):

                             
2003 2002 2001



Net income
                       
   
As reported
  $ 282,022     $ 118,618     $ 623,492  
   
Pro Forma
    270,418       83,025       588,442  
Earnings per share data:
                       
 
Basic earnings per share
                       
   
As reported
  $ 0.72     $ 0.33     $ 2.05  
   
Pro Forma
    0.69       0.23       1.94  
 
Diluted earnings per share
                       
   
As reported
  $ 0.71     $ 0.33     $ 1.80  
   
Pro Forma
    0.68       0.23       1.71  
Stock-based compensation cost included in net income, as reported
  $ 9,724     $     $  
Stock-based compensation cost included in net income, pro forma
    21,328       35,593       35,050  

      The range of fair values of the Company’s stock options granted in 2003, 2002, and 2001 were as follows, based on varying historical stock option exercise patterns by different levels of Calpine employees: $1.50-$4.38 in 2003, $3.73-$6.62 in 2002, and $18.29-$30.73 in 2001 on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: expected dividend yields of 0%, expected volatility of 70%-113% for 2003, 70%-83% for 2002, and 55%-59% for 2001, risk-free interest rates of 1.39%-

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4.04% for 2003, 2.39%-3.83% for 2002, and 3.99%-5.07% for 2001, and expected option terms of 1.5-9.5 years for 2003 and 4-9 years for 2002 and 2001.

      In January 2003 FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (“FIN 46”). FIN 46 requires the consolidation of an entity by an enterprise that absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interest in the entity. Historically, entities have generally been consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The objectives of FIN 46 are to provide guidance on the identification of Variable Interest Entities (“VIEs”) for which control is achieved through means other than ownership of a majority of the voting interest of the entity, and how to determine which business enterprise, as the Primary Beneficiary, should consolidate the Variable Interest Entity (“VIE”). This new model for consolidation applies to an entity in which either (1) sufficient equity is lacking to absorb expected losses without additional subordinated financial support or (2) its at-risk equity holders as a group are not able to make decisions that have a significant impact on the success or failure of the entity’s ongoing activities.

      In December 2003 FASB modified FIN 46 with FIN 46-R to make certain technical corrections and to address certain implementation issues. FIN 46, as originally issued, was effective immediately for VIEs created or acquired after January 31, 2003. FIN 46-R delayed the effective date of the interpretation to no later than March 31, 2004, (for calendar-year enterprises), except for Special Purpose Entities (“SPEs”) for which the effective date is December 31, 2003. The Company is still evaluating the impact FIN 46-R may have on its equity method joint ventures, its wholly owned subsidiaries that are subject to long-term power purchase agreements and tolling arrangements, operating leases, entities issuing mandatory redeemable non-controlling interests and other equity investments. However, one possible consequence of adopting FIN 46-R for non-SPEs is that certain equity investments might have to be consolidated and certain wholly owned subsidiaries might have to be de-consolidated.

      The ultimate determination of whether equity investments will be consolidated by the Company will be based on whether these equity investments are in entities that are VIEs and who is the Primary Beneficiary of the VIE. Since the joint venture investments have long-term sales agreements, it is possible these agreements will cause the joint ventures to be considered VIEs. The determination of whether the Company, the other equity owner or the purchaser of the power will consolidate the VIE will be based on which variable interest holder absorbs the majority of the risk of the VIE and is therefore the Primary Beneficiary.

      A similar analysis must be performed for certain 100% Company-owned subsidiaries with long term power sales or tolling agreements. If the Company-owned subsidiary is deemed a VIE by virtue of its long-term power sales or tolling agreement and if the power purchaser is the Primary Beneficiary because it absorbs the majority of the Company-owned subsidiary’s risk, the Company may be required to deconsolidate its subsidiary and account for it under the equity method of accounting. See Note 7 for more information regarding equity investments that may have to be consolidated.

      Acadia Powers Partners, LLC (“Acadia”) is the owner of a 1,160-megawatt electric wholesale generation facility located in Louisiana and is a joint venture between the Company and Cleco Corporation. The joint venture was formed in March 2000, but due to a change in the partnership agreement in May 2003, the Company was required to reconsider its investment in the entity under FIN 46, as originally issued. The Company determined that Acadia was a VIE and that it held a significant variable interest in the entity. However, the Company was not the Primary Beneficiary and therefore not required to consolidate the entity’s assets and liabilities. The total of both partners’ equity in Acadia was approximately $489.2 million as of December 31, 2003. The Company’s maximum potential exposure to loss at December 31, 2003, is limited to the book value of its investment of approximately $221.0 million. The Company continues to account for this investment under the equity method. Under the transition rules of FIN 46-R, the Company is required to

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adopt the provisions of FIN 46-R for Acadia as of March 31, 2003. The Company anticipates that it will still not be the Primary Beneficiary upon the adoption of FIN 46-R.

      On May 15, 2003, the Company’s wholly owned subsidiary, Calpine Northbrook Energy Marketing, LLC (“CNEM”), completed the $82.8 million monetization of an existing power sales agreement with the Bonneville Power Administration (“BPA”). CNEM borrowed $82.8 million secured by the spread between the BPA contract and the fixed power purchases. CNEM was established as a bankruptcy-remote entity and the $82.8 million loan is recourse only to CNEM’s assets and is not guaranteed by the Company. CNEM was determined to be a VIE in which the Company was the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into the Company’s accounts as of June 30, 2003. See Note 11 for information regarding this monetization.

      On June 13, 2003, Power Contract Financing, L.L.C. (“PCF”), a wholly owned stand-alone subsidiary of CES, completed an offering of two tranches of Senior Secured Notes Due 2006 and 2010 (collectively called the “PCF Notes”), totaling $802.2 million. To facilitate the transaction, the Company formed PCF as a wholly owned, bankruptcy remote entity with assets and liabilities consisting of the transferred power purchase and sales contracts and the PCF Notes. PCF was determined to be a VIE in which the Company was the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into the Company’s accounts as of June 30, 2003. See Note 11 for information regarding this offering.

      Upon adoption of FIN 46-R for the Company’s investments in SPEs, the Company deconsolidated Calpine Capital Trusts I, II and III (Trusts) as explained further in Note 11. The Company’s remaining portfolio of investments in joint ventures, wholly owned subsidiaries, operating leases, significant power purchase agreements and other equity investments did not involve SPEs.

      In April 2003 FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying to conform it to language used in FIN 45, and amends certain other existing pronouncements. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and should be applied prospectively, with the exception of certain SFAS No. 133 implementation issues that were effective for all fiscal quarters prior to June 15, 2003. Any such implementation issues should continue to be applied in accordance with their respective effective dates. The adoption of SFAS No. 149 did not have a material impact on the Company’s financial statements.

      In May 2003 FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 applies specifically to a number of financial instruments that companies have historically presented within their financial statements either as equity or between the liabilities section and the equity section, rather than as liabilities. SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003.

      The Company adopted SFAS No. 150 on July 1, 2003. As a result, approximately $82 million of mandatorily redeemable non-controlling interest in its King City facility, which had previously been included within the balance sheet caption “Minority interests,” was reclassified to “Notes payable.” Preferential distributions related to this mandatorily redeemable non-controlling interest are to be made annually beginning November 2003 through November 2019 and total approximately $169 million over the 17-year period. The preferred interest holders’ recourse is limited to the net assets of the entity and the distribution terms defined in the agreement. The Company has not guaranteed the payment of these preferential

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distributions. The distributions and accretion of issuance costs related to this preferred interest, which was previously reported as a component of “Minority interest expense” in the Consolidated Condensed Statements of Operations, is now accounted for as interest expense. Distributions and related accretion associated with this preferred interest was $5.3 million for the six months ended December 31, 2003. SFAS No. 150 does not permit reclassification of prior period amounts to conform to the current period presentation.

      During the third quarter of 2003, the Company completed the sales of preferred equity interests for Auburndale Holdings, LLC and Gilroy Energy Center (“GEC”) Holdings, LLC. These interests, in addition to the King City interest, are classified as debt on the Company’s Condensed Consolidated Balance Sheet as of December 31, 2003. Although the Company cannot readily determine the potential cost to repurchase the interests in Auburndale Holdings, LLC and GEC Holdings, LLC, the carrying value of its aggregate partners’ interests is approximately $161.6 million.

      In November 2003 FASB indefinitely deferred certain provisions of SFAS No. 150 as they apply to mandatorily redeemable non-controlling (minority) interests associated with finite-lived subsidiaries. Upon FASB’s finalization of this issue, the Company may be required to reclassify the minority interest relating to the Company’s investment in Calpine Power Limited Partnership (“CLP”) to debt. As of December 31, 2003, the minority interest related to the CLP was approximately $338 million. The Company owns approximately 30% of CLP, which is finite-lived, terminating on December 31, 2050. See Note 10 for a discussion of the Company’s investment in CLP. CLP is consolidated under SFAS No. 66, “Accounting for Sales of Real Estate” due to the Company’s significant continuing involvement in the assets transferred to CLP.

      The adoption of SFAS No. 150 and related balance sheet reclassifications did not have an effect on net income or total stockholders’ equity but have impacted the Company’s debt-to-equity and debt-to-capitalization ratios.

      In June 2003 FASB issued Derivatives Implementation Group (“DIG”) Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” DIG Issue No. C20 superseded DIG Issue No. C11 “Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception,” and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 is effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for the Company) with early application permitted. In conjunction with initially applying the implementation guidance, DIG Issue No. C20 requires the recognition of a special transition adjustment for certain contracts containing a price adjustment feature based on a broad market index for which the normal purchases and normal sales scope exception had been previously elected. In those circumstances, the derivative contract should be recognized at fair value as of the date of the initial application with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle. It should then be applied prospectively for all existing contracts as of the effective date and for all future transactions.

      Two of the Company’s power sales contracts, which meet the definition of a derivative and for which it previously elected the normal purchases and normal sales scope exception, use a CPI or similar index to escalate the Operations and Maintenance (“O&M”) charges. Adoption of DIG Issue No. C20 required the Company to recognize a special transition accounting adjustment for the estimated future economic benefits of these contracts. The Company based the transition adjustment on the nature and extent of the key price adjustment features in the contracts and estimated future market conditions on the date of adoption, such as the forward price of power and natural gas and the expected rate of inflation. The Company will realize the actual future economic benefits of these contracts over the remaining lives of these contracts which extend through 2013 and 2023 as actual power deliveries occur, although DIG Issue No. C20 required the Company

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to account for the estimated future economic benefits currently. The Company will amortize the corresponding asset recorded upon adoption of DIG Issue No. C20 through a charge to earnings in future periods. Accordingly on October 1, 2003, the date the Company adopted DIG Issue No. C20, the Company recorded other current assets and other assets of approximately $33.5 million and $259.9 million, respectively, and a cumulative effect of a change in accounting principle of approximately $181.9 million, net of $111.5 million of tax. For all periods subsequent to October 1, 2003, the Company will account for the contracts as normal purchases and sales under the provisions of DIG Issue No. C20.

      In May 2003 the EITF reached consensus in EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF Issue No. 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. Prior to adopting EITF Issue No. 01-08, the Company had accounted for certain contractual arrangements as leases under existing industry practices, and the adoption of EITF Issue No. 01-08 did not materially change accounting for previous arrangements that had been accounted for as leases prior to the adoption of EITF Issue No. 01-08. Currently the income to the Company under these arrangements is immaterial; however, the Company may, in the future, structure additional power purchase agreements as leases. For income statement presentation purposes, income from arrangements accounted for as leases is classified within electricity and steam revenue in the Company’s consolidated statements of operations.

      During 2003, the Emerging Issues Task Force (“the Task Force”) discussed EITF Issue No. 03-11. In EITF Issue No. 02-3 the Task Force reached a consensus that companies should present all gains and losses on derivative instruments held for trading purposes net in the income statement, whether or not settled physically. EITF Issue No. 03-11 addresses income statement classification of derivative instruments held for other than trading purposes. At the July 31, 2003, EITF meeting, the Task Force reached a consensus that determining whether realized gains and losses on derivative contracts not held for trading purposes’ should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. The Task Force ratified this consensus at its August 13, 2003 meeting, and it is effective beginning October 1, 2003. The Task Force did not prescribe special effective date or transition guidance for this Issue. The Company determined that under the provisions of EITF Issue No. 03-11, transactions which are not physically settled should be reported net for purposes of the Consolidated Statement of Operations. Accordingly, transactions with either of the following characteristics are presented net in the Company’s financial statements: (1) transactions executed in a back-to-back buy and sale pair, primarily because of market protocols; and (2) physical power purchase and sale transactions where the Company’s power schedulers net the physical flow of the power purchase against the physical flow of the power sale as a matter of scheduling convenience to eliminate the need to schedule actual power delivery or “book out” the physical power flows. These book out transactions may occur with the same counterparty or between different counterparties where the Company has equal but offsetting physical purchase and delivery commitments.

      Based on guidance in EITF Topic No. D-1 “Implications and Implementation of an EITF Consensus” and because EITF Issue No. 03-11 is silent with respect to transition provisions, the Company has adopted EITF No. 03-11 on a prospective basis effective October 1, 2003. While adoption of EITF No. 03-11 had no effect on the Company’s gross profit or net income, it reduced the Company’s 2003 sales of purchased power for hedging and optimization and purchased power expense for hedging and optimization by approximately $256.6 million.

      In 2002 the Company sold certain gas assets, as well as the DePere Energy Center. The decision to sell these assets required the application of one of the newly issued accounting standards, SFAS No. 144, which

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changed the criteria for determining when the disposal or sale of certain assets meets the definition of “discontinued operations.” Some of our asset sales in 2002 met the requirements of the new definition and accordingly, the Company made reclassifications to current and prior period financial statements to reflect the sale or designation as “held for sale” of certain oil and gas and power plant assets and liabilities and to separately classify the operating results of the assets sold and gain on sale of those assets from the operating results of continuing operations. See Note 10 for further information.

      In April 2002 FASB issued SFAS No. 145. SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt.” The Company elected early adoption, effective July 1, 2002, of the provisions related to the rescission of SFAS No. 4. In December 2001 the Company had recorded an extraordinary gain of $7.4 million, net of tax of $4.5 million, related to the repurchase of $122.0 million Zero Coupons. The extraordinary gain was offset by an extraordinary loss of $1.4 million, net of tax of $0.9 million, related to the write-off of unamortized deferred financing costs in connection with the repayment of $105 million of the 9 1/4% Senior Notes Due 2004 and the bridge facilities. In August 2000 in connection with repayment of outstanding borrowings, the termination of certain credit agreements and the related write-off of deferred financing costs, the Company recorded an extraordinary loss of $1.2 million, net of tax of $0.8 million.

      In October 2002 the EITF discussed EITF Issue No. 02-3. The EITF reached a consensus to rescind EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133. The EITF also reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes, as defined in SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” EITF Issue No. 02-3, had no impact on the Company’s net income but affected the presentation of the Consolidated Financial Statements. Effective July 1, 2002, the Company changed its method of reporting trading revenues to conform to this standard and accordingly, the Company reclassified certain revenue amounts and cost of revenue in its Consolidated Statements of Operations.

      The reclassification of the financial information in accordance with SFAS No. 144, SFAS No. 145 and EITF Issue No. 02-3 discussed above relates exclusively to the presentation and classification of such amounts and had no effect on net income.

 
3. Investment in Debt Securities

      The Company classifies all short-term and long-term debt securities as held-to-maturity because of the intent and ability to hold the securities to maturity. The securities are pledged as collateral to support the King City operating lease and mature serially in amounts equal to a portion of the semi-annual lease payments. The following short-term debt securities are included in Other Current Assets at December 31, 2003 and 2002:

                                                                   
2003 2002


Gross Gross Gross Gross
Amortized Unrealized Unrealized Fair Amortized Unrealized Unrealized Fair
Cost Gains Losses Value Cost Gains Losses Value








(In thousands)
Corporate Debt Securities
  $ 6,054     $ 125     $     $ 6,179     $ 2,012     $ 38     $     $ 2,050  
Government Agency Debt Securities
                            1,959       9             1,968  
U.S. Treasury Securities (non-interest bearing)
                            3,960       81             4,041  
     
     
     
     
     
     
     
     
 
 
Debt Securities
  $ 6,054     $ 125     $     $ 6,179     $ 7,931     $ 128     $     $ 8,059  
     
     
     
     
     
     
     
     
 

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CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following long-term debt securities are included in Other Assets at December 31, 2003 and 2002:

                                                                   
2003 2002


Gross Gross Gross Gross
Amortized Unrealized Unrealized Fair Amortized Unrealized Unrealized Fair
Cost Gains Losses Value Cost Gains Losses Value








(In thousands)
Corporate Debt Securities
  $ 7,855     $ 441     $     $ 8,296     $ 13,968     $ 939     $     $ 14,907  
U.S. Treasury Notes
    1,973       158             2,131       1,972       237             2,209  
U.S. Treasury Securities (non-interest bearing)
    66,700       15,074             81,774       62,224       17,068             79,292  
     
     
     
     
     
     
     
     
 
 
Debt Securities
  $ 76,528     $ 15,673     $     $ 92,201     $ 78,164     $ 18,244     $     $ 96,408  
     
     
     
     
     
     
     
     
 

      The contractual maturities of debt securities at December 31, 2003, are shown below. Actual maturities may differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

                   
Amortized Fair
Cost Value


(In thousands)
Due within one year
  $ 6,054     $ 6,179  
Due after one year through five years
    32,060       35,905  
Due after five years through ten years
    26,674       33,022  
Due after ten years
    17,794       23,274  
     
     
 
 
Total debt securities
  $ 82,582     $ 98,380  
     
     
 
 
4. Property, Plant and Equipment, Net, and Capitalized Interest

      As of December 31, 2003 and 2002, the components of property, plant and equipment, are stated at cost less accumulated depreciation and depletion as follows (in thousands):

                 
2003 2002


Buildings, machinery, and equipment
  $ 13,226,310     $ 10,169,890  
Oil and gas properties, including pipelines
    2,136,740       2,027,470  
Geothermal properties
    460,602       402,643  
Other
    234,932       183,571  
     
     
 
      16,058,584       12,783,574  
Less: Accumulated depreciation and depletion
    (1,834,701 )     (1,211,902 )
     
     
 
      14,223,883       11,571,672  
Land
    95,037       82,158  
Construction in progress
    5,762,132       7,077,017  
     
     
 
Property, plant and equipment, net
  $ 20,081,052     $ 18,730,847  
     
     
 

      Total depreciation and depletion expense for the years ended December 31, 2003, 2002 and 2001 was $600.5 million, $457.0 million and $293.8 million, respectively.

      Buildings, Machinery, and Equipment — This component includes electric power plants and related equipment. Depreciation is recorded utilizing the straight-line method over the estimated original composite useful life, generally 35 years for baseload power plants, exclusive of the estimated salvage value, typically

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CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

10%. Peaking facilities are generally depreciated over 40 years, less the estimated salvage value of 10%. The Company capitalizes the costs for major gas turbine generator refurbishment and amortizes them over their estimated useful lives of generally 3 to 6 years. The Company expenses annual planned maintenance. Included in buildings, machinery and equipment are assets under capital leases. See Note 12 for more information regarding these assets under capital leases.

      Oil and Gas Properties — The Company follows the successful efforts method of accounting for oil and natural gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Proved oil and gas properties are reviewed for potential impairment when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful. The provision for depreciation, depletion, and amortization is based on the capitalized costs as determined above, plus future abandonment costs net of salvage value, using the units of production method with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.

      Geothermal Properties — The Company capitalizes costs incurred in connection with the development of geothermal properties, including costs of drilling wells and overhead directly related to development activities, together with the costs of production equipment, the related facilities and the operating power plants at such time as management determines that it is probable the property will be developed on an economically viable basis and that costs will be recovered from operations. Proceeds from the sale of geothermal properties are applied against capitalized costs, with no gain or loss recognized.

      Geothermal costs, including an estimate of future costs to be incurred, costs to optimize the productivity of the assets, and the estimated costs to dismantle, are amortized by the units of production method based on the estimated total productive output over the estimated useful lives of the related steam fields. Depreciation of the buildings and roads is computed using the straight-line method over their estimated useful lives. It is reasonably possible that the estimate of useful lives, total unit-of-production or total capital costs to be amortized using the units-of-production method could differ materially in the near term from the amounts assumed in arriving at current depreciation expense. These estimates are affected by such factors as the ability of the Company to continue selling electricity to customers at estimated prices, changes in prices of alternative sources of energy such as hydro-generation and gas, and changes in the regulatory environment. Geothermal steam turbine generator refurbishments are expensed as incurred.

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

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CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Capital Spending — Development and Construction

      Construction and development costs in process consisted of the following at December 31, 2003 (in thousands):

                                           
Equipment Project
# of Included in Development Unassigned
Projects CIP CIP Costs Equipment





Projects in active construction
    14 (1)   $ 4,538,093     $ 1,572,708     $     $  
Projects in advanced development
    12       711,779       599,512       122,248        
Projects in suspended development
    5       466,350       204,873       8,753        
Projects in early development
    3                   8,952        
Other capital projects
    NA       45,910                    
Unassigned
    NA                         71,361  
             
     
     
     
 
 
Total construction and development costs
          $ 5,762,132     $ 2,377,093     $ 139,953     $ 71,361  
             
     
     
     
 


(1)  12 gas-fired projects and 2 project expansions. Includes expansion of the Morgan Energy Center, which entered commercial operation in January 2004.

      Projects in Active Construction — The 14 projects in active construction are estimated to come on line from January 2004 to June 2007. These projects will bring on line approximately 6,742 MW of base load (8,004 MW base load with peaking capacity). Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized. At December 31, 2003, the estimated funding requirements to complete these projects, net of expected project financing proceeds, is approximately $1.2 billion.

      Projects in Advanced Development — There are 12 projects in advanced development. These projects will bring on line approximately 5,709 MW of base load (6,835 MW base load with peaking capacity). Interest and other costs related to the development activities necessary to bring these projects to their intended use are being capitalized. However, the capitalization of interest has been suspended on two projects for which development activities are substantially complete but construction will not commence until a power purchase agreement and financing are obtained. The estimated cost to complete the 12 projects in advanced development is approximately $3.7 billion. The Company’s current plan is to project finance these costs as power purchase agreements are arranged.

      Suspended Development Projects — Due to current electric market conditions, the Company has ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met. These projects would bring on line approximately 2,569 MW of base load (3,029 MW base load with peaking capacity). The estimated cost to complete these projects is approximately $1.5 billion.

      Projects in Early Development — Costs for projects that are in early stages of development are capitalized only when it is highly probable that such costs are ultimately recoverable and significant project milestones are achieved. Until then all costs, including interest costs, are expensed. The projects in early development with capitalized costs relate to 3 projects and include geothermal drilling costs and equipment purchases.

      Other Capital Projects — Other capital projects primarily consist of enhancements to operating power plants, oil and gas and geothermal resource and facilities development, as well as software developed for internal use.

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CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Unassigned Equipment — As of December 31, 2003, the Company had made progress payments on 4 turbines, 1 heat recovery steam generator and other equipment with an aggregate carrying value of $71.4 million. This unassigned equipment is classified on the balance sheet as other assets because it is not assigned to specific development and construction projects. The Company is holding this equipment for potential use on future projects. It is possible that some of this unassigned equipment may eventually be sold, potentially in combination with the Company’s engineering and construction services. For equipment that is not assigned to development or construction projects, interest is not capitalized.

      Capitalized Interest — The Company capitalizes interest on capital invested in projects during the advanced stages of development and the construction period in accordance with SFAS No. 34, “Capitalization of Interest Cost,” as amended by SFAS No. 58, “Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34).” The Company’s qualifying assets include construction in progress, certain oil and gas properties under development, construction costs related to unconsolidated investments in power projects under construction, and advanced stage development costs. For the years ended December 31, 2003, 2002 and 2001, the total amount of interest capitalized was $444.5 million, $575.5 million and $498.7 million, including $66.0 million, $114.2 million and $136.0 million, respectively, of interest incurred on funds borrowed for specific construction projects and $378.5 million, $461.3 million and $362.7 million, respectively of interest incurred on general corporate funds used for construction. Upon commencement of plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The decrease in the amount of interest capitalized during the year ended December 31, 2003 reflects the completion of construction for several power plants and the result of the suspension of certain of the Company’s development projects.

      In accordance with SFAS No. 34, the Company determines which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. The primary debt instruments included in the rate calculation of interest incurred on general corporate funds are the Company’s Senior Notes, the Company’s term loan facilities and the secured working capital revolving credit facility.

      Impairment Evaluation — All construction and development projects and unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in fair value. Equipment assigned to such projects is not evaluated for impairment separately, as it is integral to the assumed future operations of the project to which it is assigned. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value in accordance with the provisions of SFAS No. 144. The Company reviews its unassigned equipment for potential impairment based on probability-weighted alternatives of utilizing the equipment for future projects versus selling the equipment. Utilizing this methodology, the Company does not believe that the equipment not committed to sale is impaired. However, during the year ended December 31 2003, the Company recorded approximately $27.4 million in losses in connection with the sale of four turbines, and it may incur further losses should it decide to sell more unassigned equipment in the future.

 
5. Goodwill and Other Intangible Assets

      On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires that all intangible assets with finite useful lives be amortized and that goodwill and intangible assets with indefinite lives not be amortized, but rather tested upon adoption and at least annually for impairment. The Company was required to complete the initial step of a transitional impairment test within six months of adoption of SFAS No. 142 and to complete the final step of the transitional impairment test by

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the end of the fiscal year. Any future impairment losses will be reflected in operating income or loss in the consolidated statements of operations. The Company completed both the transitional goodwill impairment test and the first annual goodwill impairment test as required and determined that the fair value of the reporting units with goodwill exceeded their net carrying values. Therefore, the Company did not record any impairment expense.

      In accordance with the standard, the Company discontinued the amortization of its recorded goodwill as of January 1, 2002, identified reporting units based on its current segment reporting structure and allocated all recorded goodwill, as well as other assets and liabilities, to the reporting units. A reconciliation of previously reported net income and earnings per share to the amounts adjusted for the exclusion of goodwill amortization is provided below (in thousands, except per share amounts):

                           
2003 2002 2001



Reported income before discontinued operations and cumulative effect of accounting changes
  $ 109,753     $ 53,690     $ 582,966  
 
Add: Goodwill amortization
                629  
     
     
     
 
Pro forma income before discontinued operations and cumulative effect of accounting changes
    109,753       53,690       583,595  
Discontinued operations and cumulative effect of accounting changes, net of tax
    172,269       64,928       40,526  
     
     
     
 
 
Pro forma net income
  $ 282,022     $ 118,618     $ 624,121  
     
     
     
 
Basic earnings per share
                       
 
As reported
  $ 0.72     $ 0.33     $ 2.05  
 
Pro forma
    0.72       0.33       2.06  
Diluted earnings per share
                       
 
As reported
  $ 0.71     $ 0.33     $ 1.80  
 
Pro forma
    0.71       0.33       1.80  

      Recorded goodwill, by segment, as of December 31, 2003 and 2002, was (in thousands):

                   
2003 2002


Electric Generation and Marketing
  $     $  
Oil and Gas Production and Marketing
           
Corporate, Other and Eliminations
    45,160       29,165  
     
     
 
 
Total
  $ 45,160     $ 29,165  
     
     
 

      The increase in goodwill of $16.0 million during 2003 is due to the acceleration of payments that the Company originally paid annually as a contingency payment based on certain performance incentives met by PSM under the terms of the PSM purchase agreement. The Company reached a conclusion that the objective of the contingency had been fully realized by PSM, thus, accelerating to 2003 the recording of goodwill to include all future payments due. These payments will continue to be made in accordance with the original schedule. Subsequent goodwill impairment tests will be performed, at a minimum, in December of each year, in conjunction with the Company’s annual reporting process.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

                                           
Weighted As of December 31, 2003 As of December 31, 2002
Average

Useful Life/ Carrying Accumulated Carrying Accumulated
Contract Life Amount(1) Amortization(1) Amount(1) Amortization(1)





Patents
    5     $ 485     $ (320 )   $ 485     $ (231 )
Power sales agreements
    22       92,947       (46,165 )     92,947       (42,360 )
Fuel supply and fuel management contracts
    26       22,198       (4,991 )     22,198       (4,105 )
Geothermal lease rights
    20       19,518       (450 )     19,518       (350 )
Steam purchase agreement
    14       5,766       (944 )     5,201       (486 )
Other
    5       2,088       (208 )     320       (71 )
             
     
     
     
 
 
Total
          $ 143,002     $ (53,078 )   $ 140,669     $ (47,603 )
             
     
     
     
 


(1)  Fully amortized intangible assets are not included.

      Amortization expense of other intangible assets was $5.3 million, $21.5 million and $23.9 million, in 2003, 2002 and 2001, respectively. Assuming no future impairments of these assets or additions as the result of acquisitions, annual amortization expense will be $4.9 million in 2004, $4.9 million in 2005, $4.8 million in 2006, $4.8 million in 2007, and $4.8 million in 2008.

 
6. Acquisitions

      The Company seeks to acquire power generating facilities and certain oil and gas properties that provide significant potential for revenue, cash flow and earnings growth, and that provide the opportunity to enhance the operating efficiency of its plants. Acquisition activity is dependent on the availability of financing on attractive terms and the expectation of returns that meets the Company’s long-term requirements. The following material mergers and acquisitions were consummated during the years ended December 31, 2003 and 2001. There were no mergers or acquisitions consummated during the year ended December 31, 2002. All business combinations were accounted for as purchases, with the exception of the Encal pooling-of-interests transaction. For all business combinations accounted for as purchases, the results of operations of the acquired companies were incorporated into the Company’s Consolidated Financial Statements commencing on the date of acquisition.

2003 Acquisitions

 
Thomassen Turbine Systems Transaction

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Because of the acquisition, TTS ceased to exist as a third party debtor to the Company, thereby resulting in a reduction of third party receivables of $5.0 million from the Company’s consolidated perspective.

2001 Acquisitions

 
Encal Transaction

      On April 19, 2001, the Company completed its merger with Encal, a Calgary, Alberta-based natural gas and petroleum exploration and development company. Encal shareholders received, in exchange for each share of Encal common stock, 0.1493 shares of Calpine common equivalent shares (called “exchangeable shares”) of the Company’s subsidiary, Calpine Canada Holdings Ltd. A total of 16,603,633 exchangeable shares were issued to Encal shareholders in exchange for all of the outstanding shares of Encal common stock. Each exchangeable share is exchangeable for one share of Calpine common stock. The aggregate value of the transaction was approximately US$1.1 billion, including the assumed indebtedness of Encal. The transaction was accounted for as a pooling-of-interests and, accordingly, all historical amounts reflected in the Consolidated Financial Statements have been restated to reflect the transaction in accordance with APB Opinion No. 16, “Business Combinations” (“APB 16”). Encal operated under the same fiscal year end as Calpine, and accordingly, Encal’s balance sheet as of December 31, 2000, and the statements of operations, shareholders’ equity and cash flows for the fiscal year ended December 31, 2000, have been combined with the Company’s Consolidated Financial Statements. The Company incurred $41.6 million in nonrecurring merger costs for this transaction. Upon completion of the acquisition, the Company gained approximately 664 billion cubic feet equivalent of proved natural gas reserves, net of royalties. This transaction also provided access to firm gas transportation capacity from western Canada to California and the eastern U.S., and an accomplished management team capable of leading the Company’s business expansion in Canada. In addition, Encal had proved undeveloped acreage totaling approximately 1.2 million acres.

 
Saltend Transaction

      On August 24, 2001, the Company acquired a 100% interest in and assumed operations of the Saltend Energy Centre (“Saltend”), a 1,200-megawatt natural gas-fired power plant located at Saltend near Hull, Yorkshire, England. The Company purchased the cogeneration facility from an affiliate of Entergy Corporation for £560.4 million (US$811.3 million at exchange rates at the closing of the acquisition). Saltend began commercial operation in November 2000 and is one of the largest natural gas-fired electric power generating facilities in England.

 
Hog Bayou and Pine Bluff Transactions

      On September 12, 2001, the Company purchased the remaining 33.3% interests in the 247-megawatt Hog Bayou Energy Center (“Hog Bayou”) and the 213-megawatt Pine Bluff Energy Center (“Pine Bluff”) from Houston, Texas-based InterGen (North America), Inc. for approximately $9.6 million and $1.4 million of a forgiven note receivable.

 
Westcoast Transaction

      On September 20, 2001, the Company’s wholly owned subsidiary, Canada Power Holdings Ltd., acquired and assumed operations of two Canadian power generating facilities from British Columbia-based Westcoast Energy Inc. (“Westcoast”) for C$325.2 million (US$207.0 million at exchange rates at the closing of the acquisition). The Company acquired a 100% interest in the Island Cogeneration facility (“Island”), a 250-megawatt natural gas-fired electric generating facility then in the commissioning phase of construction and located near Campbell River, British Columbia on Vancouver Island. The Company also acquired a 50% interest in the 50-megawatt Whitby Cogeneration facility (“Whitby”) located in Whitby, Ontario.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
California Energy General Corporation and CE Newburry, Inc. Transaction

      On October 16, 2001, the Company acquired 100% of the voting stock of California Energy General Corporation (“California Energy”) and CE Newburry, Inc. (“CE Newburry”) from MidAmerican Energy Holdings Company for $22.0 million. The transaction included geothermal resource assets, contracts, leases and development opportunities associated with the Glass Mountain Known Geothermal Resource Area (“Glass Mountain KGRA”) located in Siskiyou County, California, approximately 30 miles south of the Oregon border. These purchases were directly related to the Company’s plans to develop the 49.5-megawatt Fourmile Hill Geothermal Project located in the Glass Mountain KGRA.

 
Michael Petroleum Transaction

      On October 22, 2001, the Company completed the acquisition of 100% of the voting stock of Michael Petroleum Corporation (“Michael”), a natural gas exploration and production company, for cash of $314.0 million, plus the assumption of $54.5 million of debt. The acquired assets consisted of approximately 531 wells, producing approximately 33.5 net million cubic feet equivalent (“MMcfe”)/day of which 90 percent is gas, and developed and non-developed acreage totaling approximately 82,590 net acres at year end.

 
Delta, Metcalf and Russell City Transactions

      On November 6, 2001, the Company acquired Bechtel Enterprises Holdings, Inc.’s 50% interest in the 874-megawatt Delta Energy Center (“Delta”), the 600-megawatt Metcalf Energy Center (“Metcalf”) and the 600-megawatt Russell City Energy Center (“Russell City”) for approximately $154.0 million and the assumption of approximately $141.0 million of debt. As a result of this acquisition, the Company now owns a 100% interest in all three projects.

      The initial purchase price allocation for all material business combinations initiated after June 30, 2001, the effective date of SFAS No. 141, is shown below. As of December 31, 2001, the Company had not finalized the purchase price allocation for Saltend, Michael, or Westcoast. The allocations for the three acquisitions were subsequently completed during 2002, and the final allocations and the allocations as reported at December 31, 2001, are shown below (in thousands):

 
Final Purchase Price Allocation
                           
Michael
Saltend Petroleum Westcoast



Current assets
  $ 16,725     $ 5,970     $ 14,390  
Property, plant and equipment
    908,204       532,145       200,514  
Other assets
    9,523              
Investments in power plants
                26,000  
Current liabilities
    (21,900 )     (16,852 )     (7,932 )
Derivative liability
          (1,862 )      
Notes payable
          (54,500 )      
Other long-term liability
    (8,045 )            
Deferred tax liabilities, net
    (93,230 )     (150,944 )     (25,947 )
     
     
     
 
 
Net purchase price
  $ 811,277     $ 313,957     $ 207,025  
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Initial Purchase Price Allocation

                           
Michael
Saltend Petroleum Westcoast



Current assets
  $ 27,363     $ 5,970     $ 4,468  
Property, plant and equipment
    906,801       535,007       212,902  
Other assets
    1,478              
Investments in power plants
                25,907  
Current liabilities
    (21,900 )     (16,852 )     (6,802 )
Derivative liability
          (1,862 )      
Notes payable
          (54,500 )      
Deferred tax liabilities, net
    (95,671 )     (151,946 )     (24,408 )
     
     
     
 
 
Net purchase price
  $ 818,071     $ 315,817     $ 212,067  
     
     
     
 

      The $6.8 million decrease in the net purchase price of Saltend occurred primarily due to a $10.1 million working capital adjustment that was paid to the Company during 2002. This reduction was partially offset by a $4.0 million adjustment to reflect a previously unrecorded insurance recovery receivable held by Saltend as a result of liquidated damages Saltend owed for delays in achieving commercial operations during 2000.

      The $5.0 million decrease in the net purchase price of Westcoast occurred primarily due to a performance adjustment payment to the Company to compensate for certain plant specifications that were not met of $3.4 million and a $4.2 million compensation payment for the loss of certain tax pools that were previously represented to be held by Westcoast and were used in part to help determine the original purchase price. Both amounts were paid to the Company during 2002. These reductions were partially offset by a working capital adjustment of $2.4 million that the Company paid during 2002.

 
Pro Forma Effects of Acquisitions

      Acquired subsidiaries are consolidated upon closing date of the acquisition. The table below reflects the Company’s unaudited pro forma combined results of operations for all business combinations during 2003 and 2001, as if the acquisitions had taken place at the beginning of fiscal year 2001. The Company’s combined results include the effects of Saltend, Hog Bayou, Pine Bluff, Island, Whitby, California Energy, CE Newburry, Michael, Highland, Delta, Metcalf, Russell City and TTS (in thousands, except per share amounts):

                         
2003 2002 2001



Total revenue
  $ 8,923,142     $ 7,424,325     $ 6,966,170  
Income before discontinued operations and cumulative effect of accounting changes
  $ 110,392     $ 54,226     $ 585,308  
Net income
  $ 282,661     $ 119,154     $ 625,834  
Net income per basic share
  $ 0.72     $ 0.34     $ 2.06  
Net income per diluted share
  $ 0.71     $ 0.33     $ 1.81  

      In management’s opinion, these unaudited pro forma amounts are not necessarily indicative of what the actual combined results of operations might have been if the 2001 acquisitions had been effective at the beginning of fiscal year 2001. In addition, they are not intended to be a projection of future results and do not reflect all the synergies that might be achieved from combined operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
7. Investments in Power Projects and Oil and Gas Properties

      The Company’s investments in power projects and oil and gas properties are integral to its operations. In accordance with APB Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FASB Interpretation No. 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18),” these following investments are accounted for under the equity method (in thousands):

                           
Investment
Ownership Balance at
Interest as of December 31,
December 31,
2003 2003 2002



Acadia Energy Center(1)
    50.0 %   $ 221,038     $ 282,634  
Valladolid III IPP(2)
    45.0 %     67,320        
Aries Power Plant
    50.0 %     58,205       30,936  
Grays Ferry Power Plant
    40.0 %     53,272       42,322  
Whitby Cogeneration
    20.8 %     31,033       33,502  
Calpine Natural Gas Trust(4)
    25.0 %     28,598        
Androscoggin Power Plant
    32.3 %     11,823       9,383  
Gordonsville Power Plant(3)
          22       20,892  
Other
          1,438       1,733  
             
     
 
 
Total investments in power projects and oil and gas properties
          $ 472,749     $ 421,402  
             
     
 


(1)  On May 12, 2003, the Company completed the restructuring of its interest in Acadia. As part of the transaction, the partnership terminated its 580-MW, 20-year tolling arrangement with a subsidiary of Aquila, Inc. in return for a cash payment of $105.5 million. Acadia recorded a gain of $105.5 million and then made a $105.5 million distribution to Calpine. Contemporaneously, CES, a wholly owned subsidiary of Calpine, entered into a new 20-year, 580-MW tolling contract with Acadia. CES will now market all of the output from the Acadia Power Project under the terms of this new contract and an existing 20-year tolling agreement. Cleco will receive priority cash distributions as its consideration for the restructuring. As a result of this transaction, the Company recorded, as its share of the termination payment from the Aquila subsidiary, a $52.8 million gain, which was recorded within income from unconsolidated investments in power projects and oil and gas properties. Due to the restructuring of its interest in Acadia, the Company was required to reconsider its investment in the entity under FIN 46 and determined that it is not the Primary Beneficiary and accordingly will continue to account for its investment using the equity method. See Note 2 for further information.
 
(2)  See Note 8 for a discussion of the Valladolid project.
 
(3)  On November 26, 2003, the Company completed the sale of its 50 percent interest in the Gordonsville Power Plant. Under the terms of the transaction, the Company received $36.2 million in cash and recorded a pre-tax gain of $7.1 million. The residual investment balance in Gordonsville at December 31, 2003, is a result of third party outstanding receivables that are expected to be collected early in 2004.
 
(4)  See Note 9 for information on the Calpine Natural Gas Trust.

      On March 29, 2002, the Company sold its 11.4% interest in the Lockport Power Plant in exchange for a $27.3 million note receivable, which was subsequently paid in full, from Fortistar Tuscarora LLC, a wholly owned subsidiary of Fortistar LLC, the project’s managing general partner. As a result, the Company did not have an investment balance at December 31, 2003 or 2002, and a pre-tax gain of $9.7 million was recorded in other income during the first quarter of 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The combined unaudited results of operations and financial position of the Company’s equity method affiliates are summarized below (in thousands):

                           
December 31,

2003 2002 2001



Condensed statements of operations:
                       
 
Revenue
  $ 427,961     $ 372,212     $ 401,452  
 
Gross profit
    149,423       151,784       148,476  
 
Income from continuing operations
    126,590       132,911       102,904  
 
Net income
    175,892       70,596       87,003  
Condensed balance sheets:
                       
 
Current assets
  $ 98,035     $ 133,801          
 
Non-current assets
    1,687,612       1,740,056          
     
     
         
 
Total assets
  $ 1,785,647     $ 1,873,857          
     
     
         
 
Current liabilities
  $ 118,278     $ 132,516          
 
Non-current liabilities
    731,428       946,383          
     
     
         
 
Total liabilities
  $ 849,706     $ 1,078,899          
     
     
         

      The debt on the books of the unconsolidated power projects is not reflected on the Company’s balance sheet. At December 31, 2003, investee debt is approximately $455.9 million. Based on the Company’s pro rata ownership share of each of the investments, the Company’s share would be approximately $145.0 million. However, all such debt is non-recourse to the Company.

      The Company owns a 32.3% interest in the unconsolidated equity method investee Androscoggin Energy LLC (“AELLC”). AELLC owns the 160-MW Androscoggin Energy Center located in Maine and has construction debt of $60.8 million outstanding as of December 31, 2003. The debt is non-recourse to Calpine Corporation (the “AELLC Non-Recourse Financing”). On December 31, 2003, the Company’s investment balance was $11.8 million and its notes receivable balance due from AELLC was $13.3 million. On and after August 8, 2003, AELLC received letters from the lenders claiming that certain events of default have occurred under the credit agreement for the AELLC Non-Recourse Financing, including, among other things, that the project has been and remains in default under its debt agreement because the lending syndication had declined to extend the dates for the conversion of the construction loan to a term loan by a certain date. AELLC disputes the purported defaults. Also, the steam host for the AELLC project, International Paper Company (“IP”), filed a complaint against AELLC in October 2000, which is disclosed in Note 24. IP’s complaint has been a complicating factor in converting the construction debt to long term financing. As a result of these events, the Company has reviewed its investment and notes receivable balances and believes that the assets are not impaired. The Company further believes that AELLC will be able to convert the construction loan to a term loan.

      The Company also owns a 50% interest in the unconsolidated equity method investee Merchant Energy Partners Pleasant Hill, LLC (“Aries”). Currently, the Company is finalizing the purchase of the 50% interest in Aries that is held by Aquila, Inc. Following the purchase, the Company will have a 100% interest in Aries. Aries owns the 591-MW Aries Power Project located in Pleasant Hill, Missouri, and has construction debt of $190.0 million as of December 31, 2003, that was due but unpaid on June 26, 2003. Due to this payment default, the partners were required to contribute their proportionate share of $75 million in additional equity. During the second quarter of 2003, the Company drew down $37.5 million under its working capital revolver to fund its equity contribution. In conjunction with the Aquila buyout negotiations, the Company is in negotiation with the lenders on a term loan for the project. The project is technically in default of its debt

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

agreement until the new term loan is completed. The Company believes that the project will be able to obtain long-term project financing at commercially reasonable terms. As a result of this event, the Company has reviewed its $58.2 million investment in the Aries project and believes that the investment is not impaired.

      The following details the Company’s income and distributions from investments in unconsolidated power projects and oil and gas properties (in thousands):

                                                   
Income (loss) from Unconsolidated
Investments in Power Projects and
Oil and Gas Properties Distributions


For the Years Ended December 31,

2003 2002 2001 2003 2002 2001






Acadia Energy Center
  $ 75,272     $ 14,590     $     $ 136,977     $ 11,969     $  
Aries Power Plant
    (3,442 )     (43 )                        
Grays Ferry Power Plant
    (1,380 )     (1,499 )     594                    
Whitby Cogeneration
    303       411       684                   637  
Calpine Natural Gas Trust
    898                   1,959              
Androscoggin Power Plant
    (7,478 )     (3,951 )     (846 )                    
Gordonsville Power Plant
    11,985       5,763       4,453       2,672       2,125       825  
Lockport Power Plant
          1,570       5,562                   4,351  
Other
    80       (351 )     (293 )     19       23       170  
     
     
     
     
     
     
 
 
Total
  $ 76,238     $ 16,490     $ 10,154     $ 141,627     $ 14,117     $ 5,983  
     
     
     
     
     
     
 
Interest income on loans to power projects(1)
  $ 465     $ 62     $ 6,792                          
     
     
     
                         
 
Total
  $ 76,703     $ 16,552     $ 16,946                          
     
     
     
                         


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

(1)  At December 31, 2003 and 2002, loans to power projects represented an outstanding loan to the Company’s 32.3% owned investment, Androscoggin Energy Center LLC, in the amounts of $13.3 million and $3.1 million, respectively.

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

 
Related-Party Transactions

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

        Operation and Maintenance Agreements — The Company operates and maintains the Acadia Power Plant and Androscoggin Power Plant. This includes routine maintenance, but not major maintenance, which is typically performed under agreements with the equipment manufacturers. Responsibilities include development of annual budgets and operating plans. Payments include reimbursement of costs, including Calpine’s internal personnel and other costs, and annual fixed fees.
 
        Administrative Services Agreements — The Company handles administrative matters such as bookkeeping for certain unconsolidated investments. Payment is on a cost reimbursement basis, including Calpine’s internal costs, with no additional fee.

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        Power Marketing Agreements — Under agreements with Androscoggin Power Plant, CES can either market the plant’s power as the power facility’s agent or buy the power directly. Terms of any direct purchase are to be agreed upon at the time and incorporated into a transaction confirmation. Historically, CES has generally bought the power from the power facility rather than acting as its agent.
 
        Gas Supply Agreement — CES can be directed to supply gas to the Androscoggin Power Plant facility pursuant to transaction confirmations between the facility and CES. Contract terms are reflected in individual transaction confirmations.

      The power marketing and gas supply contracts with CES are accounted for as either purchase and sale arrangements or as tolling arrangements. In a purchase and sale arrangement, title and risk of loss associated with the purchase of gas is transferred from CES to the project at the gas delivery point. In a tolling arrangement, title to fuel provided to the project does not transfer, and CES pays the project a capacity and a variable fee based on the specific terms of the power marketing and gas supply agreements. In addition to the contracts specified above, CES maintains two tolling agreements with the Acadia facility. CPN Pleasant Hill LLC, a wholly owned subsidiary of Calpine, maintains two other tolling agreements with the Aries facility.

      All of the other power marketing and gas supply contracts are accounted for as purchases and sales.

      The related party balances as of December 31, 2003 and 2002, reflected in the accompanying consolidated balance sheets, and the related party transactions for the years ended December 31, 2003, 2002 and 2001, reflected in the accompanying consolidated statements of operations are summarized as follows (in thousands):

                         
2003 2002


As of December 31,
                       
Accounts receivable
  $ 1,156     $ 735          
Accounts payable
    12,172       4,088          
Interest receivable
    2,074       956          
Note Receivable
    13,262       3,062          
Other receivables
    8,794       6,002          
                         
2003 2002 2001



For the Years Ended December 31,
                       
Revenue
  $ 2,878     $ 4,291     $  
Cost of Revenue
    82,205       36,290       6,030  
Maintenance fee revenue
    615       438       43  
Interest income
    1,117       132       203  
 
8. Notes Receivable

      The long-term notes receivable are recorded by discounting expected future cash flows using current interest rates at which similar loans would be made to borrowers with similar credit ratings and remaining maturities. The Company intends to hold these notes to maturity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      As of December 31, 2003, and 2002, the components of notes receivable were (in thousands):

                   
2003 2002


PG&E (Gilroy) note
  $ 155,901     $ 163,584  
Panda note
    38,644       30,818  
Androscoggin note
    13,262       3,062  
Mitsui & Co., Ltd.
    8,779        
Other
    8,506       6,493  
     
     
 
 
Total notes receivable
    225,092       203,957  
Less: Notes receivable, current portion
    (11,463 )     (8,559 )
     
     
 
Notes receivable, net of current portion
  $ 213,629     $ 195,398  
     
     
 

      Calpine Gilroy Cogen, LP (“Gilroy”) had a long-term power purchase agreement (“PPA”) with Pacific Gas and Electric Company (“PG&E”) for the sale of energy through 2018. The terms of the PPA provided for 120 megawatts of firm capacity and up to 10 megawatts of as-delivered capacity. On December 2, 1999, the California Public Utilities Commission (“CPUC”) approved the restructuring of the PPA between Gilroy and PG&E. Under the terms of the restructuring, PG&E and Gilroy were each released from performance under the PPA effective November 1, 2002. Under the restructured contract, in addition to the normal capacity revenue for the period, Gilroy had earned from September 1999 to October 2002 restructured capacity revenue it would have earned over the November 2002 through March 2018 time period, for which PG&E had issued notes to the Company. These notes are scheduled to be paid by PG&E during the period from February 2003 to September 2014. The first scheduled note repayment of $1.7 million was received in February 2003.

      On December 4, 2003, the Company announced that it had sold to a group of institutional investors its right to receive payments from PG&E under the Agreement between PG&E and Calpine Gilroy Cogen, L.P (“Gilroy”), a California Limited Partnership (PG&E Log No. 08C002) For Termination and Buy-Out of Standard Offer 4 Power Purchase Agreement, executed by PG&E on July 1, 1999 (the “Gilroy Receivable”) for $133.4 million in cash. Because the transaction did not satisfy the criteria for sales treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities — a Replacement of FASB Statement No. 125,” it is reflected in the Consolidated Financial Statements as a secured financing, with a note payable of $133.4 million. The receivable balance and note payable balance are both reduced as PG&E makes payments to the buyer of the Gilroy Receivable. The $24.1 million difference between the $157.5 million book value of the Gilroy Receivable at the transaction date and the cash received will be recognized as additional interest expense over the repayment term. The Company will continue to book interest income over the repayment term and interest expense will be accreted on the amortizing note payable balance.

      Pursuant to the applicable transaction agreements, each of Gilroy and Calpine Gilroy 1, Inc., the general partner of Gilroy, has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. The Company consolidates these entities.

      In June 2000 the Company entered into a series of turbine sale contracts with, and acquired the development rights to construct, own and operate the Oneta Energy Center (“Oneta”) from, Panda Energy International, Inc. and certain related entities. As part of the transaction, the Company extended PLC II, LLC (“PLC”) a loan bearing an interest rate of LIBOR plus 5%. The loan is collateralized by PLC’s carried

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

interest in the income generated from Oneta, which achieved full commercial operations in June 2003. Additionally, Panda Energy International, Inc. executed a parental Guaranty as to the loan.

      On November 5, 2003, Panda Energy International, Inc. and certain related parties, including PLC, (collectively “Panda”) filed suit against the Company and certain of its affiliates alleging, among other things, that the Company breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate Oneta in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits from Oneta and that the Company’s actions have reduced the profits from Oneta, thereby undermining Panda’s ability to repay monies owed to the Company under the loan. The Company has filed a counterclaim against Panda Energy International, Inc. (and PLC) based on a Guaranty, and has also filed a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The Company considers Panda’s lawsuit to be without merit and intends to defend vigorously against it.

      Panda defaulted on the loan, which was due on December 1, 2003. Because of the Guaranty and the collateral, a reserve is not needed as of December 31, 2003. However, the Company ceased accruing interest after the default date and will closely monitor the receivable until the resolution of the litigation.

      The Company owns a 32.3% interest in the unconsolidated equity method investee Androscoggin Energy LLC (“AELLC”). AELLC owns the 160-MW Androscoggin Energy Center located in Maine. On December 31, 2003, the Company’s notes receivable balance due from AELLC related to unreimbursed administrative costs associated with the Company’s management of the project was $13.3 million. See Note 7 for more information on the Company’s interest in AELLC.

      In December 2003 the Company contributed two gas turbines with a book value of approximately $76.0 million in exchange for a 45% interest in the Valladolid Joint Venture project with Mitsui & Co., Ltd (“Mitsui”) in Mexico. The Company recorded its interest in the project at a value of $67.0 million, which reflects the cost of the turbines less an $9.0 million note receivable that was booked upon transfer of the turbines, representing a return of capital. Subsequently, Mitsui assumed the note receivable from the project and received additional equity in the project. The Company’s capital account on the project’s books reflects a balance of approximately $36 million. The Company’s investment in and notes receivable from Mitsui exceed its share of the underlying equity by $31 million, which will be amortized as an adjustment to the Company’s share of the project’s net income over the depreciable life of the underlying assets.

 
9. Canadian Power and Gas Trusts

      Calpine Power Income Fund — On August 29, 2002, the Company announced it had completed a Cdn$ 230 million (US$147.5 million) initial public offering of its Canadian income fund — Calpine Power Income Fund (the “Fund”). The 23 million Trust Units issued to the public were priced at Cdn$ 10 per unit, to initially yield 9.35% per annum. The Fund indirectly owns, through its 70% ownership of Calpine Power Limited Partnership (“CLP”), interests in two of Calpine’s Canadian power generating assets, the Island Cogeneration Facility and the Calgary Energy Centre, and has a loan to a Calpine subsidiary which owns Calpine’s other Canadian power generating asset, the equity investment in the Whitby cogeneration plant. Combined, these assets represent approximately 550 net megawatts of power generating capacity.

      On September 20, 2002, the syndicate of underwriters fully exercised the over-allotment option that it was granted as part of the initial public offering of Trust Units and acquired 3,450,000 additional Trust Units of the Fund at Cdn$ 10 per Trust Unit, generating Cdn$ 34.5 million (US$21.9 million).

      On February 13, 2003, the Company completed a secondary offering of 17,034,234 Warranted Units of the Calpine Power Income Fund for gross proceeds of Cdn$ 153.3 million (US$100.9 million). The Warranted Units were sold to a syndicate of underwriters at a price of Cdn$ 9.00. Each Warranted Unit consisted of one Trust Unit and one-half of one Trust Unit purchase warrant. Each Warrant entitled the holder to purchase one Trust Unit at a price of Cdn$ 9.00 per Trust Unit at any time on or prior to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 30, 2003, after which time the Warrant became null and void. During 2003, a total of 8,508,517 Warrants were exercised, resulting in cash proceeds to the Company of Cdn$ 76.6 million (US$56.7 million). The Company’s remaining ownership interest in the Fund is less than 1%; however, the Company intends to retain its 30% subordinated interest in CLP and will retain a significant continuing involvement in the assets transferred to CLP.Therefore, the financial results of CLP are consolidated in the Company’s financial statements. The proceeds from the initial public offering, the proceeds from the secondary offering of Trust Units and the proceeds from the exercise of Warrants have been recorded as minority interests in the Company’s balance sheet.

      Calpine Natural Gas Trust — On October 15, 2003, the Company closed the initial public offering of Calpine Natural Gas Trust (“CNG Trust”). A total of 18,454,200 trust units were issued at a price of Cdn$ 10.00 per trust unit for gross proceeds of approximately Cdn$ 184.5 million (US$139.4 million). CNG Trust acquired select natural gas and petroleum properties from Calpine with the proceeds from the initial public offering, Cdn$ 61.5 million (US$46.5 million) proceeds from a concurrent issuance of units to a Canadian affiliate of Calpine, and Cdn$ 40.0 million (US$30.2 million) proceeds from bank debt. Net proceeds to Calpine, totaling approximately Cdn$ 207.9 million (US$157.1 million), reflecting a gain of $62.2 million on the transfer of the properties, will be used for general corporate purposes. On October 22, 2003, the syndicate of underwriters fully exercised the over-allotment option associated with the initial public offering resulting in additional cash to the Calpine Natural Gas Trust. As a result of the exercise of the over-allotment option, Calpine acquired an additional 615,140 trust units at Cdn$ 10.0 per trust unit for a cash payment to the Calpine Natural Gas Trust of Cdn$ 6.2 million (US$4.7 million). Calpine holds 25 percent of the outstanding trust units of CNG Trust and will participate, by way of investment, in the future business strategy of the trust. The Company also has the option to purchase up to 100% of CNG Trust’s ongoing natural gas and petroleum production at daily spot prices. The CNG Trust receives a minimum price of $7.35 per mcf on all natural gas production for six months following closing. The Company accounts for this unconsolidated investment using the equity method.

 
10. Discontinued Operations

      The Company has adopted a strategy of conserving its core strategic assets and selectively disposing of certain less strategically important assets, which serves primarily to raise cash for general corporate purposes and strengthen the Company’s balance sheet through repayment of debt. Set forth below are all of the Company’s asset disposals by reportable segment that impacted the Company’s Consolidated Financial Statements as of December 31, 2003 and December 31, 2002:

 
Corporate and Other

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

 
Oil and Gas Production and Marketing

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

      On October 1, 2002, the Company completed the sale of substantially all of its British Columbia oil and gas properties to Calgary, Alberta-based Pengrowth Corporation for gross proceeds of approximately Cdn$ 387.5 million (US$244.3 million). Of the total consideration, the Company received US$155.9 million in cash. The remaining US$88.4 million of consideration was paid by Pengrowth Corporation’s purchase in the open market of US$203.2 million in aggregate principal amount of the Company’s debt securities. As a result

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of the transaction, the Company recorded a US$37.4 million pre-tax gain on the sale of the properties and a gain on the extinguishment of debt of US$114.8 million in the fourth quarter 2002. The Company used approximately US$50.4 million of cash proceeds to repay amounts outstanding under its US$1.0 billion term loan. See Note 16 for more information about the specific debt securities delivered to the Company as a result of this transaction.

      On October 31, 2002, the Company sold all of its oil and gas properties in Drake Bay Field located in Plaquemines Parish, Louisiana for approximately $3 million to Goldking Energy Corporation. As a result of the sale, the Company recognized a pre-tax loss of $0.02 million in the fourth quarter 2002.

      On November 20, 2003, the Company completed the sale of its Alvin South Field oil and gas assets located near Alvin, Texas for approximately $0.06 million to Cornerstone Energy, Inc. As a result of the sale, the Company recognized a pre-tax loss of $0.2 million.

 
Electric Generation and Marketing

      On December 16, 2002, the Company completed the sale of the 180-megawatt DePere Energy Center in DePere, Wisconsin. The facility was sold to Wisconsin Public Service for $120.4 million, which included $72.0 million in cash at closing and a $48.4 million payment due in December 2003. As a result of the sale, the Company recognized a pre-tax gain of $35.8 million. On December 17, 2002, the Company sold its right to the December 2003 payment to a third party for $46.3 million, and recognized a pre-tax loss of $2.1 million thereon.

      In December 2003 the Company announced its intention to sell its 50% interest in the 545-Megawatt Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the Lower Colorado River Authority (“LCRA”). The sale was subsequently completed on January 15, 2004. Under the terms of the agreement, Calpine received a cash payment of $146.8 million and recorded a gain before taxes of $35.5 million in January 2004. In addition, CES entered into a tolling agreement with LCRA to purchase 250 Megawatts of electricity through December 31, 2004.

 
Summary

      The Company made reclassifications to current and prior period financial statements to reflect the sale or designation as “held for sale” of these oil and gas and power plant assets and liabilities and to separately classify the operating results of the assets sold and gain on sale of those assets from the operating results of continuing operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The tables below present significant components of the Company’s income from discontinued operations for 2003, 2002 and 2001, respectively (in thousands):

                                 
2003

Electric Oil and Gas
Generation Production Corporate and
and Marketing and Marketing Other Total




Total revenue
  $ 72,968     $ 1,150     $ 3,748     $ 77,866  
     
     
     
     
 
Loss on disposal before taxes
  $     $ (235 )   $ (11,571 )   $ (11,806 )
Operating income (loss) from discontinued operations before taxes
    4,147       84       (6,918 )     (2,687 )
     
     
     
     
 
Income (loss) from discontinued operations before taxes
  $ 4,147     $ (151 )   $ (18,489 )   $ (14,493 )
     
     
     
     
 
Loss on disposal, net of tax
  $     $ (146 )   $ (7,172 )   $ (7,318 )
Operating income (loss) from discontinued operations, net of tax
    2,694       49       (4,099 )     (1,356 )
     
     
     
     
 
Income (loss) from discontinued operations, net of tax
  $ 2,694     $ (97 )   $ (11,271 )   $ (8,674 )
     
     
     
     
 
                                 
2002

Electric Oil and Gas
Generation Production Corporate and
and Marketing and Marketing Other Total




Total revenue
  $ 75,004     $ 76,783     $ 7,653     $ 159,440  
     
     
     
     
 
Gain on disposal before taxes
  $ 35,840     $ 59,288     $     $ 95,128  
Operating income (loss) from discontinued operations before taxes
    16,388       13,264       (16,968 )     12,684  
     
     
     
     
 
Income (loss) from discontinued operations before taxes
  $ 52,228     $ 72,552     $ (16,968 )   $ 107,812  
     
     
     
     
 
Gain on disposal, net of tax
  $ 21,377     $ 35,153     $     $ 56,530  
Operating income (loss) from discontinued operations, net of tax
    10,700       7,751       (10,053 )     8,398  
     
     
     
     
 
Income (loss) from discontinued operations, net of tax
  $ 32,077     $ 42,904     $ (10,053 )   $ 64,928  
     
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                                 
2001

Electric Oil and Gas
Generation Production Corporate and
and Marketing and Marketing Other Total




Total revenue
  $ 49,270     $ 140,318     $ 6,864     $ 196,452  
     
     
     
     
 
Gain on disposal before taxes
  $     $     $     $  
Operating income (loss) from discontinued operations before taxes
    9,034       70,224       (1,869 )     77,389  
     
     
     
     
 
Income (loss) from discontinued operations before taxes
  $ 9,034     $ 70,224     $ (1,869 )   $ 77,389  
     
     
     
     
 
Gain on disposal, net of tax
  $     $     $     $  
Operating income (loss) from discontinued operations, net of tax
    6,148       34,450       (1,108 )     39,490  
     
     
     
     
 
Income (loss) from discontinued operations, net of tax
  $ 6,148     $ 34,450     $ (1,108 )   $ 39,490  
     
     
     
     
 

      The table below presents the assets and liabilities held for sale on the Company’s balance sheet as of December 31, 2003 and 2002, respectively (in thousands):

                                                                   
2003 2002


Electric Oil and Gas Electric Oil and Gas
Generation Production Corporate and Generation Production Corporate and
and Marketing and Marketing Other Total and Marketing and Marketing Other Total








Current assets of discontinued operations
  $ 651     $     $     $ 651     $ 664     $     $ 2,005     $ 2,669  
Long-term assets of discontinued operations
    112,148                   112,148       115,337       396       11,630       127,363  
     
     
     
     
     
     
     
     
 
 
Total assets of discontinued operations
  $ 112,799     $     $     $ 112,799     $ 116,001     $ 396     $ 13,635     $ 130,032  
     
     
     
     
     
     
     
     
 
Current liabilities of discontinued operations
  $     $     $     $     $     $     $ 1,962     $ 1,962  
Long-term liabilities of discontinued operations
    161                   161                   19       19  
     
     
     
     
     
     
     
     
 
 
Total liabilities of discontinued operations
  $ 161     $     $     $ 161     $     $     $ 1,981     $ 1,981  
     
     
     
     
     
     
     
     
 

      The Company allocates interest expense associated with consolidated non-specific debt to its discontinued operations based on a ratio of the net assets of its discontinued operations to the Company’s total consolidated net assets, in accordance with EITF Issue No. 87-24, “Allocation of Interest to Discontinued Operations” (“EITF Issue No. 87-24”). Also in accordance with EITF Issue No. 87-24, the Company allocated interest expense to its British Columbia oil and gas properties for approximately $50.4 million of debt the Company is required to repay under the terms of its $1.0 billion term loan. In 2002 and 2001, the Company allocated interest expense of $6.2 million and $4.5 million, respectively, to its discontinued operations. No interest expense was allocated to discontinued operations in 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

                                   
Letters of Credit
Borrowings Outstanding Outstanding
December 31, December 31,


2003 2002 2003 2002




Total term loan
  $     $ 949,565     $     $  
 
Power Contract Financing, L.L.C. 
    802,246                    
 
Gilroy note payable(1)
    132,385                    
 
Siemens Westinghouse Power Corporation
    107,994                    
 
Calpine Northbrook Energy Marketing, LLC (“CNEM”) note
    74,632                    
 
Corporate revolving lines of credit
          340,000       135,600       573,899  
 
Other
    10,607       8,952       603        
     
     
     
     
 
Total notes payable and borrowings under lines of credit
    1,127,864       348,952       136,203       573,899  
Total notes payable to Calpine Capital Trusts
    1,153,500                    
 
Preferred interest in Auburndale Power Plant
    87,632                    
 
Preferred interest in King City Power Plant
    82,000                    
 
Preferred interest in Gilroy Energy Center Holdings, LLC
    74,000                    
     
     
     
     
 
Total preferred interests
    243,632                    
Total notes payable and borrowings under lines of credit, notes payable to Calpine Capital Trusts, preferred interests, and term loan
  $ 2,524,996     $ 1,298,517     $ 136,203     $ 573,899  
     
     
     
     
 
 
Less: notes payable and borrowings under lines of credit, current portion, notes payable to Calpine Capital Trusts, current portion and preferred interests, current portion
    265,512       340,703                  
     
     
                 
Notes payable and borrowings under lines of credit, net of current portion, notes payable to Calpine Capital Trusts, net of current portion, preferred interests, net of current portion, and term loan
  $ 2,259,484     $ 957,814                  
     
     
                 


(1)  See Note 8 for information regarding this note.
 
Notes Payable and Borrowings Under Lines of Credit and Term Loan

      In March 2002, the Company closed a new secured credit agreement which at that point was comprised of (a) a $1.0 billion revolving credit facility expiring on May 24, 2003 and (b) a two-year term loan facility for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

up to $600.0 million. In May 2002, the term loan facility was subsequently increased to $1.0 billion through a term of May 24, 2004, while the amount of the revolving credit facility was decreased to $600.0 million. Any letters of credit issued under the $600.0 million revolving credit facility on or prior to May 24, 2003 could be extended for up to one year at our option so long as they expired no later than five business days prior to the maturity date of the term-loan facility. As part of the March 2002 closings, the Company also amended its existing $400.0 million unsecured revolving credit agreement to provide, among other things, security for borrowings under that agreement. The $400.0 million revolving credit facility matured on May 23, 2003. All outstanding borrowings on the term loan facility and the $600.0 million and $400.0 million revolving credit facilities were repaid on July 16, 2003. All letters of credit issued under the company’s $600.0 million and $400.0 million revolving credit facilities were reissued by letters of credit issued under the company’s new $500.0 million working capital facility and the company’s new $200.0 million cash collateralized letter of credit facility, both of which closed on July 16, 2003.

      Borrowings bore variable interest and interest was paid on the last day of each interest period for such loans, at least quarterly. The term loan and credit facilities specified that the Company maintain certain covenants, with which the Company was in compliance as of December 31, 2002 and 2001, and at repayment on July 16, 2003. Commitment fees related to the revolving lines of credit are charges based on unused credit amounts. The effective interest rate on the term loan, after amortization of deferred financing charges, was 8.0% per annum at repayment on July 16, 2003. The effective interest rate on the $600.0 million revolving credit facility, after amortization of deferred financing charges, was 10.8% per annum at repayment on July 16, 2003. The effective interest rate on the $400.0 million revolving credit facility, after amortization of deferred financing charges, was 5.1% per annum at repayment on July 16, 2003.

      On July 16, 2003, the Company entered into agreements for a new $500 million working capital facility. The new first-priority senior secured facility consists of a two-year, $300 million working capital revolver and a four-year, $200 million term loan that together provide up to $500 million in combined cash borrowing and letter of credit capacity. The new facility replaced the Company’s prior $600 million and $400 million working capital facilities and is secured by a first-priority lien on the same assets that collateralize the Company’s recently completed $3.3 billion term loan and second-priority senior secured notes offering (the “$3.3 billion offering”). See Note 16 for more information on the $3.3 billion offering and the $200 million term loan discussed above. The $949.6 million outstanding under the Company’s secured term credit facility and the $555.5 million outstanding under the Company’s revolving credit facilities were repaid on July 16, 2003, with the proceeds of the $3.3 billion offering. There were no funded borrowings on the $300 million working capital revolver during 2003, while as of December 31, 2003, the company had $135.6 million in letters of credit under this facility.

      On July 16, 2003, the Company entered into a cash collateralized letter of credit facility with The Bank of Nova Scotia under which it can issue up to $200 million of letters of credit through July 15, 2005. As of December 31, 2003, the Company had $136.5 million of letters of credit issued under this facility, with a corresponding amount of cash on deposit and held by The Bank of Nova Scotia as collateral, which was classified as restricted cash in the Company’s Consolidated Balance Sheet.

      As part of the Company’s acquisition of Michael Petroleum Corporation (“MPC”) through its wholly owned subsidiary Calpine Natural Gas Company, the Company assumed a $75.0 million three-year revolving credit facility with Bank One, N.A. and other banks. Amounts outstanding under the facility bore variable interest. The interest rate ranged from 4.3% to 5.0% during 2002. The line of credit was secured by the Company’s oil and gas properties. The Company was out of compliance as of December 31, 2001, with a covenant under the loan agreement. Subsequent to December 31, 2001, the Company initiated the process to obtain a waiver for the covenant but chose to instead repay the outstanding balance of $64.8 million under the loan agreement on March 13, 2002.

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      On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of CES, completed an offering of $339.9 million of 5.2% Senior Secured Notes Due 2006 and $462.3 million of 6.256% Senior Secured Notes Due 2010. The two tranches of Senior Secured Notes, totaling $802.2 million of gross proceeds, are secured by fixed cash flows from a fixed-priced, long-term power sales agreement with the State of California Department of Water Resources and a fixed-priced, long-term power purchase agreement with a third party and are non-recourse to the Company’s other consolidated subsidiaries. The two tranches of Senior Secured Notes have been rated Baa2 by Moody’s Investor Service, Inc. and BBB (with a negative outlook) by S&P. As of December 31, 2003, PCF had $802.2 million outstanding under these secured note borrowings. The effective interest rate on the 5.2% Senior Secured Notes Due 2006 and 6.256% Senior Secured Notes Due 2010, after amortization of deferred financing costs, was 8.3% and 9.4%, respectively, per annum at December 31, 2003.

      Pursuant to the applicable transaction agreements, PCF has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. In accordance with FIN 46 the Company consolidates this entity. See Note 2 for more information on FIN 46. The above mentioned power sales and power purchase agreements, which have been acquired by PCF from CES, and the PCF Notes are assets and liabilities of PCF, separate from the assets and liabilities of the Company and other subsidiaries of the Company. The proceeds of the Senior Secured Notes were primarily used by PCF to purchase the power sales and power purchase agreements.

      On January 31, 2002, the Company’s subsidiary, Calpine Construction Management Company, Inc., entered into an agreement with Siemens Westinghouse Power Corporation (“SWPC”) to reschedule the production and delivery of gas and steam turbine generators and related equipment. Under the agreement, the Company obtained vendor financing of up to $232.0 million bearing variable interest for gas and steam turbine generators and related equipment. The financing had been due prior to the earliest of the equipment site delivery date specified in the agreement, the Company’s requested date of turbine site delivery or June 25, 2003. On July 10, 2003, the Company renegotiated its financing agreement with SWPC to extend the monthly payment due dates through January 28, 2005. Subsequent to this renegotiation, the Company made additional payments to SWPC. As a result of these additional payments, the Company intends to repay this financing by November 2004. At December 31, 2003, there was $108.0 million in borrowings outstanding under this agreement. The interest rate at December 31, 2003 and 2002, was 8.5% and 6.6%, respectively. The interest rate ranged from 6.4% to 8.5% during 2003.

      On May 15, 2003, CNEM, a wholly owned stand-alone subsidiary of CNEM Holdings LLC, which is a wholly owned indirect subsidiary of CES, completed an offering of $82.8 million secured by an existing power sales agreement with the BPA. Under the existing 100-MW fixed-price contract, CNEM delivers baseload power to BPA through December 31, 2006. As a part of the secured transaction, CNEM entered into a contract with a third party to purchase that power based on spot prices and a fixed-price swap agreement with an affiliate of Deutsche Bank to lock in the price of the purchased power. The terms of both agreements are through December 31, 2006. To complete the transactions, CNEM then entered into an agreement with an affiliate of Deutsche Bank and borrowed $82.8 million secured by the BPA contract, the spot market power purchase agreement, the fixed price swap agreement and the equity interests in CNEM. The spread between the price for power under the BPA contract and the price for power under the fixed price swap agreement provides the cash flow to pay CNEM’s debt and other expenses. Proceeds from the borrowing were used to pay transaction expenses for plant construction and general corporate purposes, as well as fees and expenses associated with this transaction. CNEM will make quarterly principal and interest payments on the loan that matures on December 31, 2006. As of December 31, 2003, there was $74.6 million outstanding under this loan. The effective interest rate, after amortization of deferred financing charges, was 12.7% per annum at December 31, 2003.

      Pursuant to the applicable transaction agreements, each of CNEM and its parent, CNEM Holdings, LLC, has been established as an entity with its existence separate from the Company and other subsidiaries of

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the Company. In accordance with FIN 46 the Company consolidates these entities. See Note 2 for more information on FIN 46. The above mentioned power sales agreement with BPA has been acquired by CNEM from CES and the spot market power purchase agreement with a third party and the swap agreement have been entered into by CNEM and, together with the $82.8 million loan, are assets and liabilities of CNEM, separate from the assets and liabilities of the Company and other subsidiaries of the Company. The only significant asset of CNEM Holdings, LLC is its equity interest in CNEM. The proceeds of the $82.8 million loan were primarily used by CNEM to purchase the power sales agreement with BPA.

 
Notes Payable to Calpine Capital Trusts

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

                                                                         
Conversion
Effective Ratio —
Interest Rate Number of
Stated per Annum at Balance Balance Common Initial
Interest December 31, December 31, December 31, Shares Per 1 First Redemption Redemption
Issue Date Shares Rate 2003 2003 2002 High Tide Date Price









HIGH TIDES I
    October 1999       5,520,000       5.75%       5.86%     $ 276,000     $ 268,608       3.4620       November 5, 2002       101.440%  
HIGH TIDES II
    January and February 2000       7,200,000       5.50%       5.59%       360,000       351,499       1.9524       February 5, 2003       101.375%  
HIGH TIDES III
    August 2000       10,350,000       5.00%       5.10%       517,500       503,862       1.1510       August 5, 2003       101.250%  
             
                     
     
                         
              23,070,000                     $ 1,153,500 (1)   $ 1,123,969                          
             
                     
     
                         


(1)  Prior to the adoption of FIN 46-R on October 1, 2003, the Trusts were consolidated in the Company’s Consolidated Balance Sheet, and the HIGH TIDES were recorded between total liabilities and stockholders equity as Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts. However, due to the adoption of FIN 46-R, the Company deconsolidated the Trusts as of October 1, 2003, and therefore no longer records the HIGH TIDES in its Consolidated Balance Sheet. However, the Company’s debentures issued to the Trusts are now recorded as notes payable to Calpine Capital Trusts in the Company’s Consolidated Balance Sheet with an outstanding balance of $1,153,500,000 at December 31, 2003. During 2003 the Company exchanged 6.5 million Calpine common shares in privately negotiated transactions for approximately $37.5 million par value of HIGH TIDES I. The repurchased HIGH TIDES are reflected in our balance sheet in other assets as available for sale securities. See Note 2 for more information regarding the Company’s adoption of FIN 46-R.

      The net proceeds from each of the offerings were used by the Trusts to invest in convertible subordinated debentures of the Company, which represent substantially all of the respective trusts’ assets. The Company has effectively guaranteed all of the respective trusts’ obligations under the trust preferred securities. The trust preferred securities have liquidation values of $50.00 per share, or $1.2 billion in total for all of the issuances. The Company has the right to defer the interest payments on the debentures for up to twenty consecutive quarters, which would also cause a deferral of distributions on the trust preferred securities. Currently, the Company has no intention of deferring interest payments on the debentures.

      The trust preferred securities are convertible into shares of the Company’s common stock at the holder’s option on or prior to the tender notification date. Additionally, the HIGH TIDES may be redeemed at any time on or after the initial redemption date. The redemption price declines to 100% during the one year following the initial redemption date.

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Preferred Interests

      On September 3, 2003, the Company announced that it had completed the sale of a 70% preferred interest in its Auburndale power plant to Pomifer Power Funding, LLC, (“PPF”), a subsidiary of ArcLight Energy Partners Fund I, L.P., for $88.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, due to certain preferential distributions to PPF. The preferential distributions are to be paid quarterly beginning in November 2003 and total approximately $204.7 million over the 11-year period. The preferred interest holders’ recourse is limited to the net assets of the entity and distribution terms are defined in the agreement. The Company has not guaranteed the payment of these preferential distributions. Calpine will hold the remaining interest in the facility and will continue to provide operations and maintenance services. As of December 31, 2003, there was $87.6 million outstanding under this preferred interest. The effective interest rate, after amortization of deferred financing charges, was 16.8% per annum at December 31, 2003.

      On April 29, 2003, the Company sold a preferred interest in a subsidiary that leases and operates the 115-MW King City Power Plant to GE Structured Finance for $82.0 million. The preferred interest holder will receive approximately 60% of future cash flow distributions based on current projections. The Company will continue to provide O&M services. As of December 31, 2003, there was $82.0 million outstanding under the preferred interest. The effective interest rate, after amortization of deferred financing charges, was 12.8% per annum at December 31, 2003.

      Pursuant to the applicable transaction agreements, each of Calpine King City Cogen LLC, Calpine Securities Company, L.P., a parent company of Calpine King City Cogen LLC, and Calpine King City, LLC, an indirect parent company of Calpine Securities Company, L.P., has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. The Company consolidates these entities.

      On September 30, 2003, GEC, a wholly owned subsidiary of the Company’s subsidiary GEC Holdings, LLC, completed an offering of $301.7 million of 4% Senior Secured Notes Due 2011 (see Note 16 for more information on this secured financing). In connection with this secured notes borrowing, the Company received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0 million. This preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as debt under the guidance of SFAS No. 150, due to certain preferential distributions to the third party. The preferential distributions are due bi-annually beginning in March 2004 through September 2011 and total approximately $113.3 million over the eight-year period. As of December 31, 2003, there was $74.0 million outstanding under the preferred interest. The effective interest rate, after amortization of deferred financing charges, was 11.3% per annum at December 31, 2003.

      Pursuant to the applicable transaction agreements, GEC has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. The Company consolidates this entity. The long-term power sales agreement with the State of California Department of Water Resources has been acquired by GEC by means of a series of capital contributions by CES and certain of its affiliates and is an asset of GEC, and the Senior Secured Notes and preferred interest are liabilities of GEC, separate from the assets and liabilities of the Company and other subsidiaries of the Company. Aside from seven peaker power plants owned directly and the power sales agreement, GEC’s assets include cash and a 100% equity interest in each of Creed Energy Center, LLC (“Creed”) and Goose Haven Energy Center, LLC (“Goose Haven”) each of which is a wholly owned subsidiary of GEC. Each of Creed and Goose Haven has been established as an entity with its existence separate from the Company and other subsidiaries of the Company. Creed and Goose Haven each have assets consisting of various power plants and other assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
12. Capital Lease Obligations

      During 2001 the Company assumed and consolidated capital leases in conjunction with certain acquisitions. As of December 31, 2003 and 2002, the asset balances for the leased assets totaled $201.5 million and $201.1 million, respectively, with accumulated amortization of $26.0 million and $20.4 million, respectively. The primary types of property leased by the Company are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The lease terms range up to 28 years.

      The following is a schedule by years of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2003 (in thousands):

             
Years Ending December 31:
       
 
2004
  $ 19,264  
 
2005
    19,348  
 
2006
    19,956  
 
2007
    20,018  
 
2008
    21,791  
 
Thereafter
    290,519  
     
 
   
Total minimum lease payments
    390,896  
Less: Amount representing interest(1)
    (193,147 )
     
 
 
Present value of net minimum lease payments
    197,749  
Less: Capital lease obligation, current portion
    4,008  
     
 
 
Capital lease obligation, net of current portion
  $ 193,741  
     
 


(1)  Amount necessary to reduce net minimum lease payments to present value calculated at the incremental borrowing rate at the time of acquisition.
 
13. Zero-Coupon Convertible Debentures

      On April 30, 2001, the Company completed the sale of $1.0 billion of Zero-Coupon Convertible Debentures Due 2021 (“Zero Coupons”) in a private placement under Rule 144A of the Securities Act of 1933.

      In December 2001 the Company repurchased $122.0 million in aggregate principal amount of its Zero Coupons in open-market purchases at a discount, and recorded a pre-tax gain of $11.9 million after the write-off of related financing costs. In January and February 2002 the Company repurchased an additional $192.5 million of its Zero Coupons at a discount and recorded a pre-tax gain of $3.5 million, after the write-off of related financing costs. On April 30, 2002, the Company repurchased the remaining $685.5 million in aggregate principal amount of its Zero Coupons at par pursuant to a scheduled put provided for by the terms of the Zero Coupons.

      The effective interest rate, after amortization of deferred financing costs, was 2.5% in 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
14. Construction/Project Financing

      The components of construction/project financing as of December 31, 2003 and 2002, are (in thousands):

                                     
Letters of Credit
Outstanding at
Outstanding at December 31, December 31,


Projects 2003 2002 2003 2002





Calpine Construction Finance Company II Revolver
  $ 2,200,358     $ 2,469,642     $ 53,190     $ 3,224  
Calpine Construction Finance Company I
                               
 
Second Priority Senior Secured Floating Rate Notes Due 2011
    407,598                    
 
First Priority Secured Institutional Term Loans Due 2009
    381,391                    
Calpine Construction Finance Company I Revolver
          970,110             29,890  
Gilroy Energy Center, LLC, 4% Senior Secured Notes Due 2011
    298,065                    
Pasadena Cogeneration, L.P. 
    289,115       388,867              
Broad River Energy LLC
    291,612       300,974              
SWPC(1)
          169,180              
Riverside Energy Center
    165,347                    
Blue Spruce Energy Center LLC
    140,000       83,540              
California Peaker Financing
          50,000              
Calpine Newark, Inc. 
    47,815       50,000              
Calpine Parlin Inc. 
    32,451       37,000              
Otay Mesa Generating Company, LLC — Ground Lease
    7,000                    
     
     
     
     
 
   
Total
    4,260,752       4,519,313     $ 53,190     $ 33,114  
                     
     
 
Less: Current portion
    65,108       1,307,291                  
     
     
                 
Long-term project financing
  $ 4,195,644     $ 3,212,022                  
     
     
                 


(1)  See Note 11 for information regarding the SWPC vendor financing.

      In October 2000 the Company entered into a credit agreement for $2.5 billion through its wholly owned subsidiary Calpine Construction Finance Company II, LLC (“CCFC II”) with a consortium of banks. The lead arrangers were The Bank of Nova Scotia and Credit Suisse First Boston. The non-recourse credit facility is utilized to finance the construction of certain of the Company’s gas-fired power plants currently under construction. As of December 31, 2003, the Company had $2.2 billion in borrowings outstanding under the facility. Borrowings under this facility bear variable interest. The credit facility specifies that the Company maintain certain covenants, with which the Company was in compliance as of December 31, 2003. The interest rate at December 31, 2003 and 2002, was 2.6% and 2.9%, respectively. The interest rate ranged from 2.6% to 2.9% during 2003. The effective interest rate, after amortization of deferred financing costs, was 3.4% per annum at December 31, 2003. See Note 27 for information regarding the Company’s refinancing of this facility.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      In November 1999 the Company entered into a credit agreement for $1.0 billion through its wholly owned subsidiary Calpine Construction Finance Company L.P. (“CCFC I”) with a consortium of banks. The lead arranger was The Bank of Nova Scotia and the lead arranger syndication agent was Credit Suisse First Boston. The non-recourse credit facility was utilized to finance the construction of certain of the Company’s gas-fired power plants. The Company repaid the outstanding balance of $880.1 million in August 2003. Borrowings under this facility bore variable interest. The interest rate at December 31, 2002, was 2.9%. The interest rate ranged from 2.6% to 5.0% during 2003. The effective interest rate, after amortization of deferred financing costs, averaged 4.3% per annum in 2003.

      On August 14, 2003, the Company’s wholly owned subsidiaries, CCFC I and CCFC Finance Corp., closed a $750.0 million institutional term loans and secured notes offering, proceeds from which were utilized to repay a majority of CCFC I’s indebtedness which would have matured in the fourth quarter of 2003. The offering included $385.0 million of First Priority Secured Institutional Term Loans Due 2009 (the “CCFC I Term Loans”) offered at 98% of par and priced at LIBOR plus 600 basis points, with a LIBOR floor of 150 basis points, and $365.0 million of Second Priority Senior Secured Floating Rate Notes Due 2011 (the “CCFC I Senior Notes”) offered at 98.01% of par and priced at LIBOR plus 850 basis points, with a LIBOR floor of 125 basis points. On September 25, 2003, CCFC I and CCFC Finance Corp. closed on an additional $50.0 million of the CCFC I Senior Notes offered at 99% of par. The noteholders’ recourse is limited to seven of CCFC I’s natural gas-fired electric generating facilities located in various power markets in the United States, and related assets and contracts. S&P has assigned a B corporate credit rating to CCFC I. S&P also assigned a B+ rating (with a negative outlook) to the CCFC I Term Loans and a B- rating (with a negative outlook) to the CCFC I Senior Notes.

      As of December 31, 2003, the company had $407.6 million in borrowings outstanding under the CCFC I Senior Notes. The interest rate at December 31, 2003, was 9.8%. The effective interest rate, after amortization of deferred financing costs, was 10.0% per annum at December 31, 2003.

      As of December 31, 2003, the company had $381.4 million in borrowings outstanding under the CCFC I Term Loans. The interest rate during 2003 was 7.5%. The effective interest rate, after amortization of deferred financing costs, was 8.2% per annum at December 31, 2003.

      On September 30, 2003, GEC, a wholly owned, stand-alone subsidiary of the Company’s subsidiary GEC Holdings, LLC, closed on $301.7 million of 4% Senior Secured Notes Due 2011. The senior secured notes are secured by GEC’s and its subsidiaries’ 11 peaking units located at nine power-generating sites in northern California. The notes also are secured by a long-term power sales agreement for 495 megawatts of peaking capacity with the State of California Department of Water Resources, which is being served by the 11 peaking units. In addition, payment of the principal and interest on the notes when due is insured by an unconditional and irrevocable financial guaranty insurance policy that was issued simultaneously with the delivery of the notes. Proceeds of the notes offering (after payment of transaction expenses, including payment of the financial guaranty insurance premium, which are capitalized and included in deferred financing costs on the balance sheet) will be used to reimburse costs incurred in connection with the development and construction of the peaker projects. The noteholders’ recourse is limited to the financial guaranty insurance policy and, insofar as payment has not been made under such policy, to the assets of GEC and its subsidiaries. The Company has not guaranteed repayment of the notes. As of December 31, 2003, there was $298.1 million outstanding under this secured notes borrowing. The effective interest rate, after amortization of deferred financing charges, was 5.1% per annum at December 31, 2003. In connection with this offering, the Company has received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0 million. See Note 11 for more information regarding this preferred interest.

      In September 2000, the Company completed the financing, which matures in 2048, for both Phase I and Phase II of the Pasadena, Texas cogeneration project. Under the terms of the project financing, the Company

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

received $400.0 million in gross proceeds. At December 31, 2003, the Company had $289.1 million in borrowings outstanding. The interest rate at December 31, 2003 and 2002, was 8.6%.

      In October 2001, the Company completed the financing, which matures in 2041, for the Broad River Energy Center in South Carolina. Under the terms of the project financing, the Company received $300.0 million in gross proceeds. At December 31, 2003, the Company had $291.6 million in borrowings outstanding. The interest rate at December 31, 2003 and 2002, was 8.1%.

      On August 25, 2003, the Company announced that it had completed a $230.0 million non-recourse project financing for its 600-megawatt Riverside Energy Center. The natural gas-fueled electric generating facility is currently under construction in Beloit, Wisconsin. Upon completion of the project, which is scheduled for June 2004, Calpine will sell 450 megawatts of electricity to Wisconsin Power and Light under the terms of a nine-year tolling agreement and provide 75 megawatts of capacity to Madison Gas & Electric under a nine-year power sales agreement. A group of banks, including Credit Lyonnais, Co-Bank, Bayerische Landesbank, HypoVereinsbank and NordLB, will finance construction of the plant at a rate of Libor plus 250 basis points. Upon commercial operation of the Riverside Energy Center, the banks will provide a three-year term-loan facility initially priced at Libor plus 275 basis points. At December 31, 2003, there was $165.3 million outstanding under this project financing. The interest rate at December 31, 2003 was 3.7%. The interest rate ranged from 3.6% to 5.8% during 2003. The effective interest rate, after amortization of deferred financing costs, was 5.3% per annum at December 31, 2003.

      On August 22, 2002, the Company completed a $106.0 million non-recourse project financing for the construction of its 300-megawatt Blue Spruce Energy Center. On November 7, 2003, the Company repaid the outstanding balance of $102.0 million with the proceeds of a new term financing described below. The effective interest rate, after amortization of deferred financing costs, and interest rate swap effect, was 14.1% in 2003.

      On November 7, 2003, the Company completed a new $140.0 million term loan financing for the Blue Spruce Energy Center. The term loan is made up of two facilities, Tranche A and Tranche B, which have 15-year and 6-year repayment terms, respectively. At December 31, 2003, there was $100.0 million outstanding under Tranche A and $40.0 million outstanding under Tranche B. The interest rate at December 31, 2003, for Tranche A and Tranche B was 7.67% and 8.57%, respectively. The effective interest rate, after amortization of deferred financing costs, for Tranche A and Tranche B was 8.2% and 8.6%, respectively, per annum at December 31, 2003.

      On May 14, 2002, the Company’s subsidiary, Calpine California Energy Finance, LLC, entered into an $100.0 million amended and restated credit agreement with ING Capital LLC for the funding of 9 California peaker facilities, of which $100.0 million was drawn on May 24, 2002,and $50.0 million was repaid on August 7, 2002, and the remaining $50.0 million was repaid on July 21, 2003. The interest rate ranged from 3.5% to 3.9% during 2003. The effective interest rate, after amortization of deferred financing costs, was 4.0% per annum at December 31, 2003.

      In December 2002 the Company completed a $50.0 million project financing secured by the Newark Power Plant. At December 31, 2003, the Company had $47.8 million in funded borrowings under this project financing. The interest rate at December 31, 2003 and 2002, was 10.6%. This project financing will mature in 2014.

      In December 2002 the Company completed a $37.0 million project financing secured by the Parlin Power Plant. At December 31, 2003, the Company had $32.5 million in funded borrowings under this project financing. The interest rate at December 31, 2003 and 2002, was 9.8%. This project financing will mature in 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      On July 8, 2003, Otay Mesa Generating Company, LLC, entered into a ground lease and easement agreement with D&D Landholdings, a Limited Partnership. At December 31, 2003, there was $7.0 million outstanding under this financing arrangement. The interest rate at December 31, 2003 was 12.6%.

 
15. Convertible Senior Notes
 
4% Convertible Senior Notes Due 2006

      In December 2001 and January 2002 the Company completed the issuance of $1.2 billion in aggregate principal amount of 4% Convertible Senior Notes Due 2006 (“2006 Convertible Senior Notes”). These securities are convertible, at the option of the holder, into shares of Calpine common stock at a price of $18.07. Holders have the right to require the Company to repurchase all or a portion of the 2006 Convertible Senior Notes on December 26, 2004, at 100% of their principal amount plus any accrued and unpaid interest. The Company has the right to repurchase the 2006 Convertible Senior Notes with cash, shares of Calpine common stock, or a combination of cash and stock. During 2003 the Company repurchased approximately $474.9 million in aggregate outstanding principal amount of the 2006 Convertible Senior Notes at a repurchase price of $458.8 million plus accrued interest Additionally, during 2003, approximately $65.0 million in aggregate outstanding principal amount of the 2006 Convertible Senior Notes were exchanged for 12.0 million shares of Calpine common stock in privately negotiated transactions. The Company recorded a pre-tax gain on these transactions in the amount of $13.6 million, net of write-offs of the associated unamortized deferred financing costs and unamortized premiums or discounts. At December 31, 2003, there was $660.1 million in outstanding borrowings under these notes. The effective interest rate on these notes at December 31, 2003 and 2002, after amortization of deferred financing costs, was 4.9% per annum, respectively

 
4 3/4% Contingent Convertible Senior Notes Due 2023

      On November 17, 2003, the Company completed the issuance of $650 million 4 3/4% Contingent Convertible Senior Notes Due 2023 (“2023 Convertible Notes”). These 2023 Convertible Notes are convertible, at the option of holder, into cash and into shares of Calpine common stock at a price of $6.50 per share, which represents a 38% premium over the New York Stock Exchange closing price of $4.71 per Calpine common share on November 6, 2003. Holders have the right to require the Company to repurchase all or a portion of these securities on November 15, 2009, November 15, 2013, and November 15, 2018, at 100% of their principal amount plus any accrued and unpaid interest and liquidated damages, if any, up to the date of repurchase. The Company has the right to pay the repurchase price in cash, shares of Calpine common stock, or a combination of cash and stock. At December 31, 2003, there was $650.0 million in outstanding borrowings under these notes. The effective interest rate on these notes, after amortization of deferred financing costs, was approximately 4.9% per annum at December 31, 2003. See Note 27 regarding a subsequent event relating to these notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
16. Senior Notes

      Senior Notes payable consist of the following as of December 31, 2003 and 2002, (in thousands):

                                                         
Fair Value as of
December 31, December 31,(3)
Interest First Call

Rates Date 2003 2002 2003 2002






First Priority Senior Secured Notes
                                               
 
First Priority Senior Secured Term Loan B Notes Due 2007
    (4)       (2)     $ 199,500     $     $ 202,243     $  
                     
     
     
     
 
   
Total First Priority Senior Secured Notes
                    199,500             202,243        
                     
     
     
     
 
 
Second Priority Senior Secured Notes
                                               
 
Second Priority Senior Secured Term Loan B Notes Due 2007
    (5)       (8)       748,125             727,552        
 
Second Priority Senior Secured Floating Rate Notes Due 2007
    (6)       (7)       498,750             488,775        
 
Second Priority Senior Secured Notes Due 2010
    8 1/2 %     (7)       1,150,000             1,127,000        
 
Second Priority Senior Secured Notes Due 2013
    8 3/4 %     (7)       900,000             877,500        
 
Second Priority Senior Secured Notes Due 2011
    9 7/8 %     (1)       392,159             401,963        
                     
     
     
     
 
   
Total Second Priority Senior Secured Notes
                    3,689,034             3,622,790        
                     
     
     
     
 
Unsecured Senior Notes
                                               
 
Senior Notes Due 2005
    8 1/4 %     (2)       224,679       249,420       215,692       117,227  
 
Senior Notes Due 2006
    10 1/2 %     2001       166,575       171,750       163,243       82,440  
 
Senior Notes Due 2006
    7 5/8 %     (1)       214,613       249,821       191,006       107,423  
 
Senior Notes Due 2007
    8 3/4 %     2002       226,120       275,107       187,679       118,296  
 
Senior Notes Due 2007(9)
    8 3/4 %     (2)       154,120       125,782       114,049       55,973  
 
Senior Notes Due 2008
    7 7/8 %     (1)       305,323       379,689       236,624       155,672  
 
Senior Notes Due 2008
    8 1/2 %     (2)       1,925,067       2,027,859       1,540,053       892,258  
 
Senior Notes Due 2008(10)
    8 3/8 %     (2)       154,140       183,509       114,064       67,898  
 
Senior Notes Due 2009
    7 3/4 %     (1)       232,520       329,593       179,041       135,133  
 
Senior Notes Due 2010
    8 5/8 %     (2)       496,909       707,036       390,074       304,025  
 
Senior Notes Due 2011
    8 1/2 %     (2)       1,179,911       1,875,571       932,130       806,496  
 
Senior Notes Due 2011(11)
    8 7/8 %     (2)       215,242       319,664       157,127       115,079  
                     
     
     
     
 
   
Total Other Senior Notes
                    5,495,219       6,894,801       4,420,782       2,957,920  
                     
     
     
     
 
     
Total Senior Notes
                    9,383,753       6,894,801       8,245,815       2,957,920  
                     
     
     
     
 
     
Less: Senior Notes, current portion
                    14,500             14,500        
                     
     
     
     
 
       
Senior Notes, net of current portion
                  $ 9,369,253     $ 6,894,801     $ 8,231,315     $ 2,957,920  
                     
     
     
     
 


  (1)  Not redeemable prior to maturity.
 
  (2)  Redeemable by the Company at any time prior to maturity.
 
  (3)  Represents the market values of the Senior Notes at the respective dates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(10)  Issued in Euros.
 
(11)  Issued in Sterling.

      The Company has completed a series of public debt offerings since 1994. Interest is payable semiannually at specified rates. Deferred financing costs are amortized using the effective interest method, over the respective lives of the notes. There are no sinking fund or mandatory redemptions of principal before the maturity dates of each offering. Certain of the Senior Note indentures limit the Company’s ability to incur additional debt, pay dividends, sell assets and enter into certain transactions. As of December 31, 2003, the Company was in compliance with all debt covenants relating to the Senior Notes. The effective interest rates for each of the Company’s Senior Notes outstanding at December 31, 2003, are consistent with the respective notes outstanding during 2002, unless otherwise noted.

      In October 2002, $88.4 million of purchase price consideration for certain oil and gas assets was paid by Pengrowth Corporation’s purchase in the open market and delivery to the Company of $203.2 million in aggregate principal amount of certain of the Company’s Senior Notes. The Company recorded a pre-tax gain, net of write-off of unamortized deferred financing costs, of US$114.8 million related to these purchases. See Note 12 for more details regarding this transaction.

      The following debt securities were delivered to the Company by Pengrowth Corporation (in millions):

           
Debt Security Principal Amount


7 7/8% Senior Notes Due 2008
  $ 19.6  
7 3/4% Senior Notes Due 2009
    20.2  
8 5/8% Senior Notes Due 2010
    42.3  
8 1/2% Senior Notes Due 2011
    121.1  
     
 
 
Total
  $ 203.2  
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Senior notes repurchased by the Company during the year totaled $1,378.5 million in aggregate outstanding principal amount at a repurchase price of $1,116.5 million plus accrued interest. The Company recorded a pre-tax gain on these transactions in the amount of $245.5 million, net of write-offs of unamortized deferred financing costs and the unamortized premiums or discounts. The following table summarizes the total senior notes repurchased by the Company in the year ended December 31, 2003 (in millions):

                 
Principal Amount
Debt Security Amount Repurchased



8 1/4% Senior Notes Due 2005
  $ 25.0     $ 24.5  
10 1/2% Senior Notes Due 2006
    5.2       5.1  
7 5/8% Senior Notes Due 2006
    35.3       32.5  
8 3/4% Senior Notes Due 2007
    48.9       45.0  
7 7/8% Senior Notes Due 2008
    74.8       58.3  
8 1/2% Senior Notes Due 2008
    48.3       42.3  
8 3/8% Senior Notes Due 2008
    59.2       46.6  
7 3/4% Senior Notes Due 2009
    97.2       75.9  
8 5/8% Senior Notes Due 2010
    210.4       170.7  
8 1/2% Senior Notes Due 2011
    648.4       521.3  
8 7/8% Senior Notes Due 2011
    125.8       94.3  
     
     
 
    $ 1,378.5     $ 1,116.5  
     
     
 

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

                 
Principal Common Stock
Debt Security Amount Issued



8 1/2% Senior Notes Due 2008
  $ 55.0       8.1  
8 1/2% Senior Notes Due 2011
    25.0       3.4  
     
     
 
    $ 80.0       11.5  
     
     
 
 
First Priority Senior Secured Term Loan B Notes Due 2007

      The Company must repay these notes in 16 consecutive quarterly installments, commencing on October 15, 2003, and ending on July 15, 2007, the first fifteen of which will be for 0.25% of the original principal amount of the notes thru April 15, 2007. The final installment, on July 15, 2007, will be 96.25% of the original principal amount. Interest is payable on each quarterly payment date occurring after the closing date of July 16, 2003. These notes may be redeemed at any time prior to maturity provided, however, that (1) any such prepayment shall be made pro rata among loans of the same type and, if applicable, having the same interest period, of all lenders; (2) each such voluntary partial prepayment shall be in an aggregate minimum amount of $2.0 million; and (3) that no voluntary prepayment of these notes shall be permitted unless the $300 million working capital revolver is reduced by at least a ratable amount. Interest is payable on each quarterly payment date occurring after the closing date of July 16, 2003. At December 31, 2003, both the book and face value of these notes was $199.5 million. The effective interest rate, after amortization of deferred financing costs, was 5.0% per annum at December 31, 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Second Priority Senior Secured Term Loan B Notes Due 2007

      The Company must repay these notes in 16 consecutive quarterly installments, commencing on October 15, 2003, and ending on July 15, 2007, the first fifteen of which will be 0.25% of the original principal amount of the notes thru April 15, 2007. The final installment, on July 15, 2007, will be 96.25% of the original principal amount. Interest is payable on each quarterly payment date occurring after the closing date of July 16, 2003. The Company may not voluntarily prepay these notes prior to July 15, 2005, except that the Company may on any one or more occasions make such prepayment with the proceeds of one or more public equity offerings. At December 31, 2003, both the book and face value of these notes was $748.1 million. The effective interest rate, after amortization of deferred financing costs, was 7.5% per annum at December 31, 2003.

 
Second Priority Senior Secured Floating Rate Notes Due 2007

      The Company must repay these notes in 16 consecutive quarterly installments, commencing on October 15, 2003, and ending on July 15, 2007, the first fifteen of which will be 0.25% of the original principal amount of the notes thru April 15, 2007. The final installment, on July 15, 2007, will be 96.25% of the original principal amount. On or before July 15, 2005, on one or more occasions, the Company may use the proceeds from one or more public equity offerings to redeem up to 35% of the aggregate principal amount of the notes at the stated redemption price of par plus the applicable Eurodollar rate in effect at the time of redemption. Interest is payable on each quarterly payment date occurring after the closing date of July 16, 2003. At December 31, 2003, both the book and face value of these notes was $498.8 million. The effective interest rate, after amortization of deferred financing costs, was 7.4% per annum at December 31, 2003.

 
Second Priority Senior Secured Notes Due 2010

      Interest is payable on these notes on January 15 and July 15 of each year. The notes will mature on July 15, 2010. On or before July 15, 2006, on one or more occasions, the Company may use the proceeds from one or more public equity offerings to redeem up to 35% of the aggregate principal amount of the notes at the stated redemption price of 108.5%. At December 31, 2003, both the book and face value of these notes were $1,150.0 million. The effective interest rate, after amortization of deferred financing costs, was 8.8% per annum at December 31, 2003.

 
Second Priority Senior Secured Notes Due 2013

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

 
Second Priority Senior Secured Notes Due 2011

      Interest is payable on these notes on June 1 and December 1 of each year, commencing on June 1, 2004. The notes will mature on December 1, 2011, and are not redeemable prior to maturity. At December 31, 2003, the book and face value of these notes were $392.2 million and $400.0 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 10.5% per annum at December 31, 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Senior Notes Due 2005

      Interest on the 8 1/4% notes is payable semi-annually on February 15 and August 15. The notes mature on August 15, 2005, or may be redeemed at any time prior to maturity at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2003, the book value and face value of these notes were $224.7 million and $225.0 million, respectively. The effective interest rate, after amortization of deferred financing costs, is 8.7% per annum.

 
Senior Notes Due 2006

      Interest on the 10 1/2% notes is payable semi-annually on May 15 and November 15 each year. The notes mature on May 15, 2006, or are redeemable, at the option of the Company, at any time on or after May 15, 2001, at various redemption prices. In addition, the Company may redeem up to $63.0 million of the Senior Notes Due 2006 from the proceeds of any public equity offering. At December 31, 2003, both the book value and face value of these notes were $166.6 million. The effective interest rate, after amortization of deferred financing costs, was 10.6% per annum at December 31, 2003, and 10.8% per annum at December 31, 2002.

      Interest on the 7 5/8% notes is payable semi-annually on April 15 and October 15 each year. The notes mature on April 15, 2006, and are not redeemable prior to maturity. At December 31, 2003, the book value and face value of these notes were $214.6 million and $214.7 million, respectively. The effective interest rate, after amortization of deferred financing costs, is 7.9% per annum.

 
Senior Notes Due 2007

      Interest on the 8 3/4% notes maturing on July 15, 2007, is payable semi-annually on January 15 and July 15 each year. These notes are redeemable, at the option of the Company, at any time on or after July 15, 2002, at various redemption prices. In addition, the Company may redeem up to $96.3 million of the Senior Notes Due 2007 from the proceeds of any public equity offering. At December 31, 2003, both the book value and face value of these notes were $226.1 million. The effective interest rate, after amortization of deferred financing costs, is 9.1% per annum.

      Interest on the 8 3/4% notes maturing on October 15, 2007, is payable semi-annually on April 15 and October 15 each year. The Notes and may be redeemed prior to maturity, at any time in whole or from time to time in part, at a redemption price equal to the greater of (a) the “Discounted Value” of the senior notes, which equals the sum of the present values of all remaining scheduled payments of principal and interest, or (b) 100% of the principal amount plus accrued and unpaid interest to the redemption date. The Notes are fully and unconditionally guaranteed by the Company. At December 31, 2003, the book value and face value of these notes were $154.1 million and $154.8 million, respectively. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 8.9% at December 31, 2003, and 9.1% per annum at December 31, 2002.

 
Senior Notes Due 2008

      Interest on the 7 7/8% notes is payable semi-annually on April 1 and October 1 each year. These notes mature on April 1, 2008, and are not redeemable prior to maturity. At December 31, 2003, the book value and face value of these notes were $305.3 million and $305.7 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 8.1% per annum at December 31, 2003, and 8.0% per annum at December 31, 2002. The Notes are fully and unconditionally guaranteed by the Company.

      Interest on the 8 1/2% notes is payable semi-annually on May 1 and November 1 each year. The notes mature on May 1, 2008, or may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2003, the book value and face value of these notes were $1,925.1 million and $1,926.7 million, respectively. The effective

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

interest rate, after amortization of deferred financing costs, was 8.7% per annum at December 31, 2003, and 8.8% per annum at December 31, 2002.

      Interest on the 8 3/8% notes is payable semi- annually on April 15 and October 15 each year. The notes mature on October 15, 2008, or may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2003, both the book value and face value of these notes were $154.1 million. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 8.7% per annum at December 31, 2003, and 9.5% per annum at December 31, 2002.

 
Senior Notes Due 2009

      Interest on these 7 3/4% notes is payable semi-annually on April 15 and October 15 each year. The notes mature on April 15, 2009, and are not redeemable prior to maturity. At December 31, 2003, the book value and face value of these notes were $232.5 million and $232.6 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 8.0% per annum at December 31, 2003, and 7.9% per annum at December 31, 2002.

 
Senior Notes Due 2010

      Interest on these 8 5/8% notes is payable semi-annually on August 15 and February 15 each year. The notes mature on August 15, 2010, and may be redeemed at any time prior to maturity at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2003, the book value and face value of these notes were $496.9 million and $497.3 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 8.8% per annum.

 
Senior Notes Due 2011

      Interest on the 8 1/2% notes is payable semi-annually on February 15 and August 15 each year. The notes mature on February 15, 2011, and may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2003, the book value and face value of these notes were $1,179.9 million and $1,181.8 million, respectively. The effective interest rate, after amortization of deferred financing costs, was 8.7% per annum.

      Interest on the 8 7/8% notes is payable semi-annually on April 15 and October 15 each year. The notes mature on October 15, 2011, and may be redeemed prior to maturity at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest plus a make-whole premium. At December 31, 2003, the book value and face value of these notes were $215.2 million and $216.7 million, respectively. The effective interest rate, after amortization of deferred financing costs and the effect of cross currency swaps, was 9.4% per annum at December 31, 2003, and 8.9% per annum at December 31, 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
17. Annual Debt Maturities and Minimum Sublease Rentals

      The annual principal repayments or maturities of notes payable and borrowings under lines of credit, notes payable to Calpine Capital Trusts, preferred interests, construction/project financing, 2006 Convertible Senior Notes, 2023 Convertible Notes, senior notes and capital lease obligations as of December 31, 2003, are as follows (in thousands):

 
Annual Debt Repayments or Maturities
           
2004
  $ 349,128  
2005
    506,639  
2006
    1,332,800  
2007
    2,187,223  
2008
    2,599,421  
Thereafter
    10,702,098  
     
 
 
Total
  $ 17,677,309  
     
 
 
Minimum Sublease Rentals

      The Company has a power sales agreement for the Broad River facility that is accounted for as a lease. The minimum sublease rentals to be received by the Company in connection with this agreement is $16.5 million, $16.8 million, $17.2 million, $17.5 million, and $17.9 million for the years 2004 through 2008, respectively. Minimum sublease rentals for 2009 and thereafter are $250.9 million.

 
18. Provision for Income Taxes

      The jurisdictional components of income before provision for income taxes at December 31, 2003, 2002, and 2001, are as follows (in thousands):

                           
2003 2002 2001



U.S. 
  $ 42,667     $ 94,633     $ 914,490  
International
    66,952       (55,888 )     (33,910 )
     
     
     
 
 
Income before provision for income taxes
  $ 109,619     $ 38,745     $ 880,580  
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The provision (benefit) for income taxes for the years ended December 31, 2003, 2002, and 2001, consists of the following (in thousands):

                               
2003 2002 2001



Current:
                       
 
Federal
  $ 137,008     $ (39,402 )   $ 183,533  
 
State
    25,582       3,837       43,676  
 
Foreign
    (10,647 )     5,898       5,810  
     
     
     
 
   
Total Current
    151,943       (29,667 )     233,019  
Deferred:
                       
 
Federal
    (180,181 )     99,595       96,848  
 
State
    (36,270 )     13,970       (16,863 )
 
Foreign
    64,374       (98,843 )     (15,390 )
     
     
     
 
   
Total Deferred
    (152,077 )     14,722       64,595  
     
     
     
 
     
Total provision (benefit)
  $ (134 )   $ (14,945 )   $ 297,614  
     
     
     
 

      The Company’s effective rate for income taxes for the years ended December 31, 2003, 2002, and 2001, differs from the United States statutory rate, as reflected in the following reconciliation:

                         
2003 2002 2001



United States statutory tax rate
    35.0 %     35.0 %     35.0 %
State income tax, net of federal benefit
    4.8       29.9       2.0  
Depletion and other permanent items
    0.8       (0.2 )     0.0  
Tax credits
    (2.3 )     (9.0 )     0.0  
Foreign tax at rates other than U.S. statutory
    (83.2 )     (102.8 )%     (3.2 )
Other, net (including U.S. tax on Foreign Income)
    44.8       8.5       0.0  
     
     
     
 
Effective income tax rate
    (0.1 )%     (38.6 )%     33.8 %
     
     
     
 

      The components of the deferred income taxes, net as of December 31, 2003 and 2002, are as follows (in thousands):

                     
2003 2002


Net operating loss and credit carryforwards
  $ 478,118     $ 109,500  
Taxes related to risk management activities and SFAS 133
    77,905       103,604  
Other differences
    78,776       197,609  
Valuation allowance
    (19,335 )     (26,665 )
     
     
 
 
Deferred tax assets
    615,464       384,048  
     
     
 
Property differences
    (1,941,508 )     (1,321,445 )
Other differences
          (186,332 )
     
     
 
 
Deferred tax liabilities
    (1,941,508 )     (1,507,777 )
     
     
 
   
Net deferred income taxes
  $ (1,326,044 )   $ (1,123,729 )
     
     
 

      The net operating loss consists of federal and state carryforwards of $364.8 million which expire between 2004 and 2023. The federal and state net operating loss carryforwards available are subject to limitations on annual usage. The Company also has loss carryforwards in certain foreign subsidiaries, resulting in tax benefits

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of approximately $113.3 million, the majority of which expire by 2008. The Company has provided a valuation allowance to reduce deferred tax assets to the extent necessary to result in an amount that is more likely than not of being realized. Realization of the deferred tax assets and net operating loss carryforwards is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. The Company is under an Internal Revenue Service review for the years 1999 through 2002. The Company believes that the ultimate resolution will not have a material effect on its financial position.

      The Company’s foreign subsidiaries had no cumulative undistributed earnings at December 31, 2003.

 
19. Employee Benefit Plans
 
Retirement Savings Plan

      The Company has a defined contribution savings plan under Section 401(a) and 501(a) of the Internal Revenue Code. The plan provides for tax deferred salary deductions and after-tax employee contributions. Employees are immediately eligible upon hire. Contributions include employee salary deferral contributions and employer profit-sharing contributions of 4% of employees’ salaries up to $8,000 per year for 2003 and increasing to $8,200 per year for 2004, made entirely in cash. Employer profit-sharing contributions in 2003, 2002, and 2001 totaled $10.7 million, $11.6 million, and $6.9 million, respectively.

 
2000 Employee Stock Purchase Plan

      The Company adopted the 2000 Employee Stock Purchase Plan (“ESPP”) in May 2000. Eligible employees may in the aggregate purchase up to 12,000,000 shares of common stock at semi-annual intervals through periodic payroll deductions. Purchases are limited to a maximum value of $25,000 per calendar year based on the IRS code Section 423 limitation. Shares are purchased on May 31 and November 30 of each year until termination of the plan on May 31, 2010. Under the ESPP, 3,636,139 and 2,611,597 shares were issued at a weighted average fair value of $3.69 and $5.72 per share in 2003 and 2002, respectively. The purchase price is 85% of the lower of (i) the fair market value of the common stock on the participant’s entry date into the offering period, or (ii) the fair market value on the semi-annual purchase date. The purchase price discount is significant enough to cause the ESPP to be considered compensatory under SFAS No. 123. As a result, the ESPP is accounted for as stock-based compensation in accordance with SFAS No. 123. See Note 2 for information related to the Company’s stock-based compensation expense.

 
1996 Stock Incentive Plan

      The Company adopted the 1996 Stock Incentive Plan (“SIP”) in September 1996. The SIP succeeded the Company’s previously adopted stock option program. Prior to the adoption of SFAS No. 123 prospectively on January 1, 2003, (see Note 3), the Company accounted for the SIP under APB Opinion No. 25, “Accounting for Stock Issued to Employees” under which no compensation cost was recognized through December 31, 2002. See Note 2 for the effects the SIP would have on the Company’s financial statements if stock-based compensation was accounted for under SFAS No. 123 prior to January 1, 2003.

      For the year ended December 31, 2003, the Company had granted options to purchase 5,998,585 shares of common stock. Over the life of the SIP, options exercised have equaled 4,702,674, leaving 28,715,414 granted and not yet exercised. Under the SIP, the option exercise price generally equals the stock’s fair market value on date of grant. The SIP options generally vest ratably over four years and expire after 10 years.

      In connection with the merger with Encal, the Company adopted Encal’s existing stock option plan. All outstanding options under the Encal stock option plan were converted at the time of the merger into options to purchase Calpine stock. No new options may be granted under the Encal stock option plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Changes in options outstanding, granted, exercisable and canceled during the years 2003, 2002, and 2001, under the option plans of Calpine and Encal were as follows:

                             
Weighted
Available for Outstanding Average
Option or Number of Exercise
Award Options Price



Outstanding January 1, 2001
    3,465,023       30,672,061     $ 6.09  
     
     
     
 
 
Additional shares reserved
    2,837,150              
   
Granted
    (3,034,014 )     3,034,014       42.89  
   
Exercised
          (5,745,505 )     8.64  
   
Canceled
    270,006       (270,006 )     34.20  
   
Canceled options available for award(1)
    (682,216 )            
     
     
     
 
Outstanding December 31, 2001
    2,855,949       27,690,564     $ 9.32  
     
     
     
 
 
Additional shares reserved
    15,070,588                  
   
Granted
    (8,997,720 )     8,997,720       7.20  
   
Exercised
          (5,112,535 )     0.77  
   
Canceled
    1,470,802       (1,470,802 )     26.53  
   
Canceled options available for award(1)
    (237,705 )            
     
     
     
 
Outstanding December 31, 2002
    10,161,914       30,104,947     $ 9.30  
     
     
     
 
 
Granted
    (5,998,585 )     5,998,585       3.93  
 
Exercised
          (536,730 )     2.01  
 
Canceled
    1,725,221       (1,725,221 )     13.59  
 
Canceled options available for award(1)
    (72,470 )                
 
Awards issued
          (3,150 )     4.03  
     
     
     
 
Outstanding December 31, 2003
    5,816,080       33,838,431     $ 8.25  
     
     
     
 
Options exercisable:
                       
              18,642,381       3.81  
              19,418,489       7.14  
              22,953,781       8.02  


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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following tables summarizes information concerning outstanding and exercisable options at December 31, 2003:

                                         
Weighted
Average Weighted Weighted
Number of Remaining Average Number of Average
Options Contractual Exercise Options Exercise
Range of Exercise Prices Outstanding Life in Years Price Exercisable Price






$ 0.570 – $ 1.070
    5,043,246       1.46     $ 0.783       5,043,246     $ 0.783  
$ 1.105 – $ 2.250
    3,954,946       4.01       2.136       3,954,946       2.136  
$ 2.345 – $ 3.860
    3,777,939       5.02       3.746       3,768,439       3.748  
$ 3.960 – $ 3.980
    5,466,259       9.02       3.980       10,000       3.960  
$ 4.010 – $ 5.240
    3,256,157       8.37       5.162       1,029,516       5.000  
$ 5.250 – $ 7.640
    4,098,249       7.03       7.557       2,444,893       7.515  
$ 7.750 – $13.850
    3,757,882       5.84       10.598       3,348,139       10.207  
$13.917 – $48.150
    4,319,587       5.97       31.172       3,215,995       28.792  
$48.188 – $56.920
    162,216       7.22       51.317       136,657       51.267  
$56.990 – $56.990
    1,950       7.33       56.990       1,950       56.990  
     
                     
         
$ 0.570 – $56.990
    33,838,431       5.81     $ 8.245       22,953,781     $ 8.015  
     
                     
         
 
20. Stockholders’ Equity
 
Common Stock

      Increase in Authorized Shares — On July 26, 2001, the Company filed amended certificates with the Delaware Secretary of State to increase the number of authorized shares of common stock to 1,000,000,000 from 500,000,000.

      Equity Offering — On April 30, 2002, Calpine completed a registered offering of 66,000,000 shares of common stock at $11.50 per share. The proceeds from this offering, after underwriting fees, were $734.3 million.

 
Preferred Stock and Preferred Share Purchase Rights

      On June 5, 1997, Calpine adopted a stockholders’ rights plan to strengthen Calpine’s ability to protect Calpine’s stockholders. The plan was amended on September 19, 2001. The rights plan is designed to protect against abusive or coercive takeover tactics that are not in the best interests of Calpine or its stockholders. To implement the rights plan, Calpine declared a dividend of one preferred share purchase right for each outstanding share of Calpine’s common stock held on record as of June 18, 1997, and directed the issuance of one preferred share purchase right with respect to each share of Calpine’s common stock that shall become outstanding thereafter until the rights become exercisable or they expire as described below. On December 31, 2003, there were 415,010,125 rights outstanding. Each right initially represents a contingent right to purchase, under certain circumstances, one one-thousandth of a share, called a “unit,” of Calpine’s Series A Participating Preferred Stock, par value $.001 per share, at a price of $140.00 per unit, subject to adjustment. The rights become exercisable and trade independently from Calpine’s common stock upon the public announcement of the acquisition by a person or group of 15% or more of Calpine’s common stock, or ten days after commencement of a tender or exchange offer that would result in the acquisition of 15% or more of Calpine’s common stock. Each unit purchased upon exercise of the rights will be entitled to a dividend equal to any dividend declared per share of common stock and will have one vote, voting together with the common

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stock. In the event of Calpine’s liquidation, each share of the participating preferred stock will be entitled to any payment made per share of common stock.

      If Calpine is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of Calpine’s common stock, each right will entitle its holder to purchase at the right’s exercise price a number of the acquiring company’s shares of common stock having a market value of twice the right’s exercise price. In addition, if a person or group acquires 15% or more of Calpine’s common stock, each right will entitle its holder (other than the acquiring person or group) to purchase, at the right’s exercise price, a number of fractional shares of Calpine’s participating preferred stock or shares of Calpine’s common stock having a market value of twice the right’s exercise price.

      The rights remain exercisable for up to 90 days following a triggering event (such as a person acquiring 15% or more of the Company’s common Stock). The rights expire on June 18, 2007, unless redeemed earlier by Calpine. Calpine can redeem the rights at a price of $.01 per right at any time before the rights become exercisable, and thereafter only in limited circumstances.

 
Comprehensive Income (Loss)

      Comprehensive income is the total of net income and all other non-owner changes in equity. Comprehensive income includes the Company’s net income, unrealized gains and losses from derivative instruments that qualify as cash flow hedges and the effects of foreign currency translation adjustments. The Company reports Accumulated Other Comprehensive Income (AOCI) in its Consolidated Balance Sheet. The tables below detail the changes during 2003, 2002 and 2001 in the Company’s AOCI balance and the components of the Company’s comprehensive income (in thousands):

                                     
Total
Accumulated
Other
Foreign Comprehensive Comprehensive
Cash Flow Currency Income Income
Hedges(1) Translation (Loss) (Loss)




Accumulated other comprehensive loss at January 1, 2001
  $     $ (25,363 )   $ (25,363 )        
     
     
     
         
Net income
                          $ 623,492  
 
Cash flow hedges:
                               
   
Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment
  $ (171,400 )                        
   
Reclassification adjustment for gain included in net income
    (126,009 )                        
   
Income tax benefit
    116,590                          
     
                         
      (180,819 )             (180,819 )     (180,819 )
 
Foreign currency translation loss
            (34,698 )     (34,698 )     (34,698 )
     
     
     
     
 
Total comprehensive income
                          $ 407,975  
                             
 
Accumulated other comprehensive loss at December 31, 2001
  $ (180,819 )   $ (60,061 )   $ (240,880 )        
     
     
     
         

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                                     
Total
Accumulated
Other
Foreign Comprehensive Comprehensive
Cash Flow Currency Income Income
Hedges(1) Translation (Loss) (Loss)




Net income
                          $ 118,618  
 
Cash flow hedges:
                               
   
Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment
    96,905                          
   
Reclassification adjustment for gain included in net income
    (169,205 )                        
   
Income tax benefit
    28,705                          
     
                         
      (43,595 )             (43,595 )     (43,595 )
 
Foreign currency translation gain
            47,018       47,018       47,018  
     
     
     
     
 
Total comprehensive income
                          $ 122,041  
                             
 
Accumulated other comprehensive loss at December 31, 2002
  $ (224,414 )   $ (13,043 )   $ (237,457 )        
     
     
     
         
Net income
                          $ 282,022  
 
Cash flow hedges:
                               
   
Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment
    112,481                          
   
Reclassification adjustment for loss included in net income
    55,620                          
   
Income tax expense
    (74,106 )                        
     
                         
      93,995               93,995       93,995  
 
Foreign currency translation gain
            200,056       200,056       200,056  
     
     
     
     
 
Total comprehensive income
                          $ 576,073  
                             
 
Accumulated other comprehensive gain (loss) at December 31, 2003
  $ (130,419 )   $ 187,013     $ 56,594          
     
     
     
         


(1)  Includes accumulated other comprehensive income (loss) from cash flow hedges held by unconsolidated investees. At December 31, 2003, 2002 and 2001, these amounts were $6,911, $12,018 and $(1,984) respectively.
 
21. Customers

      In 2003 and 2002, the California Department of Water Resources (“DWR”) was a significant customer (accounting for more than 10% of the Company’s annual consolidated revenues). In 2001 PG&E and Enron Corp. (“Enron”), both of which remain in bankruptcy as of March 12, 2004, were significant customers. Significant customers relate exclusively to the Electric Generation and Marketing segment, with the exception of $33.3 million from Enron, which was derived from Oil and Gas Production and Marketing in 2001.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Revenues earned from the significant customers for the years ended December 31, 2003, 2002, and 2001, were as follows (in thousands):

                         
2003 2002 2001



Revenues:
                       
DWR
  $ 1,219,656     $ 754,191     $ *  
PG&E(1)
    *       *       723,062  
Enron
    *       *       1,671,737  

      Receivables due from the significant customers at December 31, 2003 and 2002, were as follows (in thousands):

                 
2003 2002


Receivables:
               
DWR
  $ 97,777     $ 78,842  


* Customer not significant in respective year.
 
(1)  See Note 8 for a discussion of the December 2003 sale of the PG&E notes receivable.

      The Company’s customer and supplier base is concentrated within the energy industry. See below for a discussion of the declaration of bankruptcy by PG&E. Additionally, the Company has exposure to trends within the energy industry, including declines in the creditworthiness of its marketing counterparties. Currently, multiple companies within the energy industry are in bankruptcy or have below investment grade credit ratings. The Company has post-petition exposure to three such counterparties, NRG Power Marketing, Inc. (“NRG Power Marketing”), PG&E Energy Trading (“PGET”) and Mirant Americas Energy Marketing, L.P. (“Mirant”), which filed for bankruptcy. The Company believes that its credit exposure to other companies in the energy industry is not significant either by individual company or in the aggregate. The table below shows our post-petition exposure to these counterparties at December 31, 2003 (in thousands):

                                         
Net
Derivative Net Accounts Letters of Credit,
Assets and Receivable and Margin or Other
Liabilities Accounts Payable Reserve Offsets Net Exposure





NRG Power Marketing
  $     $ 5,349     $     $  —     $ 5,349  
PGET
  $     $  —     $     $ (402 )(1)   $ (402 )
Mirant
  $ 3,433     $ 1,688     $ (451 )   $ (500 )(1)   $ 4,170  


(1)  Margin deposit held by the Company on its balance sheet classified as other current liabilities.

      On May 14, 2003, NRG Energy, Inc. (“NRG”) and several affiliates filed chapter 11 bankruptcy petitions in the United States Bankruptcy Court for the Southern District of New York. The Company filed proofs of claim in the NRG bankruptcy for certain contingent, unliquidated amounts, and pre-petition delivery of electric energy by the Company to NRG for April and the first half of May 2003. On December 5, 2003, NRG’s plan of reorganization became effective. On December 29, 2003, the Company collected pre-petition amounts of $7.8 million. At December 31, 2003, the Company had approximately $5.3 million in net post-petition exposure; however, the receivables balance is current.

      The Company had an exposure of $1.3 million to PGET, one of PG&E’s affiliates, at December 31, 2003. PGET filed for bankruptcy on July 8, 2003. PGET’s bankruptcy triggered a contract early termination event and Calpine kept the margin deposit it held of $1.7 million that had been posted by PGET. The bankruptcy court approved the termination event.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      On July 14, 2003, Mirant Americas Energy Marketing, L.P. (“Mirant”) and several affiliates filed chapter 11 bankruptcy petitions in the United States Bankruptcy Court for the Northern District of Texas. Pursuant to an order entered by the bankruptcy court on July 15, 2003, Mirant has timely made all payments under the Master Power Purchase and Sale Agreement between the parties (the “Master Agreement”), on both pre- and post-petition obligations. The Company has also executed a post-petition assurance agreement (the “Assurance Agreement”) with Mirant, covering continued performance of Mirant’s post-petition obligations on its contracts with the Company. Mirant’s motion for approval of the Assurance Agreement and the assumption of the Master Agreement was granted by the bankruptcy court on August 27, 2003; therefore, Mirant is required to continue to timely pay all post-petition obligations under the Master Agreement. Additionally, the post-petition assurance agreement provides certain other protections to the Company. The Company’s current post-petition exposure to Mirant as of December 31, 2003, is $4.2 million, and the Company has no pre-petition exposure to Mirant.

      Enron and a number of its subsidiaries and affiliates (including Enron North America Corp. (“ENA”) and Enron Power Marketing, Inc. (“EPMI”)) (collectively “Enron” or the “Enron Bankrupt Entities”) filed for Chapter 11 bankruptcy protection on December 2, 2001. At the time of the filing, CES was a party to various open energy derivatives, swaps, and forward power and gas transactions stemming from agreements with ENA and EPMI. On November 14, 2001, CES, ENA, and EPMI entered into a Master Netting Agreement, which granted the parties a contractual right to setoff amounts owed between them pursuant to the above agreements. The above agreements were terminated by CES on December 10, 2001. The Master Netting Agreement however remained in place. In October 2002 the Company and various affiliates filed proofs of claim against the Enron Bankrupt Entities.

      Calpine and Enron reached a final settlement agreement with regard to the Company’s terminated trading positions with Enron. The agreement was approved by the Unsecured Creditors’ committee on July 24, 2003, and by the Enron Bankruptcy Court on August 7, 2003. Under the terms of the settlement agreement, CES made five monthly installment payments of $19.4 million beginning August 22, 2003, and ending December 22, 2003. The aggregate total of the payments to Enron was $97.0 million. The settlement is now final.

      In connection with this settlement, the Company recorded other revenue of $67.3 million related to settlement of net liabilities associated with terminated derivative positions and receivables and payables with the Enron Bankrupt Entities. Prior to reaching final settlement, the Company had recorded a net liability to the Enron Bankrupt Entities relating to these transactions. The ultimate obligation to the Enron Bankrupt Entities based upon the terms of the final negotiated settlement agreement was less than the net liability the Company had previously recorded. The reduction to the previously recorded net liability was the result of giving economic recognition in the settlement to value associated with: 1) commodity contracts that were not given accounting recognition (i.e. in-the-money commodity contracts accounted for as normal purchases and sales), 2) forgiveness of liabilities due to differences in discounting assumptions, and 3) claims recoveries. Because of the character of the transactions giving rise to the Enron liability, the Company classified the settlement as other revenue.

      A significant portion of the liability to the Enron Bankrupt Entities related to commodity derivatives that had been designated as hedges of price risk associated with the Company’s natural gas consumption, and to a lesser degree, its electric power generation. Under the hedge accounting rules, losses associated with designated hedges are recorded in a company’s balance sheet and recognized into earnings when the transactions being hedged occur even if the hedge instruments are terminated prior to the occurrence of the hedged transactions. As of December 31, 2003, the Company has reclassified losses of approximately $186.3 million into income related to 2003 transactions hedged by Enron derivatives. Most of these losses were recorded as fuel expense consistent with the Company’s policy for classifying gains and losses on designated fuel hedges.

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California Department of Water Resources

      In 2001 California adopted legislation permitting it to issue long-term revenue bonds to fund wholesale purchases of power by the DWR. The bonds will be repaid with the proceeds of payments by retail power customers over time. CES and DWR entered into four long-term supply contracts during 2001. The Company has recorded deferred revenue in connection with one of the long-term power supply contracts (Contract 3). All of the Company’s accounts receivables from DWR are current, with the exception of approximately $1.0 million which the Company is working to resolve with the customer.

      In early 2002, the California Public Utilities Commission (“CPUC”) and the California Electricity Oversight Board (“EOB”) filed complaints under Section 206 of the Federal Power Act with the Federal Energy Regulatory Commission (“FERC”) alleging that the prices and terms of the long-term contracts with DWR were unjust and unreasonable and contrary to the public interest (the “206 Complaint”). The contracts entered into by CES and DWR were subject to the 206 Complaint.

      On April 22, 2002, the Company announced that it had renegotiated CES’s long-term power contracts with DWR and settled the 206 Complaint. The Office of the Governor, the CPUC, the EOB and the Attorney General for the State of California all endorsed the renegotiated contracts and dropped all pending claims against the Company and its affiliates, including any efforts by the CPUC and the EOB to seek refunds from the Company and its affiliates through the FERC California Refund Proceedings. In connection with the renegotiation, the Company agreed to pay $6 million over three years to the Attorney General to resolve any and all possible claims.

 
PG&E

      The Company’s northern California Qualifying Facility (“QF”) subsidiaries sell power to PG&E under the terms of long-term contracts at eleven facilities. On April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. PG&E is the regulated subsidiary of PG&E Corporation, and the information on PG&E disclosed herein excludes PG&E Corporation’s non-regulated subsidiary activity. The Company has transactions with certain of the non-regulated subsidiaries, which have not been affected by PG&E’s bankruptcy. On July 12, 2001, the U.S. Bankruptcy Court for the Northern District of California approved the agreement the Company had entered into with PG&E to modify and assume all of Calpine’s QF contracts with PG&E. Under the terms of the agreement, the Company will continue to receive its contractual capacity payments plus a five-year fixed energy price component that averages 5.37 cents per kilowatt-hour in lieu of the short run avoided cost. In addition, all past due receivables under the QF contracts were elevated to administrative priority status to be paid to the Company, with interest, upon the effective date of a confirmed plan of reorganization. On September 20, 2001, PG&E filed its proposed plan of reorganization with the bankruptcy court.

      As of April 6, 2001, the date of PG&E’s bankruptcy filing, the Company had recorded $265.6 million in accounts receivable with PG&E under the QF contracts, plus $68.7 million in notes receivable not yet due and payable. PG&E has paid currently for power delivered after April 6, 2001.

      In December 2001 the bankruptcy court approved an agreement between Calpine and PG&E providing that PG&E repay the $265.6 million in past due pre-petition receivables plus accrued interest ($10.3 million through December 31, 2001) thereon beginning on December 31, 2001, and with monthly payments thereafter over the next 11 months. Shortly following receipt of this bankruptcy court approval and the first payments from PG&E on December 31, 2001, the Company sold the remaining PG&E receivables to a third party at a $9.0 million discount. The cash for the sale of the receivables was collected in January 2002.

      CPUC Proceeding Regarding QF Contract Pricing for Past Periods. The Company’s QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility “avoided cost” to be used to set energy payments for certain QF contracts by determining the short run avoided cost (“SRAC”) energy

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price formula. In mid-2000 the Company’s QF facilities elected the option set forth in Section 390 of the California Public Utility Code, which provides QFs the right to elect to receive energy payments based on the California Power Exchange (“PX”) market clearing price instead of the price determined by SRAC. Having elected such option, the Company was paid based upon the PX zonal day ahead clearing price (“PX Price”) from summer 2000 until January 19, 2001, when the PX ceased operating a day ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC at one point issued a proposed decision to the effect that the PX Price was the appropriate price for energy payments under the California Public Utility Code but tabled it, and a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. The Company believes that the PX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings.

      The Company had a combined accounts receivable balance of $24.2 million as of December 31, 2003, from the California Independent System Operator Corporation (“CAISO”) and Automated Power Exchange, Inc. (“APX”). Of this balance, $9.5 million relates to past due balances prior to the PG&E bankruptcy filing. The Company expects that a portion of these past due receivables will be offset against refund obligations under FERC’s California Refund Proceedings (see Note 26) and the Company has provided a partial reserve for these past due receivables. CAISO’s ability to pay the Company is directly impacted by PG&E’s ability to pay CAISO. APX’s ability to pay the Company is directly impacted by PG&E’s ability to pay the PX, which in turn would pay APX for energy delivered by the Company through APX. As noted above, the PX ceased operating in January 2001. See Note 26 for an update on the FERC investigation into the western markets.

 
Credit Evaluations

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

22.     Derivative Instruments

 
Commodity Derivative Instruments

      As an independent power producer primarily focused on generation of electricity using gas-fired turbines, the Company’s natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, the Company enters into derivative commodity instruments. The Company enters into commodity instruments to convert floating or indexed electricity and gas (and to a lesser extent oil and refined product) prices to fixed prices in order to lessen its vulnerability to reductions in electric prices for the electricity it generates, to reductions in gas prices for the gas it produces, and to increases in gas prices for the fuel it consumes in its power plants. The Company seeks to “self-hedge” its gas consumption exposure to an extent with its own gas production position. Any hedging, balancing, or optimization activities that the Company engages in are directly related to the Company’s asset-based business model of owning and operating gas-fired electric power plants and are designed to protect the Company’s “spark spread” (the difference between the Company’s fuel cost and the revenue it receives for its electric generation). The Company hedges exposures that arise from the ownership and operation of power plants and related sales of

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electricity and purchases of natural gas, and the Company utilizes derivatives to optimize the returns the Company is able to achieve from these assets for the Company’s shareholders. From time to time the Company has entered into contracts considered energy trading contracts under EITF Issue No. 02-3. However, the Company’s traders have low capital at risk and value at risk limits for energy trading, and its risk management policy limits, at any given time, its net sales of power to its generation capacity and limits its net purchases of gas to its fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133.

      The Company also routinely enters into physical commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives but are generally eligible for the normal purchases and sales exception. Some of those contracts that are not deemed normal purchases and sales can be designated as hedges of the underlying consumption of gas or production of electricity.

      In 2001 FASB cleared SFAS No. 133 Implementation Issue No. C16 “Applying the Normal Purchases and Normal Sales Exception to Contracts That Combine a Forward Contract and a Purchased Option Contract (“C16”). The guidance in C16 applies to fuel supply contracts that require delivery of a contractual minimum quantity of fuel at a fixed price and have an option that permits the holder to take specified additional amounts of fuel at the same fixed price at various times. Under C16, the volumetric optionality provided by such contracts is considered a purchased option that disqualifies the entire derivative fuel supply contract from being eligible to qualify for the normal purchases and normal sales exception in SFAS No. 133. On April 1, 2002, the Company adopted C16. At June 30, 2002, the Company had no fuel supply contracts to which C16 applies. However, one of the Company’s equity method investees has fuel supply contracts subject to C16. The equity method investee also adopted C16 in April 2002 at which time the fuel contracts qualified for and were designated as highly effective cash flow hedges of the equity method investee’s forecasted purchase of gas. Accordingly, the Company has recorded $7.8 million net of tax as a cumulative effect of change in accounting principle to other comprehensive income for its share of the equity method investee’s other comprehensive income from this accounting change.

 
Interest Rate and Currency Derivative Instruments

      The Company also enters into various interest rate swap agreements to hedge against changes in floating interest rates on certain of its project financing facilities. The interest rate swap agreements effectively convert floating rates into fixed rates so that the Company can predict with greater assurance what its future interest costs will be and protect itself against increases in floating rates.

      In conjunction with its capital markets activities, the Company enters into various forward interest rate agreements to hedge against interest rate fluctuations that may occur after the Company has decided to issue long-term fixed rate debt but before the debt is actually issued. The forward interest rate agreements effectively prevent the interest rates on anticipated future long-term debt from increasing beyond a certain level, allowing the Company to predict with greater assurance what its future interest costs on fixed rate long-term debt will be.

      The Company enters into various foreign currency swap agreements to hedge against changes in exchange rates on certain of its senior notes denominated in currencies other than the U.S. dollar. The foreign currency swaps effectively convert floating exchange rates into fixed exchange rates so that the Company can predict with greater assurance what its U.S. dollar cost will be for purchasing foreign currencies to satisfy the interest and principal payments on these senior notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 
Summary of Derivative Values

      The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at December 31, 2003, for the Company’s derivative instruments:

                             
Commodity
Interest Rate Derivative Total
Derivative Instruments Derivative
Instruments Net Instruments



Current derivative assets
  $ 5,908     $ 491,059     $ 496,967  
Long-term derivative assets
          673,979       673,979  
     
     
     
 
 
Total assets
  $ 5,908     $ 1,165,038     $ 1,170,946  
     
     
     
 
Current derivative liabilities
  $ 12,446     $ 444,242     $ 456,688  
Long-term derivative liabilities
    47,833       644,255       692,088  
     
     
     
 
 
Total liabilities
  $ 60,279     $ 1,088,497     $ 1,148,776  
     
     
     
 
   
Net derivative assets (liabilities)
  $ (54,371 )   $ 76,541     $ 22,170  
     
     
     
 

      Of the Company’s net derivative assets, $434.6 million and $80.2 million are net derivative assets of PCF and CNEM, respectively, each of which is an entity with its existence separate from the Company and other subsidiaries of the Company, but both of which are consolidated by the Company pursuant to FIN 46.

      At any point in time, it is highly unlikely that total net derivative assets and liabilities will equal accumulated OCI, net of tax from derivatives, for three primary reasons:

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Below is a reconciliation of the Company’s net derivative assets to its accumulated other comprehensive loss, net of tax from derivative instruments at December 31, 2003 (in thousands):

         
Net derivative assets
  $ 22,170  
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness
    (119,168 )
Cash flow hedges terminated prior to maturity
    (106,023 )
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges
    71,189  
Accumulated OCI from unconsolidated investees
    1,413  
     
 
Accumulated other comprehensive loss from derivative instruments, net of tax(1)
  $ (130,419 )
     
 


(1)  Amount represents one portion of the Company’s total accumulated OCI balance. See Note 20 for further information.

      The asset and liability balances for the Company’s commodity derivative instruments represent the net totals after offsetting certain assets against certain liabilities under the criteria of FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB Opinion No. 10 and FASB Statement No. 105)” (“FIN 39”). For a given contract, FIN 39 will allow the offsetting of assets against liabilities so long as four criteria are met: (1) each of the two parties under contract owes the other determinable amounts; (2) the party reporting under the offset method has the right to set off the amount it owes against the amount owed to it by the other party; (3) the party reporting under the offset method intends to exercise its right to set off; and; (4) the right of set-off is enforceable by law. The table below reflects both the amounts (in thousands) recorded as assets and liabilities by the Company and the amounts that would have been recorded had the Company’s commodity derivative instrument contracts not qualified for offsetting as of December 31, 2003.

                     
December 31, 2003

Gross Net


Current derivative assets
  $ 863,861     $ 491,059  
Long-term derivative assets
    1,176,423       673,979  
     
     
 
 
Total derivative assets
  $ 2,040,284     $ 1,165,038  
     
     
 
Current derivative liabilities
  $ 817,044     $ 444,242  
Long-term derivative liabilities
    1,146,699       644,255  
     
     
 
 
Total derivative liabilities
  $ 1,963,743     $ 1,088,497  
     
     
 
   
Net commodity derivative assets
  $ 76,541     $ 76,541  
     
     
 

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The tables below reflect the impact of the Company’s derivative instruments on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the changes in market value of derivatives not designated as hedges of cash flows, for the years ended December 31, 2003, 2002 and 2001, respectively (in thousands):

                                                                           
2003 2002 2001



Hedge Undesignated Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total









Natural gas derivatives(1)
  $ 3,153     $ 7,768     $ 10,921     $ 2,147     $ (14,792 )   $ (12,645 )   $ (5,788 )   $ 30,113     $ 24,325  
Power derivatives(1)
    (5,001 )     (56,693 )     (61,694 )     (4,934 )     12,974       8,040       1,866       96,402       98,268  
Interest rate derivatives(2)
    (974 )           (974 )     (810 )           (810 )     (1,330 )     (5,785 )     (7,115 )
     
     
     
     
     
     
     
     
     
 
 
Total
  $ (2,822 )   $ (48,925 )   $ (51,747 )   $ (3,597 )   $ (1,818 )   $ (5,415 )   $ (5,252 )   $ 120,730     $ 115,478  
     
     
     
     
     
     
     
     
     
 


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

      The table below reflects the contribution of the Company’s cash flow hedge activity to pre-tax earnings based on the reclassification adjustment from OCI to earnings for the years ended December 31, 2003, 2002 and 2001, respectively (in thousands):

                           
2003 2002 2001



Natural gas and crude oil derivatives
  $ 40,752     $ (119,419 )   $ (30,745 )
Power derivatives
    (79,233 )     304,073       163,228  
Interest rate derivatives
    (27,727 )     (10,993 )     (6,474 )
Foreign currency derivatives
    10,588       (4,456 )      
     
     
     
 
 
Total derivatives
  $ (55,620 )   $ 169,205     $ 126,009  
     
     
     
 

      As of December 31, 2003 the maximum length of time over which the Company was hedging its exposure to the variability in future cash flows for forecasted transactions was 8 and 13 years, for commodity and interest rate derivative instruments, respectively. The Company estimates that pre-tax losses of $42.9 million would be reclassified from accumulated OCI into earnings during the twelve months ended December 31, 2004, as the hedged transactions affect earnings assuming constant gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified will likely vary based on the probability that gas and power prices as well as interest rates and exchange rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next twelve months.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The table below presents (in thousands) the pre-tax gains (losses) currently held in OCI that will be recognized annually into earnings, assuming constant gas and power prices, interest rates, and exchange rates over time.

                                                           
2009 &
2004 2005 2006 2007 2008 After Total







Gas OCI
  $ 24,628     $ (27,989 )   $ 14,036     $ 479     $ 426     $ 1,045     $ 12,625  
Power OCI
    (46,119 )     (39,554 )     (31,060 )     (1,255 )     354       705       (116,929 )
Interest rate OCI
    (19,578 )     (15,675 )     (10,865 )     (7,470 )     (5,308 )     (31,356 )     (90,252 )
Foreign currency OCI
    (1,869 )     (1,869 )     (1,869 )     (1,479 )     32             (7,054 )
     
     
     
     
     
     
     
 
 
Total pre-tax OCI
  $ (42,938 )   $ (85,087 )   $ (29,758 )   $ (9,725 )   $ (4,496 )   $ (29,606 )   $ (201,610 )
     
     
     
     
     
     
     
 
 
23. Earnings per Share

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

                                                                           
For the Years Ended December 31,

2003 2002 2001



Net Net Net
Income Shares EPS Income Shares EPS Income Shares EPS









Basic earnings per common share:
                                                                       
 
Income before discontinued operations and cumulative effect of a change in accounting principle
  $ 109,753       390,772     $ 0.28     $ 53,690       354,822     $ 0.15     $ 582,966       303,522     $ 1.92  
 
Discontinued operations, net of tax
    (8,674 )             (0.02 )     64,928               0.18       39,490               0.13  
 
Cumulative effect of a change in accounting principle
    180,943               0.46                           1,036                
     
             
     
             
     
             
 
 
Net income
  $ 282,022       390,772     $ 0.72     $ 118,618       354,822     $ 0.33     $ 623,492       303,522     $ 2.05  
     
             
     
             
     
             
 
Diluted earnings per common share:
                                                                       
 
Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle
  $ 109,753       396,219     $ 0.28     $ 53,690       362,533     $ 0.15     $ 582,966       317,919     $ 1.83  
 
Dilutive effect of certain convertible securities
                                        46,632       54,337       (0.14 )
     
     
     
     
     
     
     
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                                                                         
For the Years Ended December 31,

2003 2002 2001



Net Net Net
Income Shares EPS Income Shares EPS Income Shares EPS









Income before discontinued operations and cumulative effect of a change in accounting principle
    109,753       396,219       0.28       53,690       362,533       0.15       629,598       372,256       1.69  
Discontinued operations, net of tax
    (8,674 )             (0.02 )     64,928               0.18       39,490               0.11  
Cumulative effect of a change in accounting principle
    180,943               0.45                           1,036                
     
     
     
     
     
     
     
     
     
 
Net income, as adjusted
  $ 282,022       396,219     $ 0.71     $ 118,618       362,533     $ 0.33     $ 670,124       372,256     $ 1.80  
     
     
     
     
     
     
     
     
     
 

      Potentially convertible securities and unexercised employee stock options to purchase 127,057,325, 136,744,307, and 13,293,586, shares of the Company’s common stock were not included in the computation of diluted shares outstanding during the years ended December 31, 2003, 2002, and 2001, respectively, because such inclusion would be anti-dilutive.

 
24. Commitments and Contingencies

      Turbines. On February 11, 2003, the Company announced a significant restructuring of its turbine agreements (see Note 4), which enables the Company to cancel up to 131 steam and gas turbines. The Company recorded a pre-tax charge of $207.4 million in the quarter ending December 31, 2002, in connection with fees paid to vendors to restructure these contracts. To date 60 of these turbines have been cancelled, leaving the disposition of 71 turbines still to be determined.

      In July 2003 the Company completed a restructuring of its existing agreements with Siemens Westinghouse Power Corporation for 20 gas and 2 steam turbines. The new agreement provides for later payment dates, which are in line with the Company’s construction program. The table below sets forth future turbine payments for construction and development projects, as well as for unassigned turbines. It includes previously delivered turbines, payments and delivery year for the remaining 5 turbines to be delivered as well as payment required for the potential cancellation costs of the remaining 71 gas and steam turbines. The table does not include payments that would result if the Company were to release for manufacturing any of these remaining 71 turbines.

                 
Units to
Year Total Be Delivered



(In thousands)
2004
  $ 100,186       5  
2005
    18,641        
2006
    2,516        
     
     
 
Total
  $ 121,343       5  
     
     
 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Power Plant Operating Leases — The Company has entered into long-term operating leases for power generating facilities, expiring through 2049. Many of the lease agreements provide for renewal options at fair value, and some of the agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance agreements. In accordance with SFAS No. 13 and SFAS No. 98, “Accounting for Leases” the Company’s operating leases are not reflected on our balance sheet. Future minimum lease payments under these leases are as follows (in thousands):

                                                                   
Initial
Year 2004 2005 2006 2007 2008 Thereafter Total








Watsonville
    1995     $ 2,905     $ 2,905     $ 2,905     $ 2,905     $ 2,905     $ 4,065     $ 18,590  
King City
    1996       13,746       10,344       9,700       9,100       9,050       87,100       139,040  
Greenleaf
    1998       8,858       8,723       8,650       8,650       7,495       38,133       80,509  
Geysers
    1999       55,415       55,890       47,991       47,150       42,886       140,533       389,865  
KIAC
    2000       24,251       24,077       23,875       23,845       24,473       264,619       385,140  
Rumford/ Tiverton
    2000       35,365       44,942       45,000       45,000       45,000       608,292       823,599  
South Point
    2001       31,627       9,620       9,620       9,620       9,620       316,810       386,917  
RockGen
    2001       26,565       27,031       26,088       27,478       28,732       198,612       334,506  
             
     
     
     
     
     
     
 
 
Total
          $ 198,732     $ 183,532     $ 173,829     $ 173,748     $ 170,161     $ 1,658,164     $ 2,558,166  
             
     
     
     
     
     
     
 

      In 2003, 2002, and 2001 rent expense for power plant operating leases amounted to $112.1 million, $111.0 million, and $99.5 million, respectively. Calpine guarantees $1.7 billion of the total future minimum lease payments of its consolidated subsidiaries.

      The King City operating lease commitment is supported by collateral debt securities that mature serially in amounts equal to a portion of the semi-annual lease payment. These debt securities are classified as held-to-maturity and are recorded at an amortized cost of $82.6 million at December 31, 2003.

      The Company has two tolling agreements with Acadia Energy Center, an equity method affiliate in which the Company has a 50% interest. The total future minimum lease payments for the tolling agreements are as follows (in thousands):

           
2004
  $ 63,967  
2005
    63,967  
2006
    63,967  
2007
    65,902  
2008
    67,836  
Thereafter
    915,788  
     
 
 
Total
  $ 1,241,427  
     
 

      Production Royalties and Leases — The Company is committed under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on CPI changes and are not material. Under the terms of most geothermal leases, prior to May 1999, when the Company consolidated the steam field and power plant operations in Lake and Sonoma Counties in northern California (The Geysers), royalties were based on steam and effluent revenue. Following the consolidation of operations, the royalties began to accrue as a percentage of electrical revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Production royalties for the years ended December 31, 2003, 2002, and 2001, were $24.9 million, $17.6 million, and $27.5 million, respectively.

      Office and Equipment Leases — The Company leases its corporate, regional and satellite offices as well as some of its office equipment under noncancellable operating leases expiring through 2013. Future minimum lease payments under these leases are as follows (in thousands):

           
2004
  $ 29,065  
2005
    27,173  
2006
    22,768  
2007
    20,395  
2008
    19,573  
Thereafter
    76,820  
     
 
 
Total
  $ 195,794  
     
 

      Lease payments are subject to adjustments for the Company’s pro rata portion of annual increases or decreases in building operating costs. In 2003, 2002, and 2001 rent expense for noncancellable operating leases amounted to $21.6 million, $25.8 million, and $16.2 million, respectively.

      Natural Gas Purchases — The Company enters into gas purchase contracts of various terms with third parties to supply gas to its gas-fired cogeneration projects.

      Gas Pipeline Transportation in Canada — To support production and marketing operations, Calpine has firm commitments in the ordinary course of business for gathering, processing and transmission services that require the Company to deliver certain minimum quantities of natural gas to third parties or pay the corresponding tariffs. The agreements expire at various times through 2015. Estimated payments to be made under these arrangements are $6.5 million, $6.6 million, $6.0 million, $6.0 million, $6.2 million and $48.6 million for each of the next five years and thereafter, respectively.

      Guarantees — As part of normal business, Calpine enters into various agreements providing, or otherwise arranges, financial or performance assurance to third parties on behalf of its subsidiaries. Such arrangements include guarantees, standby letters of credit and surety bonds. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes.

      Calpine routinely issues guarantees to third parties in connection with contractual arrangements entered into by Calpine’s direct and indirect wholly owned subsidiaries in the ordinary course of such subsidiaries’ respective business, including power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of Calpine’s fleet of power generating facilities and natural gas facilities. Under these guarantees, if the subsidiary in question were to fail to perform its obligations under the guaranteed contract, giving rise to a default and/or an amount owing by the subsidiary to the third party under the contract, Calpine could be called upon to pay such amount to the third party or, in some instances, to perform the subsidiary’s obligations under the contract. It is Calpine’s policy to attempt to negotiate specific limits or caps on Calpine’s overall liability under these types of guarantees; however, in some instances, Calpine’s liability is not limited by way of such a contractual liability cap.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      At December 31, 2003, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in thousands):

                                                           
Commitments Expiring 2004 2005 2006 2007 2008 Thereafter Total








Guarantee of subsidiary debt
  $ 27,194     $ 17,531     $ 15,128     $ 171,621     $ 2,099,553     $ 658,876     $ 2,989,903  
Standby letters of credit(1)
    320,580       75,756       10,666       3,401       400             410,803  
Surety bonds(2)
    34,273                               36,207       70,480  
Guarantee of subsidiary operating lease payments
    96,688       83,169       81,772       82,487       115,604       1,277,760       1,737,480  
     
     
     
     
     
     
     
 
 
Total
  $ 478,735     $ 176,456     $ 107,566     $ 257,509     $ 2,215,557     $ 1,972,843     $ 5,208,666  
     
     
     
     
     
     
     
 


(1)  The Standby letters of credit disclosed above include those disclosed in Notes 11 and 14.
 
(2)  The bonds that do not have expiration or cancellation dates are included in the Thereafter column.

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

                 
Balance at December 31,

2003 2002


Guarantee of subsidiary debt
  $ 2,989,903     $ 3,259,878  
Standby letters of credit
    410,803       685,606  
Surety bonds
    70,480       72,267  
     
     
 
    $ 3,471,186     $ 4,017,751  
     
     
 

      The Company has guaranteed the principal payment of $2,448.6 million and $2,656.8 million, as of December 31, 2003 and 2002, respectively, of Senior Notes for two wholly owned finance subsidiaries of Calpine, Calpine Canada Energy Finance ULC and Calpine Canada Energy Finance II ULC. As of December 31, 2003, the Company has guaranteed $291.6 million and $214.1 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant and $301.0 million and $214.1 million, respectively, as of December 31, 2002, for these power plants. As of December 31, 2003 and 2002, the Company has also guaranteed $35.6 million and $38.0 million, respectively, of other miscellaneous debt. All of the guaranteed debt is recorded on the Company’s Consolidated Balance Sheet.

      The King City operating lease commitment is supported by collateral debt securities that mature serially in amounts equal to a portion of the semi-annual lease payment. See “Financial Market Risks — Collateral Debt Securities” for more information.

      Calpine routinely arranges for the issuance of letters of credit and various forms of surety bonds to third parties in support of its subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of its partially owned subsidiaries up to the Company’s ownership percentage. The letters of credit outstanding under various credit facilities support CES risk management, and other operational and construction activities. Of the total letters of credit outstanding, $14.5 million and $106.1 million were issued to support CES risk management at December 31, 2003 and 2002, respectively. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, Calpine would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of 1 to 10 days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included in the Consolidated Balance Sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      At December 31, 2003, investee debt was $455.9 million. Based on the Company’s ownership share of each of the investments, the Company’s share would be approximately $145.0 million. However, all such debt is non-recourse to the Company.

      In the course of its business, Calpine and its subsidiaries have entered into various purchase and sale agreements relating to stock and asset acquisitions or dispositions. These purchase and sale agreements customarily provide for indemnification by each of the purchaser and the seller, and/or their respective parent, to the counter-party for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction. The Company has no reason to believe that it currently has any material liability relating to such routine indemnification obligations.

      Additionally, Calpine and its subsidiaries from time to time assume other indemnification obligations in conjunction with transactions other than purchase or sale transactions. These indemnification obligations generally have a discrete term and are intended to protect our counterparties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction, such as the costs associated with litigation that may result from the transaction. The Company has no reason to believe that it currently has any material liability relating to such routine indemnification obligations.

      Calpine has in a few limited circumstances directly or indirectly guaranteed the performance of obligations by unrelated third parties. These circumstances have arisen in situations in which a third party has contractual obligations with respect to the construction, operation or maintenance of a power generating facility or related equipment owned in whole or in part by Calpine. Generally, the third party’s obligations with respect to related equipment are guaranteed for the direct or indirect benefit of Calpine by the third party’s parent or other party. A financing party or investor in such facility or equipment may negotiate for Calpine also to guarantee the performance of such third party’s obligations as additional support for the third party’s obligations. For example, in conjunction with the financing of California peaker program, Calpine guaranteed for the benefit of the lenders certain warranty obligations of third party suppliers and contractors. Calpine has entered into few guarantees of unrelated third party’s obligations. Calpine has no reason to believe that it currently has any liability with respect to these guarantees.

      The Company believes that the likelihood that it would be required to perform or otherwise incur any significant losses associated with any of these guarantees is remote.

 
Litigation

      The Company is party to various litigation matters arising out of the normal course of business, the more significant of which are summarized below. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result, these matters may potentially be material to the Company’s consolidated financial statements.

      Securities Class Action Lawsuits. Since March 11, 2002, fourteen shareholder lawsuits have been filed against the Company and certain of its officers in the United States District Court, Northern District of California. The actions captioned Weisz v. Calpine Corp., et al., filed March 11, 2002, and Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002, are purported class actions on behalf of purchasers of Calpine stock between March 15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18, 2002, is a purported class action on behalf of purchasers of Calpine stock between February 6, 2001 and December 13, 2001. The eleven other actions, captioned Local 144 Nursing Home Pension Fund v.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Calpine Corp., Lukowski v. Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., Laborers Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp., and Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The complaints in these eleven actions are virtually identical — they are filed by three law firms, in conjunction with other law firms as co-counsel. All eleven lawsuits are purported class actions on behalf of purchasers of the Company’s securities between January 5, 2001 and December 13, 2001.

      The complaints in these fourteen actions allege that, during the purported class periods, certain Calpine executives issued false and misleading statements about the Company’s financial condition in violation of Sections 10(b) and 20(1) of the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek an unspecified amount of damages, in addition to other forms of relief.

      In addition, a fifteenth securities class action, Ser v. Calpine, et al., was filed on May 13, 2002. The underlying allegations in the Ser action are substantially the same as those in the above-referenced actions. However, the Ser action is brought on behalf of a purported class of purchasers of Calpine’s 8.5% Senior Notes Due February 15, 2011 (“2011 Notes”) and the alleged class period is October 15, 2001 through December 13, 2001. The Ser complaint alleges that, in violation of Sections 11 and 15 of the Securities Act of 1933, the Supplemental Prospectus for the 2011 Notes contained false and misleading statements regarding the Company’s financial condition. This action names the Company, certain of its officers and directors, and the underwriters of the 2011 Notes offering as defendants, and seeks an unspecified amount of damages, in addition to other forms of relief.

      All fifteen of these securities class action lawsuits were consolidated in the U.S. District Court for the Northern District Court of California. The plaintiffs filed a first amended complaint in October 2002. The amended complaint did not include the 1933 Act complaints raised in the bondholders’ complaint, and the number of defendants named was reduced. On January 16, 2003, before our response was due to this amended complaint, the plaintiffs filed a further second complaint. This second amended complaint added three additional Calpine executives and Arthur Andersen LLP as defendants. The second amended complaint set forth additional alleged violations of Section 10 of the Securities Exchange Act of 1934 relating to allegedly false and misleading statements made regarding Calpine’s role in the California energy crisis, the long term power contracts with the California Department of Water Resources, and Calpine’s dealings with Enron, and additional claims under Section 11 and Section 15 of the Securities Act of 1933 relating to statements regarding the causes of the California energy crisis. The Company filed a motion to dismiss this consolidated action in early April 2003.

      On August 29, 2003, the judge issued an order dismissing, with leave to amend, all of the allegations set forth in the second amended complaint except for a claim under Section 11 of the Securities Act relating to statements relating to the causes of the California energy crisis and the related increase in wholesale prices contained in the Supplemental Prospectuses for the 2011 Notes. The judge instructed plaintiffs to file a third amended complaint, which they did on October 17, 2003. The third amended complaint names Calpine and three executives as defendants and alleges the Section 11 claim that survived the judge’s August 29, 2003 order.

      On November 21, 2003, Calpine and the individual defendants moved to dismiss the third amended complaint on the grounds that plaintiff’s Section 11 claim was barred by the applicable one-year statute of limitations. On February 5, 2004, the judge denied our motion to dismiss but has asked the parties to be prepared to file summary judgment motions to address the statute of limitations issue. Our answer to the third amended complaint has been filed. The Company considers the lawsuit to be without merit and intends to continue to defend vigorously against these allegations.

      Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was filed on March 11, 2003, against Calpine, its

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

directors and certain investment banks in the California Superior Court, San Diego County. The underlying allegations in the Hawaii Structural Ironworkers Pension Fund action (“Hawaii action”) are substantially the same as the federal securities class actions described above. However, the Hawaii action is brought on behalf of a purported class of purchasers of the Company’s equity securities sold to public investors in its April 2002 equity offering. The Hawaii action alleges that the Registration Statement and Prospectus filed by Calpine which became effective on April 24, 2002, contained false and misleading statements regarding the Company’s financial condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933. The Hawaii action relies in part on the Company’s restatement of certain past financial results, announced on March 3, 2003, to support its allegations. The Hawaii action seeks an unspecified amount of damages, in addition to other forms of relief.

      The Company removed the Hawaii action to federal court in April 2003 and filed a motion to transfer the case for consolidation with the other securities class action lawsuits in the U.S. District Court Northern District Court of California in May 2003. The plaintiff sought to have the action remanded to state court, and on August 27, 2003, the U.S. District Court for the Southern District of California granted plaintiff’s motion to remand the action to state court. In early October 2003 plaintiff agreed to dismiss the claims it has against three of the outside directors.

      On November 5, 2003, Calpine, the individual defendants and the underwriter defendants filed motions to dismiss this complaint on numerous grounds. On February 6, 2004, the court issued a tentative ruling sustaining our motion to dismiss on the issue of the plaintiff’s standing. The court found that the plaintiff had not shown that it had purchased Calpine’ stock “traceable” to the April 2002 equity offering. The court overruled our motion to dismiss on all other grounds. The Company has requested oral argument on these other issues which oral argument is currently scheduled for March 2004. The Company considers this lawsuit to be without merit and intends to continue to defend vigorously against it.

      Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in the Calpine Corporation Retirement Savings Plan (the “401(k) Plan”) filed a class action lawsuit in the Northern District Court of California. The underlying allegations in this action (“Phelps action”) are substantially the same as those in the securities class actions described above. However, the Phelps action is brought on behalf of a purported class of participants in the 401(k) Plan. The Phelps action alleges that various filings and statements made by Calpine during the class period were materially false and misleading, and that the defendants failed to fulfill their fiduciary obligations as fiduciaries of the 401(k) Plan by allowing the 401(k) Plan to invest in Calpine common stock. The Phelps action seeks an unspecified amount of damages, in addition to other forms of relief. In May 2003 Lennette Poor-Herena, another participant in the 401(k) Plan, filed a substantially similar class action lawsuit as the Phelps action also in the Northern District of California. Plaintiffs’ counsel is the same in both of these actions, and they have agreed to consolidate these two cases and to coordinate them with the consolidated federal securities class actions described above. On January 20, 2004, plaintiff James Phelps filed a consolidated ERISA complaint naming the Company and numerous individual current and former Calpine Board members and employees as defendants. Calpine’s response to the amended complaint is due March 22, 2004. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.

      Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of the Company against its directors and one if its senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. and is pending in the California Superior Court, Santa Clara County. The Company is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about Calpine and stock sales by certain of the director defendants and the officer defendant. In December 2002 the court dismissed the complaint with respect to certain of the director defendants for lack of personal jurisdiction, though the plaintiff may appeal this ruling. In early February 2003 the plaintiff filed an amended complaint. In March 2003 the Company and the individual defendants filed motions to dismiss and motions to stay this proceeding in favor of the federal securities class actions described above. In July 2003 the Court

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granted the motions to stay this proceeding in favor of the consolidated federal securities class actions described above. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.

      Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a derivative suit in the United States District Court for the Northern District California on behalf of Calpine against its directors, captioned Gordon v. Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to dismiss the action against certain of the director defendants on the grounds of lack of personal jurisdiction, as well as to dismiss the complaint in total on other grounds. In February 2003 plaintiff agreed to stay these proceedings in favor of the consolidated federal securities class actions described above and to dismiss without prejudice certain director defendants. On March 4, 2003, the plaintiff filed papers with the court voluntarily agreeing to dismiss without prejudice the claims he had against three of the outside directors. The Company considers this lawsuit to be without merit and intends to continue to defend vigorously against it.

      Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, the Company sued Automated Credit Exchange (“ACE”) in the Superior Court of the State of California for the County of Alameda for negligence and breach of contract to recover reclaim trading credits, a form of emission reduction credits that should have been held in the Company’s account with U.S. Trust Company (“US Trust”). Calpine wrote off $17.7 million in December 2001 related to losses that it alleged were caused by ACE. Calpine and ACE entered into a Settlement Agreement on March 29, 2002, pursuant to which ACE made a payment to the Company of $7 million and transferred to the Company the rights to the emission reduction credits to be held by ACE. The Company recognized the $7 million as income in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. (“InterGen”) against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to the Company’s loss from ACE. InterGen’s complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. By a judgment entered on October 30, 2002, the Bankruptcy Court consolidated ACE and the other Sholtz controlled entities with the bankruptcy estate of EonXchange. Subsequently, the Trustee of EonXchange filed a separate motion to substantively consolidate Anne Sholtz into the bankruptcy estate of EonXchange. Although Anne Sholtz initially opposed such motion, she entered into a settlement agreement with the Trustee consenting to her being substantively consolidated into the bankruptcy proceeding. The Bankruptcy Court entered an order approving Anne Sholtz’s settlement agreement with the Trustee on April 3, 2002. On July 10, 2003, Howard Grobstein, the Trustee in the EonXchange bankruptcy, filed a complaint for avoidance against Calpine, seeking recovery of the $7 million (plus interest and costs) paid to Calpine in the March 29, 2002 Settlement Agreement. The complaint claims that the $7 million received by Calpine in the Settlement Agreement was transferred within 90 days of the filing of bankruptcy and therefore should be avoided and preserved for the benefit of the bankruptcy estate. On August 28, 2003, Calpine filed its answer denying that the $7 million is an avoidable preference. Discovery is currently ongoing. Calpine believes that it has valid defenses to this claim and will vigorously defend against this complaint. On January 26, 2004, Calpine filed a Motion for Partial Summary Judgment asserting that the Bankruptcy Court did not properly consolidate Anne Sholtz into the bankruptcy estate of EonXchange. If the motion is granted, at least $2.9 million of the $7 million that the Trustee is seeking to recover from the Company could not be avoided as a preferential transfer. The Company believes it has adequately reserved for the possible loss, if any, it may ultimately incur as a result of this matter.

      International Paper Company v. Androscoggin Energy LLC. In October 2000 International Paper Company (“IP”) filed a complaint in the Federal District Court for the Northern District of Illinois against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of

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AELLC’s fixed-cost gas supply agreements. The Company had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which closed in October 2000. AELLC filed a counterclaim against IP that has been referred to arbitration. AELLC may commence the arbitration counterclaim after discovery has progressed further. On November 7, 2002, the court issued an opinion on the parties’ cross motions for summary judgment finding in AELLC’s favor on certain matters though granting summary judgment to IP on the liability aspect of a particular claim against AELLC. The Court also denied a motion submitted by IP for preliminary injunction to permit IP to make payment of funds into escrow (not directly to AELLC) and require AELLC to post a significant bond.

      In mid-April of 2003 IP unilaterally availed itself to self-help in withholding amounts in excess of $2.0 million as a set-off for litigation expenses and fees incurred to date as well as an estimated portion of a rate fund to AELLC. Upon AELLC’s amended complaint and request for immediate injunctive relief against such actions, the Court ordered that IP must pay the approximately $1.2 million withheld as attorneys’ fees related to the litigation as any such perceived entitlement was premature, but deferred to provide injunctive relief on the incomplete record concerning the offset of $799,000 as an estimated pass-through of the rate fund. IP complied with the order on April 29, 2003, and tendered payment to AELLC of the approximately $1.2 million. On June 26, 2003, the court entered an order dismissing AELLC’s Amended Counterclaim without prejudice to AELLC refiling the claims as breach of contract claims in a separate lawsuit. On June 30, 2003, AELLC filed a motion to reconsider the order dismissing AELLC’s Amended Counterclaim. On December 11, 2003, the Court denied in part IP’s summary judgment motion pertaining to damages. In short, the Court: (i) determined that, as a matter of law, IP is entitled to pursue an action for damages as a result of AELLC’s breach, and (ii) ruled that sufficient questions of fact remain to deny IP summary judgment on the measure of damages as IP did not sufficiently establish causation resulting from AELLC’s breach of contract (the liability aspect of which IP obtained a summary judgment in December 2002). On February 2, 2004, the parties filed a pretrial order with the Court. The case appears likely scheduled for trial in the second quarter of 2004, subject to the Court’s discretion and calendar. The Company believes it has adequately reserved for the possible loss, if any, it may ultimately incur as a result of this matter.

      Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22, 2003, Pacific Gas and Electric Company (“PG&E”) filed with the California Public Utilities Commission (“CPUC”) a Complaint of PG&E and Request for Immediate Issuance of an Order to Show Cause (“Complaint”) against Calpine Corporation, CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas Company, and Lodi Gas Storage, LLC (“LGS”) . The Complaint requests the CPUC to issue an order requiring the defendants to show cause why they should not be ordered to cease and desist from using any direct interconnections between the facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek and obtain regulatory approval from the CPUC. The Complaint also seeks an order directing defendants to pay to PG&E any underpayments of PG&E’s tariffed transportation rates and to make restitution for any profits earned from any business activity related to LGS’ direct interconnections to any entity other than PG&E. The Complaint further alleges that various natural gas consumers, including Company-affiliated generation projects within California, are engaged with defendants in the acts complained of, and that the defendants unlawfully bypass PG&E’s system and operate as an unregulated local distribution company within PG&E’s service territory. On August 27, 2003, Calpine filed its answer and a motion to dismiss. LGS has also made similar filings. On October 16, 2003, the presiding administrative law judge denied the motion to dismiss and on October 24, 2003, issued a Scoping Memo and Ruling establishing a procedural schedule and set the matter for an evidentiary hearing. Although Calpine has denied the allegations in the Complaint and believes this Complaint to be without merit, on January 15, 2004, Calpine, LGS and PG&E executed a Settlement Agreement to resolve all outstanding allegations and claims raised in the Complaint. Certain aspects of the Settlement Agreement are effective immediately and the effectiveness of other provisions is subject to the approval of the Settlement Agreement by the CPUC; in the event the CPUC fails to approve the Settlement Agreement, its operative terms and conditions become null and void. The Settlement Agreement provides, in

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part, for: 1) PG&E to be paid $2.7 million; 2) the disconnection of the LGS interconnections with Calpine; 3) Calpine to obtain PG&E consent or regulatory or other governmental approval before resuming any sales or exchanges at the Ryer Island Meter Station; 4) PG&E’s withdrawal of its public utility claims against Calpine; and 5) no party admitting any wrongdoing. Accordingly, the presiding administrative law judge vacated the hearing schedule and established a new procedural schedule for the filing of the Settlement Agreement. On February 6, 2004, the Settlement Agreement was filed with the CPUC. Parties have the opportunity to submit comments and reply comments on the Settlement Agreement and then the matter shall be before the CPUC for its consideration.

      Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On November 5, 2003, Panda Energy International, Inc. and certain related parties, including PLC II, LLC, (collectively “Panda”) filed suit against the Company and certain of its affiliates in the U.S. District Court for the Northern District of Texas, alleging, among other things, that the Company breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta Energy Center (“Oneta”), which the Company acquired from Panda, in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits from Oneta and that the Company’s actions have reduced the profits from Oneta thereby undermining Panda’s ability to repay monies owed to the Company on December 1, 2003, under a promissory note on which approximately $38.6 million (including interest) is currently outstanding. The note is collateralized by Panda’s carried interest in the income generated from Oneta, which achieved full commercial operations in June 2003. The Company has filed a counterclaim against Panda Energy International, Inc. (and PLC II, LLC) based on a guaranty, and has also filed a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The Company considers Panda’s lawsuit to be without merit and intends to defend vigorously against it. The Company stopped accruing interest income on the promissory note due December 1, 2003, as of the due date because of Panda’s default in repayment of the note.

      California Business & Professions Code Section 17200 Cases, of which the lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al. This purported class action complaint filed in May 2002 against twenty energy traders and energy companies, including CES, alleges that defendants exercised market power and manipulated prices in violation of California Business & Professions Code Section 17200 et seq., and seeks injunctive relief, restitution, and attorneys’ fees. The Company also has been named in seven other similar complaints for violations of Section 17200. All seven cases were removed from the various state courts in which they were originally filed to federal court for pretrial proceedings with other cases in which the Company is not named as a defendant. The Company considers the allegations to be without merit, and filed a motion to dismiss on August 28, 2003. The court granted the motion, and plaintiffs have appealed.

      Prior to the motion to dismiss being granted, one of the actions, captioned Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to the Superior Court of the State of California for the County of Alameda. On January 12, 2004, CES was added as a defendant in Millar. This action includes similar allegations to the other 17200 cases, but also seeks rescission of the long term power contracts with the California Department of Water Resources. The Company anticipates filing a timely motion for dismissal of this action as well.

      McClintock et al. v. Vikram Budhraja, et al. California Department of Water Resources Case. On May 1, 2002, California State Senator Tom McClintock and others filed a complaint against Vikram Budhraja, a consultant to the California Department of Water Resources (“DWR”), DWR itself, and more than twenty-nine energy providers and other interested parties, including Calpine. The complaint alleged that the long term power contracts that DWR entered into with these energy providers, including Calpine, were rendered void because Budhraja, who negotiated the contracts on behalf of DWR, allegedly had an undisclosed financial interest in the contracts due to his connection with one of the energy providers, Edison International. Among other things, the complaint sought an injunction prohibiting further performance of the

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long term contracts and restitution of any funds paid to energy providers by the State of California under the contracts. The action had been stayed by order of the Court since August 26, 2002, pending resolution of an earlier filed state court action involving the same parties and subject matter captioned Carboneau v. State of California in which the Company is not a defendant. The Company considered the allegations against it in this lawsuit to be without merit and filed a motion for dismissal with prejudice on November 26, 2003, which was granted. No appeal was filed and therefore the case has been concluded in its entirety.

      Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy Services, L.P. before the FERC, filed on December 4, 2001. Nevada Section 206 Complaint. On December 4, 2001, Nevada Power Company (“NPC”) and Sierra Pacific Power Company (“SPPC”) filed a complaint with FERC under Section 206 of the Federal Power Act against a number of parties to their power sales agreements, including the Company. NPC and SPPC allege in their complaint, which seeks a refund, that the prices they agreed to pay in certain of the power sales agreements, including those signed with Calpine, were negotiated during a time when the power market was dysfunctional and that they are unjust and unreasonable. The Administrative Law Judge issued an Initial Decision on December 19, 2002, that found for Calpine and the other respondents in the case and denied NPC the relief that it was seeking. In June 2003, FERC rejected the complaint. Some plaintiffs appealed to the FERC and their request for rehearing was denied. The FERC decision is therefore final, and the matter is pending on appeal before the United States Court of Appeals for the Ninth Circuit.

      Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6, 2002, Calpine Canada Natural Gas Partnership (“Calpine Canada”) filed a complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp. (“Enron Canada”) owed it approximately $1.5 million from the sale of gas in connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron Canada has not sought bankruptcy relief and has counterclaimed in the amount of $18 million. Discovery is currently in progress, and the Company believes that Enron Canada’s counterclaim is without merit and intends to vigorously defend against it.

      Jones v. Calpine Corporation. On June 11, 2003, the Estate of Darrell Jones and the Estate of Cynthia Jones filed a complaint against Calpine in the U.S. District Court, Western District of Washington. Calpine purchased Goldendale Energy, Inc., a Washington Corporation, from Darrell Jones. The agreement provided, among other things, that upon substantial completion of the Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0 million less $0.2 million per day for each day that elapsed between July 1, 2002, and the date of substantial completion. Substantial completion of the Goldendale facility has not occurred and the daily reduction in the payment amount has reduced the $18.0 million payment to zero. The complaint alleges that by not achieving substantial completion by July 1, 2002, Calpine breached its contract with Mr. Jones, violated a duty of good faith and fair dealing, and caused an inequitable forfeiture. The complaint seeks damages in an unspecified amount in excess of $75,000. On July 28, 2003, Calpine filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. The court granted Calpine’s motion to dismiss the complaint on March 10, 2004. The plaintiffs have filed a motion for reconsideration of the decision, and the plaintiffs may also ultimately appeal. Calpine still, however, expects to make the $6.0 million payment to the estates when the project is completed.

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

 
25. Operating Segments

      The Company is first and foremost an electric generating company. In pursuing this single business strategy, it is the Company’s long-range objective to produce at a level of approximately 25% of its fuel

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consumption requirements from its own natural gas reserves (“equity gas”). Since the Company’s oil and gas production and marketing activity has reached the quantitative criteria to be considered a reportable segment under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” the following represents reportable segments and their defining criteria. The Company’s segments are electric generation and marketing; oil and gas production and marketing; and corporate and other activities. Electric generation and marketing includes the development, acquisition, ownership and operation of power production facilities, hedging, balancing, optimization, and trading activity transacted on behalf of the Company’s power generation facilities. Oil and gas production includes the ownership and operation of gas fields, gathering systems and gas pipelines for internal gas consumption, third party sales and hedging, balancing, optimization, and trading activity transacted on behalf of the Company’s oil and gas operations. Corporate activities and other consists primarily of financing activities, the Company’s specialty data center engineering business, which was divested in the third quarter of 2003 and general and administrative costs. Certain costs related to company-wide functions are allocated to each segment, such as interest expense, distributions on HIGH TIDES prior to October 1, 2003, and interest income, which are allocated based on a ratio of segment assets to total assets.

      The Company evaluates performance based upon several criteria including profits before tax. The accounting policies of the operating segments are the same as those described in Note 2. The financial results for the Company’s operating segments have been prepared on a basis consistent with the manner in which the Company’s management internally disaggregates financial information for the purposes of assisting in making internal operating decisions.

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

                                 
Electric Oil and Gas
Generation Production Corporate
and Marketing and Marketing and Other Total




(In thousands)
2003
                               
Revenue from external customers
  $ 8,798,695     $ 82,542     $ 38,302     $ 8,919,539  
Depreciation and amortization
    407,547       173,262       3,103       583,912  
Interest expense
    640,034       47,808       38,261       726,103  
Interest (income)
    (35,008 )     (2,615 )     (2,093 )     (39,716 )
Income before taxes
    (42,966 )     169,066       (16,481 )     109,619  
Discontinued operations, net of tax
    2,694       (97 )     (11,271 )     (8,674 )
Cumulative effect of a change in accounting principle, net gain (loss)
    183,270       (1,443 )     (884 )     180,943  
(Income) from unconsolidated investments in power projects and oil and gas properties
    (76,703 )                 (76,703 )
(Income) from repurchase of various issuances of debt
                (278,612 )     (278,612 )
Other (income) expense
    (50,517 )     (47,941 )     52,332       (46,126 )
Total assets
    24,067,448       1,797,755       1,438,729       27,303,932  
Investments in power plants and oil and gas properties
    444,151       28,598             472,749  
Property Additions
    1,848,318       46,633       4,288       1,899,239  
Equipment cancellation and impairment cost
    64,384                   64,384  
Intersegment revenues
          409,063             409,063  

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Electric Oil and Gas
Generation Production Corporate
and Marketing and Marketing and Other Total




(In thousands)
2002
                               
Revenue from external customers
  $ 7,088,665     $ 301,304     $ 1,892     $ 7,391,861  
Depreciation and amortization
    298,928       146,448       8,035       453,411  
Interest expense
    331,066       30,514       52,110       413,690  
Interest (income)
    (34,500 )     (3,182 )     (5,405 )     (43,087 )
Income before taxes
    175,960       (4,940 )     (132,275 )     38,745  
Discontinued operations, net of tax
    32,076       42,905       (10,053 )     64,928  
(Income) from unconsolidated investments in power projects and oil and gas properties
    (16,552 )                 (16,552 )
(Income) from repurchase of various issuances of debt
                (118,020 )     (118,020 )
Other (income) expense
    (41,043 )     (7,674 )     14,517       (34,200 )
Total assets
    18,587,342       1,713,085       2,926,565       23,226,992  
Investments in power plants and oil and gas properties
    421,402                   421,402  
Property Additions
    3,274,051       413,174       344,311       4,031,536  
Merger costs
    404,737                   404,737  
Intersegment revenues
          180,374             180,374  
2001
                               
Revenue from external customers
  $ 6,290,302     $ 406,536     $ 18,091     $ 6,714,929  
Depreciation and amortization
    181,078       122,129       6,166       309,373  
Interest expense
    150,237       15,281       31,103       196,621  
Interest (income)
    (55,507 )     (5,578 )     (11,363 )     (72,448 )
Income before taxes
    849,527       116,509       (85,456 )     880,580  
Discontinued operations, net of tax
    6,149       34,449       (1,108 )     39,490  
Cumulative effect of a change in accounting principle, net gain (loss)
    1,036                   1,036  
(Income) from unconsolidated investments in power projects and oil and gas properties
    (16,946 )                 (16,946 )
Merger costs
          41,627             41,627  
(Income) from repurchase of various issuances of debt
                (11,919 )     (11,919 )
Other (income) expense
    (30,869 )     (13,455 )     2,338       (41,786 )
Intersegment revenues
          123,845             123,845  

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

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Geographic Area Information

      As of December 31, 2003, the Company owned interests in 87 operating power plants in the United States, three operating power plants in Canada and one operating power plant in the United Kingdom. In addition, the Company had oil and gas interests in the United States and Canada. Geographic revenue and property, plant and equipment information is based on physical location of the assets at the end of each period.

                                 
United
United States Canada Kingdom Total




2003
                               
Total Revenue
  $ 8,384,544     $ 244,917     $ 290,078     $ 8,919,539  
Property, plant and equipment, net
    18,069,817       972,467       1,038,768       20,081,052  
2002
                               
Total Revenue
  $ 7,062,069     $ 123,908     $ 205,884     $ 7,391,861  
Property, plant and equipment, net
    16,841,885       925,787       963,175       18,730,847  
2001
                               
Total Revenue
  $ 6,428,137     $ 192,097     $ 94,695     $ 6,714,929  
 
26. California Power Market

      California Refund Proceeding. On August 2, 2000, the California Refund Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric Company under Section 206 of the Federal Power Act alleging, among other things, that the markets operated by the California Independent System Operator (“CAISO”) and the California Power Exchange (“CalPX”) were dysfunctional. In addition to commencing an inquiry regarding the market structure, FERC established a refund effective period of October 2, 2000, to June 19, 2001, for sales made into those markets.

      On December 12, 2002, the Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability (“December 12 Certification”) making an initial determination of refund liability. On March 26, 2003, FERC also issued an order adopting many of the ALJ’s findings set forth in the December 12 Certification (the “March 26 Order”). In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the refund period, FERC ordered that the basis for calculating a party’s potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the refund proceeding. The Company believes, based on the available information, that any refund liability that may be attributable to it will increase modestly, from approximately $6.2 million to $8.4 million, after taking the appropriate set-offs for outstanding receivables owed by the CalPX and CAISO to Calpine. The Company has fully reserved the amount of refund liability that by its analysis would potentially be owed under the refund calculation clarification in the March 26 order. The final determination of the refund liability is subject to further Commission proceedings to ascertain the allocation of payment obligations among the numerous buyers and sellers in the California markets. At this time, the Company is unable to predict the timing of the completion of these proceedings or the final refund liability. Thus the impact on the Company’s business is uncertain at this time.

      FERC Investigation into Western Markets. On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron and others used their market position to distort electric and natural gas markets in the West. The scope of the investigation is to consider whether, as a result of any manipulation in the short-term markets for electric energy or natural gas or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West are potentially unjust and unreasonable. FERC has stated that it may use the

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information gathered in connection with the investigation to determine how to proceed on any existing or future complaint brought under Section 206 of the Federal Power Act involving long-term power contracts entered into in the West since January 1, 2000, or to initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding on its own initiative. On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific Separate Proceedings and Generic Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies (the “Initial Report”) summarizing its initial findings in this investigation. There were no findings or allegations of wrongdoing by Calpine set forth or described in the Initial Report. On March 26, 2003, the FERC staff issued a final report in this investigation (the “Final Report”). The FERC staff recommended that FERC issue a show cause order to a number of companies, including Calpine, regarding certain power scheduling practices that may have been be in violation of the CAISO’s or CalPX’s tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. Calpine believes that it did not violate these tariffs and that, to the extent that such a finding could be made, any potential liability would not be material.

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

      CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our Qualifying Facilities (“QF”) contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility “avoided cost” to be used to set energy payments for certain QF contracts by determining the short run avoided cost (“SRAC”) energy price formula. In mid-2000 our QF facilities elected the option set forth in Section 390 of the California Public Utility Code, which provides QFs the right to elect to receive energy payments based on the California Power Exchange (“PX”) market clearing price instead of the price determined by SRAC. Having elected such option, the Company was paid based upon the PX zonal day-ahead clearing price (“PX Price”) from summer 2000 until January 19, 2001, when the PX ceased operating a day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC at one point issued a proposed decision to the effect that the PX Price was the appropriate price for energy payments under the California Public Utility Code but tabled it, and a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. The Company believes that the PX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings.

      City of Lodi Agreement. On February 9, 2001, the Company entered into an agreement with the City of Lodi (the Northern California Power Agency acted as agent on behalf of the City of Lodi) whereby CES would sell 25 MW of ATC fixed price power plus a 1.7 MW day-ahead call option to the City of Lodi for delivery from January 1, 2002, through December 31, 2011. In September 2002 the City of Lodi and Calpine agreed to terminate this agreement resulting in a $41.5 million gain to the Company. The gain is included in Other income in the accompanying consolidated financial statements.

      Geysers Reliability Must Run Section 206 Proceeding. California Independent System Operator, California Electricity Oversight Board, Public Utilities Commission of the State of California, Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison (collectively referred to as the “Buyers Coalition”) filed a complaint on November 2, 2001 at the FERC requesting the

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commencement of a Federal Power Act Section 206 proceeding to challenge one component of a number of separate settlements previously reached on the terms and conditions of “reliability must run” contracts (“RMR Contracts) with certain generation owners, including Geysers Power Company, LLC, which settlements were also previously approved by the FERC. RMR Contracts require the owner of the specific generation unit to provide energy and ancillary services when called upon to do so by the ISO to meet local transmission reliability needs or to manage transmission constraints. The Buyers Coalition has asked FERC to find that the availability payments under these RMR Contracts are not just and reasonable. Geysers Power Company, LLC filed an answer to the complaint in November 2001. To date, FERC has not established a Section 206 proceeding. The outcome of this litigation and the impact on the Company’s business cannot be determined at the present time.

 
27. Subsequent Events

      On January 9, 2004, one of the initial purchasers of the 2023 Convertible Notes exercised in full its option to purchase an additional $250.0 million of these notes. The notes are convertible into cash and into shares of Calpine common stock upon the occurrence of certain contingencies at an initial conversion price of $6.50 per share, which represents a 38% premium over the New York Stock Exchange closing price of $4.71 per share on November 6, 2003, the date the notes were originally priced. Upon conversion of the notes, Calpine will deliver par value in cash and any additional value in Calpine shares.

      On January 15, 2004, the Company completed the sale of its 50-percent undivided interest in the 545 megawatt Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the Lower Colorado River Authority (LCRA). Under the terms of the agreement, Calpine received a cash payment of $146.8 million and recorded a gain before taxes of $35.5. In addition, Calpine Energy Services entered into a tolling agreement with LCRA to purchase 250 megawatts of electricity through December 31, 2004. At December 31, 2003, the Company’s undivided interest in the Lost Pines facility was classified as “held for sale” and all current and historical results reclassified to discontinued operations (see Note 10).

      In January 2004 CES concluded a settlement with the Commodity Futures Trading Commission (“CFTC”) related to the CFTC’s finding of inaccurate reporting of certain natural gas trading information by one former CES employee during 2001 and 2002. Neither Calpine nor CES benefited from the trader’s conduct. Under the terms of the agreement, CES paid a civil monetary penalty in the amount of $1.5 million without admitting or denying the findings in the CFTC’s order.

      Subsequent to December 31, 2003, the Company repurchased approximately $177.0 million in principal amount of our outstanding 2006 Convertible Senior Notes that can be put to the Company in exchange for approximately $176.0 million in cash. Additionally, on February 9, 2004, the Company made a cash tender offer, which expired on March 9, 2004, for all of the outstanding 2006 Convertible Senior Notes at a price of par plus accrued interest. On March 10, 2004, the Company paid an aggregate amount of $412.8 million for the tendered 2006 Convertible Senior Notes which included accrued interest of $3.4 million. Currently, 2006 Convertible Senior Notes in the aggregate principal amount of $73.7 million remain outstanding.

      On February 2, 2004, a class action complaint was filed in the United States District Court for the Southern District of New York against CES and others. The complaint alleges unlawful manipulation of natural gas futures and options contracts traded on NYMEX during the period January 21, 2000 through December 31, 2002. The causes of action alleged are fraudulent concealment and violations of the Commodity Exchange Act, and CES anticipates filing a motion to dismiss the complaint. This complaint was filed as a related action to another consolidated class action complaint involving numerous other defendants. The court has not granted class action certification for any of the matters at this time.

      On February 18, 2004, one of the Company’s wholly owned subsidiaries closed on the sale of natural gas properties to Calpine Natural Gas Trust (“CNG Trust”). The Company received consideration of

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Cdn$40.5 million (US$30.9 million). Calpine holds 25% of the outstanding trust units of CNG Trust and accounts for the investment using the equity method.

      On February 20, 2004, the Company completed a $250.0 million, non-recourse project financing for the 600-megawatt Rocky Mountain Energy Center. A consortium of banks financed the construction of the plant at a rate of LIBOR plus 250 basis points. Upon commercial operation of the Rocky Mountain Energy Center, the banks will provide a three-year term-loan facility.

      On March 23, 2004, the Company’s wholly owned subsidiary Calpine Generating Company, LLC (“CalGen”), formerly Calpine Construction Finance Company II, LLC (“CCFC II”), completed its offering of secured term loans and secured notes. As expected, the Company realized net total proceeds from the offerings (after payment of transaction fees and expenses, including the fee payable to Morgan Stanley in connection with an index hedge) in the approximate amount of $2.3 billion. The offerings included:

             
Amount Description Interest Rate



$235.0 million
  First Priority Secured Floating Rate Notes Due 2009     LIBOR plus 375 basis points  
$640.0 million
  Second Priority Secured Floating Rate Notes Due 2010     LIBOR plus 575 basis points  
$680.0 million
  Third Priority Secured Floating Rate Notes Due 2011     LIBOR plus 900 basis points  
$150.0 million
  Third Priority Secured Notes Due 2011     11.50%  
$600.0 million
  First Priority Secured Term Loans due 2009     LIBOR plus 375 basis points (1)
$100.0 million
  Second Priority Secured Term Loans due 2010     LIBOR plus 575 basis points (2)


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

      The secured term loans and secured notes described above in each case are 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 refinance amounts outstanding under the $2.5 billion CCFC II revolving construction credit facility, which was scheduled to mature in November 2004, and to pay fees and transaction costs associated with the refinancing. Concurrently with this refinancing, the Company amended and restated the CCFC II credit facility (as amended and restated, the “CalGen revolving credit facility”) to reduce the commitments under the facility to $200.0 million and extend its maturity to March 2007. Interest under the CalGen revolving facility equals LIBOR plus 350 basis points (or, at the Company’s election, the Base Rate plus 250 basis points). Outstanding indebtedness and letters of credit at December 31, 2003, and at the refinancing date, under the CCFC II credit facility totaled approximately $2.3 billion and 2.4 billion, respectively.

 
28. Quarterly Consolidated Financial Data (unaudited)

      The Company’s quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, the timing and size of acquisitions, the completion of development projects, the timing and amount of curtailment of operations under the terms of certain power sales agreements, the degree of risk management and trading activity, and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of the Company’s power sales agreements are received during the months of May through October.

      The Company’s common stock has been traded on the New York Stock Exchange since September 19, 1996. There were 2,173 common stockholders of record at December 31, 2003. No dividends were paid for the

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years ended December 31, 2002 and 2001. All share data has been adjusted to reflect the two-for-one stock split effective June 8, 2000, and the two-for-one stock split effective November 14, 2000.

                                   
Quarter Ended

December 31, September 30, June 30, March 31,




(In thousands, except per share amounts)
2003
                               
Total revenue
  $ 1,920,575     $ 2,667,723 (i)   $ 2,165,308 (i)   $ 2,165,933 (i)
Gross profit
    126,691       353,987       183,232       172,791  
Income (loss) from operations
    (20,032 )     292,729       153,471       119,040  
Income (loss) before discontinued operations
    (59,827 )     237,493       (16,375 )     (51,538 )
Discontinued operations, net of tax
    (967 )     290       (6,991 )     (1,006 )
Cumulative effect of a change in accounting principle
    180,414                   529  
Net income (loss)
  $ 119,622     $ 237,782     $ (23,366 )   $ (52,016 )
Basic earnings per common share:
                               
 
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle
  $ (0.15 )   $ 0.61     $ (0.04 )   $ (0.14 )
 
Discontinued operations, net of tax
                (0.02 )      
 
Cumulative effect of a change in accounting principle
    0.44                    
 
Net income (loss)
    0.29       0.61       (0.06 )     (0.14 )
Diluted earnings per common share:
                               
 
Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities
  $ (0.15 )   $ 0.60     $ (0.04 )   $ (0.14 )
 
Dilutive effect of certain trust preferred securities
          (0.09 )            
 
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle
    (0.15 )     0.51       (0.04 )     (0.14 )
 
Discontinued operations, net of tax
                (0.02 )      
 
Cumulative effect of a change in accounting principle
    0.44                    
 
Net income (loss)
    0.29       (0.51 )     (0.06 )     (0.14 )
Common stock price per share:
                               
 
High
  $ 5.25     $ 8.03     $ 7.25     $ 4.42  
 
Low
    3.28       4.76       3.33       2.51  
2002
                               
Total revenue
  $ 1,869,640 (ii)   $ 2,457,346 (ii)   $ 1,744,592 (ii)   $ 1,320,283 (ii)
Gross profit
    236,942       345,965       244,847       178,899  
Income (loss) from operations
    (71,152 )     284,266       166,601       (57,239 )
Income (loss) before discontinued operations
    (64,397 )     138,884       57,732       (78,529 )
Discontinued operations, net of tax
    39,239       12,245       10,588       2,856  
Net income (loss)
  $ (25,158 )   $ 151,128     $ 68,321     $ (75,673 )

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                                   
Quarter Ended

December 31, September 30, June 30, March 31,




(In thousands, except per share amounts)
Basic earnings per common share:
                               
 
Income (loss) before discontinued operations
  $ (0.17 )   $ 0.37     $ 0.16     $ (0.26 )
 
Discontinued operations, net of tax
    0.10       0.03       0.03       0.01  
 
Net income (loss)
    (0.07 )     0.40       0.19       (0.25 )
Diluted earnings per common share:
                               
 
Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities
  $ (0.17 )   $ 0.36     $ 0.16     $ (0.26 )
 
Dilutive effect of certain trust preferred securities
          (0.04 )     (0.01 )      
 
Income (loss) before discontinued operations
    (0.17 )     0.32       0.15       (0.26 )
 
Discontinued operations, net of tax
    0.10       0.02       0.03       0.01  
 
Net income (loss)
    (0.07 )     0.34       0.18       (0.25 )
Common stock price per share:
                               
 
High
  $ 4.69     $ 7.29     $ 13.55     $ 17.28  
 
Low
    1.55       2.36       5.30       6.15  


 (i)  The total revenue amounts reported for the quarters ended September 30, 2003, June 30, 2003, and March 31, 2003, were $2,687,127, $2,186,056, and $2,186,277, respectively. The total revenue amounts above for the first, second and third quarters of 2003 have been restated as a result of discontinued operations. See Note 10 for more information regarding discontinued operations.
 
(ii)  The total revenue amounts reported for the quarters ended December 31, 2002, September 30, 2002, June 30, 2002, and March 31, 2002, were $1,886,470, $2,474,698, $1,758,372, and $1,332,535, respectively. The total revenue amounts above for the four quarters in 2003 have been restated as a result of discontinued operations. See Note 10 for more information regarding discontinued operations.

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SCHEDULE II

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

                                                           
Charged to
Accumulated
Balance at Other
Beginning Charged to Comprehensive Reserved Balance at
Description of Year Expense Loss Gain Reductions(1) Other(2) End of Year








(In thousands)
Year ended December 31, 2003
                                                       
 
Allowance for doubtful accounts
  $ 5,955     $ 3,278     $     $     $ (2,099 )   $ 480     $ 7,614  
 
Reserve for notes receivable
          273                                 273  
 
Gross reserve for California Refund Liability
    10,700       2,205                                 12,905  
 
Reserve for derivative assets
    16,452       19,459       3,640             (32,097 )             7,454  
 
Gain reserved on certain Enron transactions
    17,862                         (17,862 )              
 
Repayment reserve for third-party default on emission reduction credits’ settlement
          3,000                                 3,000  
 
Deferred tax asset valuation allowance
    26,665                         (7,330 )           19,335  
Year Ended December 31, 2002
                                                       
 
Allowance for doubtful accounts
  $ 15,422     $ 1,636     $     $     $ (11,246 )   $ 143     $ 5,955  
 
Gross reserve for California Refund Liability
          10,700                                 10,700  
 
Reserve for derivative assets
    1,583       17,253       8,444             (10,828 )             16,452  
 
Gain reserved on certain Enron transactions
    17,862                                       17,862  
 
Reserve for third-party default on emission reduction credits
    17,677                         (17,677 )              
 
Deferred tax asset valuation allowance
    26,665                                     26,665  
Year Ended December 31, 2001
                                                       
 
Allowance for doubtful accounts
  $ 11,555     $ 11,528     $     $     $ (7,656 )   $ (4 )   $ 15,423  
 
Reserve for notes receivable
    2,920                         (2,920 )              
 
Reserve for derivative assets
          23       1,560                           1,583  
 
Gain reserved on certain Enron transactions
                      17,862                     17,862  
 
Reserve for third-party default on emission reduction credits
          17,677                                 17,677  


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

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SUPPLEMENTAL OIL AND GAS DISCLOSURES

(Unaudited)

Oil and Gas Producing Activities

      The following disclosures for Calpine Corporation (the “Company”) are made in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 69, “Disclosures About Oil and Gas Producing Activities (An Amendment of FASB Statements 19, 25, 33 and 39).” Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

      Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

      Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.

      Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

      Estimates of proved and proved developed reserves as of December 31, 2003, 2002, and 2001, were based on estimates made by Netherland, Sewell & Associates Inc. (“NSA”) for reserves in the United States; and Gilbert Laustsen Jung Associates Ltd. (“GLJ”) for reserves in Canada, both independent petroleum consultants.

      Market prices as of each year-end were used for future sales of natural gas, crude oil and natural gas liquids. Future operating costs, production and ad valorem taxes and capital costs were based on current costs as of each year-end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risk.

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Capitalized Costs Relating to Oil and Gas Producing Activities

      The following table sets forth the capitalized costs relating to the Company’s natural gas and crude oil producing activities (excluding pipeline and related assets) at December 31, 2003, 2002 and 2001, (in thousands):

                           
2003 2002 2001



Proved properties
  $ 2,079,871     $ 1,668,626     $ 1,913,025  
Unproved properties
    63,143       305,639       322,735  
     
     
     
 
 
Total
    2,143,014       1,974,265       2,235,760  
Less: Accumulated depreciation, depletion and amortization
    (703,581 )     (525,700 )     (519,747 )
     
     
     
 
 
Net capitalized costs
  $ 1,439,433     $ 1,448,565     $ 1,716,013  
     
     
     
 
 
Company’s share of equity method investees’ net capitalized costs
  $ 54,453     $     $  
     
     
     
 

      Pursuant to SFAS No. 143, net capitalized cost includes related asset retirement cost, net of $13,819.

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

      The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include exploration expenses and additions to exploration wells, including those in progress. Development costs include additions to production facilities and equipment, as well as additions to development wells, including those in progress. The following table sets forth costs incurred related to the Company’s oil and gas activities for the years ended December 31, 2003, 2002, and 2001, (in thousands):

                               
United States Canada Total



                       
 
Acquisition costs of properties
                       
   
Proved
  $ 14,156     $ 7,109     $ 21,265  
   
Unproved
    13,617       3,304       16,921  
     
     
     
 
     
Subtotal
    27,773       10,413       38,186  
 
Exploration costs
    36,129       4,073       40,202  
 
Development costs
    58,130       51,986       110,116  
     
     
     
 
     
Total
  $ 122,032     $ 66,472     $ 188,504  
     
     
     
 
     
Company’s share of equity method investees’ costs of property acquisition, exploration and development
  $ 1,268     $ 53,039     $ 54,307  
                       
 
Acquisition costs of properties
                       
   
Proved
  $ 9,763     $ 2,650     $ 12,413  
   
Unproved
    8,460       1,694       10,154  
     
     
     
 
     
Subtotal
    18,223       4,344       22,567  
 
Exploration costs
    10,958       7,559       18,517  
 
Development costs
    54,986       61,209       116,195  
     
     
     
 
     
Total
  $ 84,167     $ 73,112     $ 157,279  
     
     
     
 

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United States Canada Total



                       
 
Acquisition costs of properties
                       
   
Proved
  $ 342,941     $ 6,762     $ 349,703  
   
Unproved
    234,789       17,780       252,569  
     
     
     
 
     
Subtotal
    577,730       24,542       602,272  
 
Exploration costs
    20,495       17,970       38,465  
 
Development costs
    86,311       162,343       248,654  
     
     
     
 
     
Total
  $ 684,536     $ 204,855     $ 889,391  
     
     
     
 
 
Results of Operations for Oil and Gas Producing Activities

      The following table sets forth results of operations for oil and gas producing activities (excluding pipeline and related operations) for the years ended December 31, 2003, 2002, and 2001, (in thousands):

                               
United States Canada Total



                       
 
Oil and gas production revenues
                       
   
Third-party
  $ 57,748     $ 33,834     $ 91,582  
   
Intercompany
    247,631       146,631       394,262  
     
     
     
 
     
Total revenues
    305,379       180,465       485,844  
 
Exploration expenses, including dry hole
    16,869       2,443       19,312  
 
Production costs
    47,848       35,658       83,506  
 
Depreciation, depletion and amortization
    83,238       85,879       169,117  
     
     
     
 
 
Income before income taxes
    157,424       56,485       213,909  
 
Income tax provision
    59,963       25,317       85,280  
 
(Income)/loss after income taxes from discontinued operations
    (110 )     95       (15 )
     
     
     
 
     
Results of operations
  $ 97,571     $ 31,073     $ 128,644  
     
     
     
 
Company’s share of equity method investees’ results of operations for producing activities
  $ 86     $ 101     $ 187  
     
     
     
 
                       
 
Oil and gas production revenues
                       
   
Third-party
  $ 39,739     $ 61,067     $ 100,806  
   
Intercompany
    138,010       62,844       200,854  
     
     
     
 
     
Total revenues
    177,749       123,911       301,660  
 
Exploration expenses, including dry hole
    10,287       2,797       13,084  
 
Production costs
    36,927       42,304       79,231  
 
Depreciation, depletion and amortization
    77,497       67,400       144,897  
     
     
     
 
 
Income before income taxes
    53,038       11,410       64,448  
 
Income tax provision
    20,685       5,438       26,123  
 
(Income)/loss after income taxes from discontinued operations
    1,795       (15,762 )     (13,967 )
     
     
     
 
     
Results of operations
  $ 30,558     $ 21,734     $ 52,292  
     
     
     
 

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United States Canada Total



                       
 
Oil and gas production revenues
                       
   
Third-party
  $ 92,345     $ 194,452     $ 286,797  
   
Intercompany
    112,171       3,730       115,901  
     
     
     
 
     
Total revenues
    204,516       198,182       402,698  
 
Exploration expenses, including dry hole
    4,311       9,284       13,595  
 
Production costs
    28,128       40,645       68,773  
 
Depreciation, depletion and amortization
    58,779       62,082       120,861  
     
     
     
 
 
Income before income taxes
    113,298       86,171       199,469  
 
Income tax provision
    40,610       41,069       81,679  
 
(Income)/loss after income taxes from discontinued operations
    35       (38,009 )     (37,974 )
     
     
     
 
     
Results of operations
  $ 72,653     $ 83,111     $ 155,764  
     
     
     
 

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

 
Net Proved and Proved Developed Reserve Summary

      The following table sets forth the Company’s net proved and proved developed reserves at December 31 for each of the three years in the period ended December 31, 2003, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the independent petroleum consultants.

                             
United States Canada Total



Natural gas (Bcf)(1):
                       
 
Net proved reserves at December 31, 2000
    333       537       870  
   
Revisions of previous estimates
    (24 )     (49 )     (73 )
   
Purchases in place
    208             208  
   
Extensions, discoveries and other additions
    125       31       156  
   
Sales in place
    (11 )     (13 )     (24 )
   
Production
    (41 )     (61 )     (102 )
     
     
     
 
 
Net proved reserves at December 31, 2001
    590       445       1,035  
   
Revisions of previous estimates
    (23 )     (1 )     (24 )
   
Purchases in place
                 
   
Extensions, discoveries and other additions
    64       22       86  
   
Sales in place
    (3 )     (119 )     (122 )
   
Production
    (53 )     (46 )     (99 )
     
     
     
 
 
Net proved reserves at December 31, 2002
    575       301       876  
   
Revisions of previous estimates
    (25 )     (22 )     (47 )
   
Purchases in place
    7       3       10  
   
Extensions, discoveries and other additions
    58       14       72  
   
Sales in place
    (5 )     (64 )     (69 )
   
Production
    (55 )     (31 )     (86 )
     
     
     
 
 
Net proved reserves at December 31, 2003
    555       201       756  
     
     
     
 

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United States Canada Total



Natural gas liquids and crude oil (MBbl)(2)(3):
                       
 
Net proved reserves at December 31, 2000
    3,539       46,661       50,200  
   
Revisions of previous estimates
    (238 )     (1,492 )     (1,730 )
   
Purchases in place
    1,116       450       1,566  
   
Extensions, discoveries and other additions
    671       2,243       2,914  
   
Sales in place
    (80 )     (3,054 )     (3,134 )
   
Production
    (434 )     (6,192 )     (6,626 )
     
     
     
 
 
Net proved reserves at December 31, 2001
    4,574       38,616       43,190  
   
Revisions of previous estimates
    265       782       1,047  
   
Purchases in place
                 
   
Extensions, discoveries and other additions
    191       819       1,010  
   
Sales in place
    (347 )     (23,620 )     (23,967 )
   
Production
    (574 )     (3,704 )     (4,278 )
     
     
     
 
 
Net proved reserves at December 31, 2002
    4,109       12,893       17,002  
   
Revisions of previous estimates
    (357 )     (882 )     (1,239 )
   
Purchases in place
    19       11       30  
   
Extensions, discoveries and other additions
    166       789       955  
   
Sales in place
    (113 )     (3,788 )     (3,901 )
   
Production
    (456 )     (1,480 )     (1,936 )
     
     
     
 
 
Net proved reserves at December 31, 2003
    3,368       7,543       10,911  
     
     
     
 
(Bcfe)(1) equivalents(4):
                       
 
Net proved reserves at December 31, 2000
    355       816       1,171  
   
Revisions of previous estimates
    (25 )     (58 )     (83 )
   
Purchases in place
    214       3       217  
   
Extensions, discoveries and other additions
    129       45       174  
   
Sales in place
    (12 )     (32 )     (44 )
   
Production
    (44 )     (97 )     (141 )
     
     
     
 
 
Net proved reserves at December 31, 2001
    617       677       1,294  
   
Revisions of previous estimates
    (21 )     4       (17 )
   
Purchases in place
                 
   
Extensions, discoveries and other additions
    65       27       92  
   
Sales in place
    (5 )     (261 )     (266 )
   
Production
    (56 )     (69 )     (125 )
     
     
     
 

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United States Canada Total



 
Net proved reserves at December 31, 2002
    600       378       978  
   
Revisions of previous estimates
    (27 )     (27 )     (54 )
   
Purchases in place
    7       3       10  
   
Extensions, discoveries and other additions
    59       19       78  
   
Sales in place
    (6 )     (87 )     (93 )
   
Production
    (58 )     (40 )     (98 )
     
     
     
 
 
Net proved reserves at December 31, 2003
    575       246       821  
     
     
     
 
   
Company’s proportional interest in reserves of investees accounted for by the equity method — December 31, 2003
    1       18       19  
     
     
     
 
Net proved developed reserves:
                       
 
Natural gas (Bcf)(1)
                       
        378       394       772  
        378       262       640  
        369       176       545  
 
Natural gas liquids and crude oil (MBbl)(2)(3)
                       
        2,719       34,131       36,850  
        2,509       11,623       14,132  
        1,870       6,820       8,690  
 
Bcf(1) equivalents(4)
                       
        394       599       993  
        393       332       725  
        380       216       596  


(1)  Billion cubic feet or billion cubic feet equivalent, as applicable.
 
(2)  Thousand barrels.
 
(3)  Includes crude oil, condensate and natural gas liquids.
 
(4)  Natural gas liquids and crude oil volumes have been converted to equivalent gas volumes using a conversion factor of six cubic feet of gas to one barrel of natural gas liquids and crude oil.
 
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

      The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on natural gas and crude oil reserve and production volumes estimated by the independent petroleum consultants. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and gas assets.

      The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas and crude oil reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense, for both the United States and Canada, has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities.

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      Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

      The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s natural gas and crude oil reserves for the years ended December 31, 2003, 2002, and 2001, (in millions):

                           
United States Canada Total



                       
 
Future cash inflows
  $ 3,365     $ 1,233     $ 4,598  
 
Future production and development costs
    (982 )     (496 )     (1,478 )
     
     
     
 
 
Future net cash flows before income taxes
    2,383       737       3,120  
 
Future income taxes
    (666 )     (135 )     (801 )
     
     
     
 
 
Future net cash flows
    1,717       602       2,319  
 
Discount to present value at 10% annual rate
    (792 )     (186 )     (978 )
     
     
     
 
 
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves
  $ 925     $ 416     $ 1,341  
     
     
     
 
 
Company’s share of equity method investees’ standardized measure of discounted future net cash flows
  $ 2     $ 18     $ 20  
     
     
     
 

      Pursuant to SFAS No. 143, future production and development cost includes future cash outflows related to the settlement of asset retirement obligations for the United States of $45 and Canada of $61.

                           
United States Canada Total



                       
 
Future cash inflows
  $ 2,798     $ 1,569     $ 4,367  
 
Future production and development costs
    (852 )     (435 )     (1,287 )
     
     
     
 
 
Future net cash flows before income taxes
    1,946       1,134       3,080  
 
Future income taxes
    (548 )     (379 )     (927 )
     
     
     
 
 
Future net cash flows
    1,398       755       2,153  
 
Discount to present value at 10% annual rate
    (622 )     (272 )     (894 )
     
     
     
 
 
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves
  $ 776     $ 483     $ 1,259  
     
     
     
 
                       
 
Future cash inflows
  $ 1,609     $ 1,621     $ 3,230  
 
Future production and development costs
    (602 )     (569 )     (1,171 )
     
     
     
 
 
Future net cash flows before income taxes
    1,007       1,052       2,059  
 
Future income taxes
    (217 )     (245 )     (462 )
     
     
     
 
 
Future net cash flows
    790       807       1,597  
 
Discount to present value at 10% annual rate
    (349 )     (269 )     (618 )
     
     
     
 
 
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves
  $ 441     $ 538     $ 979  
     
     
     
 

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Changes in Standardized Measure of Discounted Future Net Cash Flows

      The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, 2003, 2002, and 2001 (in millions):

                           
United States Canada Total



  $ 1,198     $ 1,880     $ 3,078  
 
Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs
    (177 )     (273 )     (450 )
 
Net changes in prices and production costs
    (1,314 )     (1,733 )     (3,047 )
 
Extensions, discoveries, additions and improved recovery, net of related costs
    165       70       235  
 
Development costs incurred
    26       46       72  
 
Revisions of previous quantity estimates and development costs
    (110 )     (298 )     (408 )
 
Accretion of discount
    120       40       160  
 
Net change in income taxes
    370       869       1,239  
 
Purchases of reserves in place
    187       6       193  
 
Sales of reserves in place
    (48 )     (36 )     (84 )
 
Changes in timing and other
    24       (33 )     (9 )
     
     
     
 
  $ 441     $ 538     $ 979  
 
Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs
    (140 )     (143 )     (283 )
 
Net changes in prices and production costs
    529       640       1,169  
 
Extensions, discoveries, additions and improved recovery, net of related costs
    120       44       164  
 
Development costs incurred
    47       (22 )     25  
 
Revisions of previous quantity estimates and development costs
    (88 )     12       (76 )
 
Accretion of discount
    44       6       50  
 
Net change in income taxes
    (181 )     (65 )     (246 )
 
Purchases of reserves in place
          2       2  
 
Sales of reserves in place
    (6 )     (515 )     (521 )
 
Changes in timing and other
    10       (14 )     (4 )
     
     
     
 
  $ 776     $ 483     $ 1,259  
 
Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs
    (258 )     (145 )     (403 )
 
Net changes in prices and production costs
    316       (78 )     238  
 
Extensions, discoveries, additions and improved recovery, net of related costs
    133       44       177  
 
Development costs incurred
    64       25       89  
 
Revisions of previous quantity estimates and development costs
    (91 )     (69 )     (160 )
 
Accretion of discount
    78       36       114  
 
Net change in income taxes
    (52 )     193       141  
 
Purchases of reserves in place
    10       11       21  
 
Sales of reserves in place
    (6 )     (166 )     (172 )
 
Changes in timing and other
    (45 )     82       37  
     
     
     
 
  $ 925     $ 416     $ 1,341  
     
     
     
 

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EXHIBIT INDEX

         
Exhibit
Number Description


  3.1.1     Amended and Restated Certificate of Incorporation of Calpine Corporation.(a)
  3.1.2     Certificate of Correction of Calpine Corporation.(b)
  3.1.3     Certificate of Amendment of Amended and Restated Certificate of Incorporation of Calpine Corporation.(c)
  3.1.4     Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation.(b)
  3.1.5     Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation.(b)
  3.1.6     Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation.(c)
  3.1.7     Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation.(d)
  3.1.8     Certificate of Ownership and Merger Merging Calpine Natural Gas GP, Inc. into Calpine Corporation.(e)
  3.1.9     Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation.(e)
  3.1.10     Amended and Restated By-laws of Calpine Corporation.(f)
  4.1.1     Indenture dated as of May 16, 1996, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(g)
  4.1.2     First Supplemental Indenture dated as of August 1, 2000, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(b)
  4.2.1     Indenture dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(h)
  4.2.2     Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(i)
  4.2.3     Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(b)
  4.3.1     Indenture dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(j)
  4.3.2     Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(j)
  4.3.3     Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(b)
  4.4.1     Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(k)
  4.4.2     First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(b)
  4.5.1     Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(k)
  4.5.2     First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(b)
  4.6.1     Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(l)
  4.6.2     First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(b)
  4.7     Indenture, dated as of April 30, 2001, between the Company and Wilmington Trust Company, as Trustee.(m)
  4.8.1     Amended and Restated Indenture dated as of October 16, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee.(n)


Table of Contents

         
Exhibit
Number Description


  4.8.2     Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(o)
  4.8.3     First Amendment, dated as of October 16, 2001, to Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(n)
  4.9.1     Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(n)
  4.9.2     First Supplemental Indenture, dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(n)
  4.9.3     Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(n)
  4.9.4     First Amendment, dated as of October 18, 2001, to Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(n)
  4.10     Indenture, dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(p)
  4.11     Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(p)
  4.12     Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(p)
  4.13     Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(p)
  4.14.1     Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee, including form of Notes.(q)
  4.14.2     Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q)
  4.14.3     Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(*)
  4.14.4     Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(*)
  4.15     Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy Center, as Guarantors, and Wilmington Trust Company, as Trustee and Collateral Agent, including form of Notes.(q)
  4.16     Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(*)
  4.17.1     Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(*)
  4.17.2     Registration Rights Agreement, dated as of November 14, 2003, between the Company and Deutsche Bank Securities, Inc., as Representative of the Initial Purchasers.(*)
  4.18     Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(r)
  4.19     First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(*)
  4.20     Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(*)


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Exhibit
Number Description


  4.21     Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(*)
  4.22     HIGH TIDES I.
  4.22.1     Certificate of Trust of Calpine Capital Trust, a Delaware statutory trust, dated September 29, 1999.(s)
  4.22.2     Corrected Certificate of Certificate of Trust of Calpine Capital Trust, a Delaware statutory trust, filed October 4, 1999.(s)
  4.22.3     Declaration of Trust of Calpine Capital Trust, dated as of October 4, 1999, among Calpine Corporation, as Depositor, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee, and the Administrative Trustees named therein.(s)
  4.22.4     Indenture, dated as of November 2, 1999, between Calpine Corporation and The Bank of New York, as Trustee, including form of Debenture.(s)
  4.22.5     Remarketing Agreement, dated November 2, 1999, among Calpine Corporation, Calpine Capital Trust, The Bank of New York, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(s)
  4.22.6     Amended and Restated Declaration of Trust of Calpine Capital Trust, dated as of November 2, 1999, among Calpine Corporation, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, and The Bank of New York, as Property Trustee, and the Administrative Trustees named therein, including form of Preferred Security and form of Common Security.(s)
  4.22.7     Preferred Securities Guarantee Agreement, dated as of November 2, 1999, between Calpine Corporation and The Bank of New York, as Guarantee Trustee.(s)
  4.23     HIGH TIDES II.
  4.23.1     Certificate of Trust of Calpine Capital Trust II, a Delaware statutory trust, filed January 25, 2000.(t)
  4.23.2     Declaration of Trust of Calpine Capital Trust II, dated as of January 24, 2000, among Calpine Corporation, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee, and the Administrative Trustees named therein.(t)
  4.23.3     Indenture, dated as of January 31, 2000, between Calpine Corporation and The Bank of New York, as Trustee, including form of Debenture.(t)
  4.23.4     Remarketing Agreement, dated as of January 31, 2000, among Calpine Corporation, Calpine Capital Trust II, The Bank of New York, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(t)
  4.23.5     Registration Rights Agreement, dated January 31, 2000, among Calpine Corporation, Calpine Capital Trust II, Credit Suisse First Boston Corporation and ING Barings LLC.(t)
  4.23.6     Amended and Restated Declaration of Trust of Calpine Capital Trust II, dated as of January 31, 2000, among Calpine Corporation, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee, and the Administrative Trustees named therein, including form of Preferred Security and form of Common Security.(t)
  4.23.7     Preferred Securities Guarantee Agreement, dated as of January 31, 2000, between Calpine Corporation and The Bank of New York, as Guarantee Trustee.(t)
  4.24     HIGH TIDES III.
  4.24.1     Amended and Restated Certificate of Trust of Calpine Capital Trust III, a Delaware statutory trust, filed July 19, 2000.(u)
  4.24.2     Declaration of Trust of Calpine Capital Trust III dated June 28, 2000, among the Company, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee and the Administrative Trustees named therein.(u)


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Exhibit
Number Description


  4.24.3     Amendment No. 1 to the Declaration of Trust of Calpine Capital Trust III dated July 19, 2000, among the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein.(u)
  4.24.4     Indenture dated as of August 9, 2000, between the Company and Wilmington Trust Company, as Trustee.(u)
  4.24.5     Remarketing Agreement dated as of August 9, 2000, among the Company, Calpine Capital Trust III, Wilmington Trust Company, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(u)
  4.24.6     Registration Rights Agreement dated as August 9, 2000, between the Company, Calpine Capital Trust III, Credit Suisse First Boston Corporation, ING Barings LLC and CIBC World Markets Corp.(u)
  4.24.7     Amended and Restated Declaration of Trust of Calpine Capital Trust III dated as of August 9, 2000, the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein, including the form of Preferred Security and form of Common Security.(u)
  4.24.8     Preferred Securities Guarantee Agreement dated as of August 9, 2000, between the Company, as Guarantor, and Wilmington Trust Company, as Guarantee Trustee.(u)
  4.25     PASS THROUGH CERTIFICATES (TIVERTON AND RUMFORD).
  4.25.1     Pass Through Trust Agreement dated as of December 19, 2000, among Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of Certificate.(b)
  4.25.2     Participation Agreement dated as of December 19, 2000, among the Company, Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership, PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee.(b)
  4.25.3     Appendix A — Definitions and Rules of Interpretation.(b)
  4.25.4     Indenture of Trust, Mortgage and Security Agreement, dated as of December 19, 2000, between PMCC Calpine New England Investment LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, including the forms of Lessor Notes.(b)
  4.25.5     Calpine Guaranty and Payment Agreement (Tiverton) dated as of December 19, 2000, by Calpine, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(b)
  4.25.6     Calpine Guaranty and Payment Agreement (Rumford) dated as of December 19, 2000, by Calpine, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(b)
  4.26     PASS THROUGH CERTIFICATES (SOUTH POINT, BROAD RIVER AND ROCKGEN).
  4.26.1     Pass Through Trust Agreement A dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 8.400% Pass Through Certificate, Series A.(f)
  4.26.2     Pass Through Trust Agreement B dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 9.825% Pass Through Certificate, Series B.(f)


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Exhibit
Number Description


  4.26.3     Participation Agreement (SP-1) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.4     Participation Agreement (SP-2) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.5     Participation Agreement (SP-3) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.6     Participation Agreement (SP-4) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.7     Participation Agreement (BR-1) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.8     Participation Agreement (BR-2) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.9     Participation Agreement (BR-3) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.10     Participation Agreement (BR-4) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)


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Exhibit
Number Description


  4.26.11     Participation Agreement (RG-1) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.12     Participation Agreement (RG-2) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.13     Participation Agreement (RG-3) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.14     Participation Agreement (RG-4) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(f)
  4.26.15     Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)
  4.26.16     Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)
  4.26.17     Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)
  4.26.18     Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(f)
  4.26.19     Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)
  4.26.20     Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)
  4.26.21     Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)


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Exhibit
Number Description


  4.26.22     Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(f)
  4.26.23     Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)
  4.26.24     Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)
  4.26.25     Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)
  4.26.26     Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(f)
  4.26.27     Calpine Guaranty and Payment Agreement (South Point SP-1) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.28     Calpine Guaranty and Payment Agreement (South Point SP-2) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.29     Calpine Guaranty and Payment Agreement (South Point SP-3) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.30     Calpine Guaranty and Payment Agreement (South Point SP-4) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.31     Calpine Guaranty and Payment Agreement (Broad River BR-1) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.32     Calpine Guaranty and Payment Agreement (Broad River BR-2) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.33     Calpine Guaranty and Payment Agreement (Broad River BR-3) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.34     Calpine Guaranty and Payment Agreement (Broad River BR-4) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)


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Exhibit
Number Description


  4.26.35     Calpine Guaranty and Payment Agreement (RockGen RG-1) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.36     Calpine Guaranty and Payment Agreement (RockGen RG-2) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.37     Calpine Guaranty and Payment Agreement (RockGen RG-3) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  4.26.38     Calpine Guaranty and Payment Agreement (RockGen RG-4) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(f)
  10.1     Financing Agreements.
  10.1.1.1     Calpine Construction Finance Company Financing Agreement (“CCFC II”), dated as of October 16, 2000.(b)(v)
  10.1.1.2     Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(*)
  10.1.2.1     Amended and Restated Credit Agreement, dated as of July 16, 2003 (“Amended and Restated Credit Agreement”), among the Company, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, Funding Agent, Lead Arranger and Bookrunner, Bayerische Landesbank, Cayman Islands Branch, as Lead Arranger, as Co-Bookrunner and Documentation Agent, and ING Capital LLC and Toronto Dominion (Texas) Inc., as Lead Arrangers, Co-Bookrunners and Syndication Agents.(p)
  10.1.2.2     First Amendment to Amended and Restated Credit Agreement, dated as of August 7, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(p)
  10.1.2.3     Amendment and Waiver to Amended and Restated Credit Agreement, dated as of August 28, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(q)
  10.1.2.4     Letter Agreement regarding Technical Correction to Amendment and Waiver to Amended and Restated Credit Agreement, dated as of September 5, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(q)
  10.1.2.5     Third Amendment to Amended and Restated Credit Agreement, dated as of November 6, 2003, among the Company, each of Quintana Minerals (USA) Inc., JOQ Canada, Inc., and Quintana Canada Holdings, LLC, as a Guarantor, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(q)
  10.1.2.6     Fourth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of November 19, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(*)
  10.1.2.7     Fifth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of December 30, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(*)


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Exhibit
Number Description


  10.1.2.8     Technical Correction to Fifth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of December 31, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(*)
  10.1.2.9     Waiver to Amended and Restated Credit Agreement, dated as of March 5, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(*)
  10.1.3     Letter of Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent.(p)
  10.1.4     Guarantee and Collateral Agreement, dated as of July 16, 2003, made by Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.5     First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.6     First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.7.1     Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.7.2     Amendment No. 1 to the Second Amendment Pledge Agreement (Stock Interests), dated as of November 18, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(*)
  10.1.8.1     Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.8.2     Amendment No. 1 to the Second Amendment Pledge Agreement (Membership Interests), dated as of November 18, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(*)
  10.1.9     First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.10. 1   Collateral Trust Agreement, dated as of July 16, 2003, among Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(p)
  10.1.10. 2   First Amendment to the Collateral Trust Agreement, dated as of November 18, 2003, among Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(*)
  10.1.11     Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from Calpine Corporation to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee.(p)
  10.1.12     Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(p)
  10.1.13     Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(p)


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Exhibit
Number Description


  10.1.14     Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from Calpine Corporation to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(p)
  10.1.15     Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee.(p)
  10.1.16     Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee.(p)
  10.1.17     Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee.(p)
  10.1.18     Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee.(p)
  10.1.19     Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from Calpine Corporation to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.20     Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.21     Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from Calpine Corporation to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.22     Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from Calpine Corporation to The Bank of New York, as Collateral Trustee.(p)
  10.1.23     Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.24     Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by Calpine Corporation in favor of The Bank of New York, as Collateral Trustee.(p)
  10.1.25     Designated Asset Sale Proceeds Account Control Agreement, dated as of July 16, 2003, among Calpine Corporation, Union Bank of California, N.A., and The Bank of New York, as Collateral Agent.(*)
  10.2     Term Loan Agreements.
  10.2.1     Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents.(p)
  10.2.2.1     Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q)
  10.2.2.2     Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q)


Table of Contents

         
Exhibit
Number Description


  10.2.2.3     Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)
  10.2.2.4     Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(*)
  10.2.3     Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(*)
  10.2.4     Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(*)
  10.3     Management Contracts or Compensatory Plans or Arrangements.
  10.3.1     Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(*)(w)
  10.3.2     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Mr. Peter Cartwright.(t)(w)
  10.3.3     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Ms. Ann B. Curtis.(f)(w)
  10.3.4     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Mr. Ron A. Walter.(f)(w)
  10.3.5     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Mr. Robert D. Kelly.(f)(w)
  10.3.6     Employment Agreement, dated as of January 1, 2000, between Calpine Corporation and Mr. Thomas R. Mason.(f)(w)
  10.3.7     Consulting Contract, dated as of January 1, 2004, between Calpine Corporation and Mr. George J. Stathakis. (*)(w)
  10.3.8     Calpine Corporation Annual Management Incentive Plan.(x)(w)
  10.3.9     $500,000 Promissory Note Secured by Deed of Trust made by Thomas R. Mason and Debra J. Mason in favor of Calpine Corporation.(x)(w)
  10.3.10     2000 Employee Stock Purchase Plan (y)(w)
  10.3.11     Form of Indemnification Agreement for directors and officers.(z)(w)
  10.3.12     Form of Indemnification Agreement for directors and officers.(f)(w)
  12.1     Statement on Computation of Ratio of Earnings to Fixed Charges.(*)
  21.1     Subsidiaries of the Company.(*)
  23.1     Consent of Deloitte & Touche LLP, Independent Public Accountants.(*)
  23.2     Consent of PricewaterhouseCoopers LLP, Independent Public Accountants.(*)
  23.3     Consent of Netherland, Sewell & Associates, Inc., independent engineer.(*)
  23.4     Consent of Gilbert Laustsen Jung Associates, Ltd., independent engineer.(*)
  24.1     Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this report).(*)
  31.1     Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)


Table of Contents

         
Exhibit
Number Description


  31.2     Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*)
  32.1     Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*)
  99.1     Acadia Power Partners, LLC and Subsidiary, Consolidated Financial Statements, December 31, 2003, 2002 and 2001.(*)
  99.2     Consent of PricewaterhouseCoopers LLP, Independent Public Accountants.(*)


 
(*) Filed herewith.
 
(a) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-40652) filed with the SEC on June 30, 2000.
 
(b) Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.
 
(c) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-66078) filed with the SEC on July 27, 2001.
 
(d) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.
 
(e) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2002, filed with the SEC on May 15, 2002.
 
(f) Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2001, filed with the SEC on March 29, 2002.
 
(g) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-06259) filed with the SEC on June 19, 1996.
 
(h) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.
 
(i) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-41261) filed with the SEC on November 28, 1997.
 
(j) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-61047) filed with the SEC on August 10, 1998.
 
(k) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-72583) filed with the SEC on March 8, 1999.
 
(l) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17, 2002.
 
(m) Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001.
 
(n) Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001.
 
(o) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-57338) filed with the SEC on April 19, 2001.
 
(p) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
 
(q) Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003.
 
(r) Incorporated by reference to Calpine Corporation’s Registration Statement on Form 8-A/ A (Registration No. 001-12079) filed with the SEC on September 28, 2001.
 
(s) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-87427) filed with the SEC on October 26, 1999.


Table of Contents

 
(t) Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, filed with the SEC on February 29, 2000.
 
(u) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration Statement No. 333-47068) filed with the SEC on September 29, 2000.
 
(v) Approximately 71 pages of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.
 
(w) Management contract or compensatory plan or arrangement.
 
(x) Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated March 30, 2000, filed with the SEC on April 3, 2000.
 
(y) Incorporated by reference to Calpine Corporation’s Definitive Proxy Statement on Schedule 14A dated April 13, 2000, filed with the SEC on April 13, 2000.
 
(z) Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-1/ A (Registration Statement No. 333-07497) filed with the SEC on August 22, 1996.

Dates Referenced Herein   and   Documents Incorporated by Reference

This ‘10-K’ Filing    Date    Other Filings
11/15/23
11/22/18
11/15/18
11/22/13
11/15/134
7/15/13
12/31/1110-K,  5
12/1/11
10/15/11
2/15/11
8/15/10
7/15/10
5/31/10
11/22/09
11/15/09
4/15/09
10/15/084,  4/A
5/1/08
4/1/08
10/15/07
7/15/07
6/18/07
4/15/07
12/31/0610-K,  11-K,  8-K
12/26/06
7/15/06
5/15/06
4/15/06
8/15/05
8/1/05
7/15/05
2/1/058-K
1/28/05
12/31/0410-K,  11-K,  8-K,  NT 10-K
12/26/04
11/1/044
6/1/044
5/24/04
3/31/0410-Q,  10-Q/A,  8-K
Filed as of:3/25/04
Filed on:3/24/04
3/23/048-K
3/22/04
3/19/04
3/12/048-K
3/10/048-K
3/9/04
3/5/04
2/20/048-K
2/18/044
2/9/048-K,  SC TO-I
2/6/048-K
2/5/04
2/2/044
1/26/04
1/20/048-K
1/15/04
1/14/04
1/13/04
1/12/04
1/9/048-K
1/7/04
1/1/04
For Period End:12/31/0310-K/A,  11-K,  NT 10-K,  NT 11-K
12/30/03
12/29/03
12/22/03
12/11/03
12/5/038-K
12/4/038-K
12/1/03
11/26/038-K
11/21/03
11/20/038-K
11/19/03
11/18/03
11/17/038-K
11/14/03
11/13/0310-Q
11/7/038-K
11/6/038-K
11/5/038-K
10/24/03
10/22/038-K
10/21/038-K
10/20/03
10/17/03
10/16/038-K
10/15/038-K
10/1/038-K
9/30/0310-Q
9/25/038-K
9/18/03
9/12/03
9/5/03
9/3/038-K
8/29/03
8/28/038-K
8/27/038-K
8/25/038-K
8/22/03
8/14/0310-Q,  8-K
8/13/03
8/8/03
8/7/038-K
8/5/03
7/31/03
7/28/03
7/24/038-K
7/23/038-K
7/22/03
7/21/03
7/17/038-K
7/16/038-K
7/15/03424B3
7/14/034
7/10/038-K
7/8/03
7/1/0310-Q,  NT 11-K,  S-8
6/30/0310-Q,  NT 11-K
6/26/038-K
6/25/038-K
6/15/03
6/13/038-K
6/11/03
5/31/03
5/28/03DEF 14A
5/24/03
5/23/038-K
5/15/03
5/14/038-K
5/12/03
4/29/03
4/17/038-K
4/10/03
3/31/0310-K,  10-Q
3/26/03
3/11/03
3/10/03
3/5/03
3/4/038-K
3/3/038-K
2/26/03
2/13/038-K
2/11/038-K
2/5/03
1/31/03
1/16/03
1/1/03
12/31/0210-K,  11-K,  8-K,  NT 11-K
12/19/028-K
12/18/028-K
12/17/02
12/16/02
12/15/02
12/12/02
11/7/02
11/5/028-K
11/1/02
10/31/02
10/30/02
10/1/02
9/30/0210-Q
9/20/028-K
8/29/028-K
8/26/028-K
8/22/02
8/13/02
8/8/02
8/7/02
7/15/02
7/1/02
6/30/0210-Q
6/21/02
6/15/02
5/24/02
5/15/0210-Q
5/14/02
5/13/02
5/6/02
5/1/02
4/30/02
4/24/028-K
4/23/02
4/22/02
4/18/02424B5
4/3/02
4/1/02
3/31/0210-Q
3/29/0210-K
3/28/02
3/18/02
3/13/028-K
3/12/028-K
3/11/02
3/5/02
2/13/0210-Q/A
2/6/02
1/31/028-K
1/17/028-K,  S-3
1/3/02
1/1/02
12/31/0110-K,  11-K
12/26/01
12/19/01
12/17/01
12/13/018-K
12/10/01
12/4/01
12/2/01
11/14/0110-Q,  8-K
11/13/018-K
11/6/01424B3,  S-3/A
11/2/01
10/22/01S-3,  S-3/A
10/18/01
10/16/01424B3,  8-K
10/15/01424B3
9/28/018-A12B/A,  8-K,  U-57
9/25/01
9/21/01
9/20/01S-3/A
9/19/018-K
9/12/01
8/24/01
7/27/018-K,  S-3
7/26/018-K
7/12/018-K
7/10/01
6/30/0110-Q,  8-K
6/27/01
6/19/01
5/15/0110-Q
4/30/018-K,  S-3
4/25/01
4/19/018-K,  DEF 14A,  S-3/A,  S-8
4/6/01
3/31/0110-Q
3/15/0110-K
2/9/018-K,  SC 13G/A
2/6/01
1/26/01
1/19/01424B5
1/5/01
1/1/01
12/31/0010-K,  11-K,  8-K
12/19/00
12/15/00424B5
11/14/0010-Q,  424B2,  S-3/A
10/16/00
10/2/00
9/29/00S-3
9/28/00
8/10/00
8/9/0010-Q,  8-K
8/2/00424B5
8/1/00
7/31/00
7/19/00
6/30/0010-Q,  8-K,  S-3
6/28/0011-K
6/8/00
5/23/00
5/1/00
4/13/00DEF 14A
4/3/008-K
3/30/008-K
2/29/0010-K
2/24/00
1/31/00
1/25/00
1/24/00
1/21/00
1/11/00
1/1/00
12/31/9910-K,  11-K
12/2/99
11/2/99
10/26/99S-3/A
10/4/99
9/29/99SC 13D/A,  SC 14D1/A
7/1/99
5/7/998-K
4/30/99
3/29/99
3/8/9910-K/A,  S-3/A
8/10/98S-4
7/24/98
5/8/98
4/1/9810-K/A,  8-K
3/31/9810-Q,  8-K,  8-K/A
11/28/97S-4
9/10/97
8/14/9710-Q
7/8/97
6/30/9710-Q
6/18/978-A12B
6/5/978-K,  DEF 14A
9/20/96424B4
9/19/96S-1/A
8/22/96S-1/A
6/19/96S-4
5/16/96
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