ITEM 1. BUSINESS
Except for historical financial information contained herein, the matters discussed in this annual report may be considered forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended and subject to the safe harbor created by the Securities Litigation Reform Act of 1995. Such statements include declarations regarding the intent, belief or current expectations of the Company and its management. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties; actual results could differ materially from those indicated by such forward-looking statements. Among the important factors that could cause actual results to differ materially from those indicated by such forward-looking statements are: (i) that the information is of a preliminary nature and may be subject to further adjustment, (ii) those risks and uncertainties identified under "Risk Factors" included in Item 1. Business in this Annual Report on Form 10-K, (iii) the possible unavailability of financing, (iv) risks related to the development, acquisition and operation of power plants, (v) the impact of avoided cost pricing, energy price fluctuations and gas price increases, (vi) the impact of curtailment, (vii) the seasonal nature of the Company's business, (viii) start-up risks, (ix) general operating risks, (x) the dependence on third parties, (xi) risks associated with international investments, (xii) risks associated with the power marketing business, (xiii) changes in government regulation, (xiv) the availability of natural gas, (xv) the effects of competition, (xvi) the dependence on senior management, (xvii) volatility in the Company's stock price, (xviii) fluctuations in quarterly results and seasonality, and (xix) other risks identified from time to time in the Company's reports and registration statements filed with the Securities and Exchange Commission.
OVERVIEW
Calpine is a leading independent power company engaged in the development, acquisition, ownership and operation of power generation facilities and the sale of electricity predominantly in the United States. We have experienced significant growth in all aspects of our business over the last five years. Currently, we own interests in 22 power plants having an aggregate capacity of 2,729 megawatts and have three acquisition transactions pending in which we will acquire 14 geothermal power plants with an aggregate capacity of 694 megawatts and certain related steam fields. We also have six gas-fired projects under construction having an aggregate capacity of 1,784 megawatts and have announced plans to develop four gas-fired power plants with a total capacity of 2,580 megawatts. Upon completion of pending acquisitions and projects under construction, we will have interests in 40 power plants having an aggregate capacity of 5,207 megawatts, of which we will have a net interest in 4,271 megawatts. This represents significant growth from the 342 megawatts of capacity we had at the end of 1993. Of this total generating capacity, 81% will be attributable to gas-fired facilities and 19% will be attributable to geothermal facilities.
As a result of our expansion program, our revenues, cash flow, earnings and assets have grown significantly over the last five years, as shown in the table below.
Since our inception in 1984, we have developed substantial expertise in all aspects of the development, acquisition and operation of power generation facilities. We believe that the vertical integration of our extensive engineering, construction management, operations, fuel management and financing capabilities provides us with a competitive advantage to successfully implement our acquisition and development program and has contributed to our significant growth over the past five years.
THE MARKET
The power industry represents the third largest industry in the United States, with an estimated end-user market of over $250 billion of electricity sales in 1998 produced by an aggregate base of power generation facilities with a capacity of approximately 750,000 megawatts. In response to increasing customer demand for access to low-cost electricity and enhanced services, new regulatory initiatives have been and are continuing to be adopted at both the state and federal level to increase competition in the domestic power generation industry. The power generation industry historically has been largely characterized by electric utility monopolies producing electricity from old, inefficient, high-cost generating facilities selling to a captive customer base. Industry trends and regulatory initiatives have transformed the existing market into a more competitive market where end users purchase electricity from a variety of suppliers, including non-utility generators, power marketers, public utilities and others.
There is a significant need for additional power generating capacity throughout the United States, both to satisfy increasing demand, as well as to replace old and inefficient generating facilities. Due to environmental and economic considerations, we believe this new capacity will be provided predominantly by gas-fired facilities. We believe that these market trends will create substantial opportunities for efficient, low-cost power producers that can produce and sell energy to customers at competitive rates.
In addition, as a result of a variety of factors, including deregulation of the power generation market, utilities, independent power producers and industrial companies are disposing of power generation facilities. To date, numerous utilities have sold or announced their intentions to sell their power generation facilities and have focused their resources on the transmission and distribution segments. Many independent producers operating a limited number of power plants are also seeking to dispose of their plants in response to competitive pressures, and industrial companies are selling their power plants to redeploy capital in their core businesses.
STRATEGY
Our strategy is to continue our rapid growth by capitalizing on the significant opportunities in the power market, primarily through our active development and acquisition programs. In pursuing our proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach uses our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations and power marketing, which we believe provides us with a competitive advantage. The key elements of our strategy are as follows:
- Development and expansion of power plants. We are actively pursuing the development and expansion of highly efficient, low-cost, gas-fired power plants to replace old and inefficient generating facilities and meet the demand for new generation. Our strategy is to develop power plants in strategic geographic locations that enable us to utilize existing power generation assets and operate the power plants as integrated electric generation systems. This allows us to achieve significant operating synergies and efficiencies in fuel procurement, power marketing and operations and maintenance.
In July 1998, we achieved a key milestone in our development program by completing the development of our 240 megawatt gas-fired power plant in Pasadena, Texas. The Pasadena Power Plant serves as a prototype for future development projects. We currently have six gas-fired projects under construction, representing an additional 1,784 megawatts of capacity. Of these new projects, we are expanding our Pasadena and Clear Lake facilities by an aggregate of 545 megawatts. In addition, four new gas-fired power plants, with a total capacity of 1,239 megawatts, are currently under construction in Dighton, Massachusetts; Tiverton, Rhode Island; Rumford, Maine; and Westbrook, Maine. We have also announced plans to develop four additional power generation facilities, totaling an estimated 2,580 megawatts of electricity, in California, Texas and Arizona.
- Acquisition of power plants. Our strategy is to acquire power generating facilities that meet our stringent criteria, provide significant potential for revenue, cash flow and earnings growth and provide
the opportunity to enhance the operating efficiencies of the plants. We have significantly expanded and diversified our project portfolio through the acquisition of power generation facilities through the completion of 23 acquisitions to date.
We are currently in the process of completing three acquisitions comprising 14 geothermal power plants with an aggregate capacity of 694 megawatts and certain related steam fields located in The Geysers, California. Historically, we have served as the steam supplier for these facilities, which have been owned and operated by PG&E. We anticipate that these acquisitions will enable us to consolidate our operations in The Geysers into a single ownership structure and to integrate the power plant and steam field operations, allowing us to optimize the efficiency and performance of the facilities. We believe that these acquisitions will provide us with significant synergies that utilize our expertise in geothermal power generation and position us to benefit from the demand for "green" energy in the competitive market.
- Enhancement of the performance and efficiency of existing power projects. We continually seek to maximize the power generation potential of our operating assets and minimize our operating and maintenance expenses and fuel costs. This will become even more significant as our portfolio of power generation facilities expands to an aggregate of 40 power plants with an aggregate capacity of 5,207 megawatts, after completion of our pending acquisitions and projects currently under construction. We focus on operating our plants as an integrated system of power generation, which enables us to minimize costs and maximize operating efficiencies. As of December 31, 1998, our power generation facilities have operated at an average availability of approximately 96.5%. We believe that achieving and maintaining a low-cost of production will be increasingly important to compete effectively in the power generation market.
DESCRIPTION OF FACILITIES
We currently have interests in 22 power generation facilities and three steam fields with a current aggregate capacity of approximately 3,018 megawatts, consisting of 18 gas-fired power plants with a total capacity of 2,602 megawatts, four geothermal power generation facilities with a total capacity of 127 megawatts, and three steam fields with a total capacity of 289 megawatts. We also have three pending acquisitions of 14 geothermal power plants with an aggregate capacity of 694 megawatts and certain related steam fields, six gas-fired projects currently under construction with an aggregate capacity of 1,784 megawatts, and have announced the development of four additional power plants with an aggregate capacity of 2,580 megawatts. Each of the power generation facilities currently in operation produces electricity for sale to a utility or other third-party end user. Thermal energy produced by the gas-fired cogeneration facilities is sold to governmental and industrial users.
The gas-fired and geothermal power generation projects in which we have an interest produce electricity and thermal energy that are typically sold pursuant to long-term power sales agreements. Revenue from a power sales agreement usually consists of two components: energy payments and capacity payments. Energy payments are based on a power plant's net electrical output where payment rates may be determined by a schedule of prices covering a fixed number of years under the power sales agreement, after which payment rates are usually indexed to the fuel costs of the contracting utility or to general inflation indices. Capacity payments are based on a power plant's net electrical output and/or its available capacity. Energy payments are made for each kilowatt hour of energy delivered, while capacity payments, under certain circumstances, are made whether or not any electricity is delivered.
Upon completion of the pending acquisitions and projects under construction, we will provide operating and maintenance services for 31 of the 40 power plants and steam fields in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps, 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 performed 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 are generally subordinated to any lease payments or debt service obligations of non-recourse 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 attempt to structure a gas-fired power facility's fuel supply agreement so that gas costs have a direct relationship to the fuel component of revenue energy payments. We currently hold interests in geothermal leaseholds in The Geysers that produce steam that is supplied to the power generation facilities owned by us for use in producing electricity.
Certain power generation facilities in which we have an interest have been financed primarily with non-recourse project financing that is structured to be serviced out of the cash flows derived from the sale of electricity, thermal energy and/or steam produced by such facilities and provides that the obligations to pay interest and principal on the loans are secured almost solely by the capital stock or partnership interests, physical assets, contracts and/or cash flow attributable to the entities that own the facilities. The lenders under non-recourse project financing generally have no recourse for repayment against us or any of our assets or the assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the facilities.
Substantially all of the power generation facilities in which we have an interest are located on sites which are leased on a long-term basis. See "-- Properties."
Set forth below is certain information regarding our operating power plants, plants under construction, pending power plant acquisitions and development projects.
- --------------- (1) Nameplate capacity may not represent the actual output for a facility at any particular time.
(2) See "-- Operating Power Plants -- Sumas Power Plant" for a description of our interest in the Sumas Power Plant. Based on our current estimates, these payments represent approximately 70% of distributable cash.
(3) See "Project Development and Acquisitions -- Project Development -- Projects Under Construction -- Tiverton Power Plant" for a description of our interest in the Tiverton Power Plant.
(4) See "Project Development and Acquisitions -- Project Development -- Projects Under Construction -- Rumford Power Plant" for a description of our interest in the Rumford Power Plant.
(5) See "Project Development and Acquisitions -- Project Development -- Projects Under Construction -- Dighton Power Plant" for a description of our interest in the Dighton Power Plant. Based on our current estimates, our interest represents our right to receive approximately 50% of project cash flow beginning at the commencement of commercial operation.
OPERATING POWER PLANTS
Texas City Power Plant. The Texas City Power Plant is a 450 megawatt gas-fired cogeneration facility located in Texas City, Texas. Electricity generated by the Texas City Power Plant is sold under two separate long-term agreements to (1) Texas Utilities Electric Company ("TUEC") under a power sales agreement terminating on September 30, 2002, and (2) Union Carbide Corporation ("UCC") under a steam and electricity services agreement terminating on June 30, 1999. Each agreement contains payment provisions for capacity and electric energy payments. Under a steam and electricity services agreement expiring October 19, 2003, the Texas City Power Plant will supply UCC with 300,000 lbs/hr of steam on a monthly average basis, with the required supply of steam not exceeding 600,000 lbs/hr at any given time. During 1998, the Texas City Power Plant generated approximately 2,517,316,000 kilowatt hours of electric energy for sale to TUEC and UCC and approximately $188.3 million of revenue.
Clear Lake Power Plant. The Clear Lake Power Plant is a 377 megawatt gas/hydrogen-fired cogeneration facility located in Pasadena, Texas. Electricity generated by the Clear Lake Power Plant is sold under three separate long-term agreements to (1) Texas-New Mexico Power Company ("TNP") under a power sales agreement terminating in 2004, (2) Houston Lighting and Power Company ("HL&P") under a power sales agreement terminating in 2005, and (3) Hoechst Celanese Chemical Group, Inc. ("HCCG") under a power sales agreement terminating in 2004. Each power sales agreement contains payment provisions for capacity and energy payments. Under a steam purchase and sale agreement expiring August 31, 2004, the Clear Lake Power Plant will supply up to 900,000 lbs/hr of steam to HCCG. During 1998, the Clear Lake Power Plant generated approximately 2,912,649,000 kilowatt hours of electric energy for sale to TNP, HL&P and HCCG and approximately $89.3 million of revenue.
Pasadena Power Plant. The Pasadena Power Plant is a 240 megawatt gas-fired cogeneration facility located in Pasadena, Texas. Electricity generated by the Pasadena Power Plant is sold under contract and into the open market. We entered into an energy sales agreement with Phillips Petroleum Company ("Phillips") terminating in 2018. Under this agreement, we provide 90 megawatts of electricity and 200,000 lbs/hr of steam to Phillips' Houston Chemical Complex. West Texas Utilities purchased 50 megawatts of capacity through the end of 1998. In 1999, LG&E Energy Marketing will purchase up to 150 megawatts of electricity under a one-year agreement. TUEC is also under contract to purchase up to 150 megawatts of electricity under a two-year agreement beginning December 1, 1999. The remaining available electricity output is sold into the competitive market through our power marketing organization. During 1998, the Pasadena Power Plant generated approximately 812,314,000 kilowatt hours of electric energy with approximately $30.5 million of revenue.
Gordonsville Power Plant. The Gordonsville Power Plant is a 240 megawatt gas-fired cogeneration facility located near Gordonsville, Virginia. Electricity generated by the Gordonsville Power Plant is sold to the Virginia Electric and Power Company under two power sales agreements terminating on June 1, 2024, each of which include payment provisions for capacity and energy. The Gordonsville Power Plant sells steam to Rapidan Service Authority under the terms of a steam purchase and sales agreement, which expires June 1, 2004. During 1998, the Gordonsville Power Plant generated approximately 213,382,000 kilowatt hours of electrical energy and approximately $37.4 million of revenue.
Lockport Power Plant. The Lockport Power Plant is a 184 megawatt gas-fired, combined-cycle cogeneration facility located in Lockport, New York. The facility is owned and operated by Lockport Energy
Associates, L.P. ("LEA"). We own an indirect 11.36% limited partnership interest in LEA. Electricity and steam is sold to General Motors Corporation ("GM") under an energy sales agreement expiring in December 2007 for use at the GM Harrison plant, which is located on a site adjacent to the Lockport Power Plant. Electricity is also sold to New York State Electricity and Gas Company ("NYSEG") under a power purchase agreement expiring October 2007. NYSEG is required to purchase all of the electric power produced by the Lockport Power Plant not required by GM. For 1998, the Lockport Power Plant generated approximately 1,284,830,000 kilowatt hours of electricity and had $118.6 million in revenue.
Bayonne Power Plant. The Bayonne Power Plant is a 165 megawatt gas-fired cogeneration facility located in Bayonne, New Jersey. The facility is primarily owned by an affiliate of Cogen Technologies, Inc. We own an indirect 7.5% limited partnership interest in the facility. Electricity generated by the Bayonne Power Plant is sold under various power sales agreements to Jersey Central Power & Light Company and Public Service Electric and Gas Company of New Jersey. The Bayonne Power Plant also sells steam to two industrial entities. During 1998, the Bayonne Power Plant generated approximately 1,399,860,000 kilowatt hours of electrical energy and approximately $116.6 million in revenue.
Auburndale Power Plant. The Auburndale Power Plant is a 150 megawatt gas-fired cogeneration facility located near the city of Auburndale, Florida. Electricity generated by the Auburndale Power Plant is sold under various power sales agreements to Florida Power Corporation ("FPC"), Enron Power Marketing and Sonat Power Marketing. Auburndale sells 131.18 megawatts of capacity and energy to FPC under three power sales agreements, each terminating at the end of 2013. The Auburndale Power Plant sells steam under two steam purchase and sale agreements. One agreement is with Cutrale Citrus Juices, USA, an affiliate of Sucocitro Cutrale LTDA, expiring on July 1, 2014. The second agreement is with Todhunter International, Inc., doing business as Florida Distillers Company, expiring on July 1, 2009. During 1998, the Auburndale Power Plant generated approximately 1,022,146,000 kilowatt hours of electrical energy and approximately $49.6 million in revenue.
Sumas Power Plant. The Sumas Power Plant is a 125 megawatt gas-fired, combined cycle cogeneration facility located in Sumas, Washington. We currently hold an ownership interest in the Sumas Power Plant, which entitles us to receive certain scheduled distributions during the next two years. Upon receipt of the scheduled distributions, we will no longer have any ownership interest in the Sumas Power Plant. Electrical energy generated by the Sumas Power Plant is sold to Puget Sound Power & Light Company ("Puget") under the terms of a power sales agreement terminating in 2013. Under the power sales agreement, Puget has agreed to purchase an annual average of 123 megawatts of electrical energy. In addition to the sale of electricity to Puget, pursuant to a long-term steam supply and dry kiln lease agreement, the Sumas Power Plant produces and sells approximately 23,000 lbs/hr of low pressure steam to an adjacent lumber-drying facility owned by Sumas, which has been leased to and is operated by Socco, Inc. During 1998, the Sumas Power Plant generated approximately 915,227,280 kilowatt hours of electrical energy and approximately $49.6 million of total revenue.
King City Power Plant. The King City Power Plant is a 120 megawatt gas-fired, combined-cycle cogeneration facility located in King City, California. We operate the King City Power Plant under a long-term operating lease for this facility with BAF Energy ("BAF"), terminating in 2018. Electricity generated by the King City Power Plant is sold to Pacific Gas and Electric Company ("PG&E") under a power sales agreement terminating in 2019. The power sales agreement contains payment provisions for capacity and energy. In addition to the sale of electricity to PG&E, the King City Power Plant produces and sells thermal energy to a thermal host, Basic Vegetable Products, Inc., an affiliate of BAF, under a long-term contract coterminous with the power sales agreement. During 1998, the King City Power Plant generated approximately 428,825,000 kilowatt hours of electrical energy and approximately $45.6 million of total revenue.
Gilroy Power Plant. The Gilroy Power Plant is a 120 megawatt gas-fired cogeneration facility located in Gilroy, California. Electricity generated by the Gilroy Power Plant is sold to PG&E under a power sales agreement terminating in 2018. In addition, the Gilroy Power Plant produces and sells thermal energy to a thermal host, Gilroy Foods, Inc., under a long-term contract that is coterminous with the power sales
agreement. During 1998, the Gilroy Power Plant generated approximately 477,628,000 kilowatt hours of electrical energy for sale to PG&E and approximately $39.3 million in revenue.
Kennedy International Airport Power Plant. The Kennedy International Airport Power Plant is a 107 megawatt gas-fired cogeneration facility located at John F. Kennedy International Airport in Queens, New York. The facility is owned and operated by KIAC Partners ("KIAC"). We own an indirect 50% general partnership interest in KIAC. Electricity and thermal energy generated by the Kennedy International Airport Power Plant is sold to the Port Authority, and incremental electric power is sold to Consolidated Edison Company of New York, the New York Power Authority and other utility customers. Electric power and chilled and hot water generated by the Kennedy International Airport Power Plant is sold to the Port Authority under an energy purchase agreement that expires November 2015. The Port Authority has a minimum thermal take requirement in an amount sufficient to maintain the Kennedy International Airport Power Plant's QF status. For 1998, the Kennedy International Airport Power Plant generated approximately 533,755,000 kilowatt hours of electrical energy, 266,252 mmbtu of chilled water and 178,405 mmbtu of hot water for sale to the Port Authority, and generated approximately $56.1 million in revenue.
Pittsburg Power Plant. The Pittsburg Power Plant is a 70 megawatt gas-fired cogeneration facility, located at The Dow Chemical Company's ("Dow") Pittsburg, California chemical facility. We sell up to 18 megawatts of electricity to Dow under a power sales agreement expiring in 2008. Surplus energy is sold to PG&E under an existing power sales agreement. In addition, we sell approximately 200,000 lbs/hr of steam to Dow under an energy sales agreement expiring in 2003 and to USS-POSCO Industries' nearby steel mill under a process steam contract expiring in 2001. From its acquisition, in July 1998, through the end of 1998, the Pittsburg Power Plant generated approximately 92,358,000 kilowatt hours of electrical energy to Dow and PG&E and approximately $9.4 million in revenue.
Sonoma Power Plant. The Sonoma Power Plant consists of a 60 megawatt geothermal power plant and associated steam fields located in Sonoma County, California. Electricity generated by the Sonoma Power Plant is sold to the Sacramento Municipal Utility District ("SMUD") under a 50 megawatt agreement terminating in 2001. In addition, SMUD has the option to purchase 10 megawatts of peak power production through 2005. We market the excess electricity into the California power market. From its acquisition, in June 1998, through the end of 1998, the Sonoma Power Plant generated approximately 215,433,000 kilowatt hours of electrical energy and approximately $6.2 million in revenue.
Bethpage Power Plant. The Bethpage Power Plant is a 57 megawatt gas-fired, combined cycle cogeneration facility located adjacent to a Northrup Grumman Corporation ("Grumman") facility in Bethpage, New York. Electricity and steam generated by the Bethpage Power Plant are sold to Grumman under an energy purchase agreement expiring August 2004. Electric power not sold to Grumman is sold to Long Island Power Authority ("LIPA") under a generation agreement also expiring August 2004. Grumman is also obligated to purchase a minimum of 158,000 klbs of steam per year from the Bethpage Power Plant. For 1998, the Bethpage Power Plant generated approximately 474,991,000 kilowatt hours of electrical energy for sale to Grumman and LIPA and approximately $32.9 million in revenue.
Greenleaf 1 Power Plant. The Greenleaf 1 Power Plant is a 49.5 megawatt gas-fired cogeneration facility located near Yuba City, California. We operate this facility under an operating lease with Union Bank of California, terminating in 2014 (the "Greenleaf Lease"). Electricity generated by the Greenleaf 1 Power Plant is sold to PG&E under a power sales agreement terminating in 2019 which contains payment provisions for capacity and energy. In addition, the Greenleaf 1 Power Plant sells thermal energy, in the form of hot exhaust to dry wood waste, to a thermal host which is owned and operated by us. For 1998, the Greenleaf 1 Power Plant generated approximately 326,543,000 kilowatt hours of electrical energy for sale to PG&E and approximately $17.8 million in revenue.
Greenleaf 2 Power Plant. The Greenleaf 2 Power Plant is a 49.5 megawatt gas-fired cogeneration facility located near Yuba City, California. This facility is also operated by us under the Greenleaf Lease. Electricity generated by the Greenleaf 2 Power Plant is sold to PG&E under a power sales agreement terminating in 2019 which includes payment provisions for capacity and energy. In addition to the sale of electricity to PG&E, the Greenleaf 2 Power Plant sells thermal energy to Sunsweet Growers, Inc. pursuant to a 30-year contract. For
1998, the Greenleaf 2 Power Plant generated approximately 377,101,000 kilowatt hours of electrical energy for sale to PG&E and approximately $20.3 million in revenue.
Stony Brook Power Plant. The Stony Brook Power Plant is a 40 megawatt gas-fired cogeneration facility located on the campus of the State University of New York at Stony Brook, New York ("SUNY"). The facility is owned by Nissequogue Cogen Partners ("NCP"). We own an indirect 50% general partner interest in NCP. Steam and electric power is sold to SUNY under an energy supply agreement expiring in 2023. Under the energy supply agreement, SUNY is required to purchase, and the Stony Brook Power Plant is required to provide, all of SUNY's electric power and steam requirements up to 36.125 megawatts of electricity and 280,000 lbs/hr of process steam. The remaining electricity is sold to LIPA under a long-term agreement. LIPA is obligated to purchase electric power generated by the facility not required by SUNY. SUNY is required to purchase a minimum of 402,000 klbs per year of steam. For 1998, the Stony Brook Power Plant generated approximately 326,584,000 kilowatt hours of electrical energy and 1,185,000 klbs of steam for sale to SUNY and LIPA and approximately $31.1 million in revenue.
Agnews Power Plant. The Agnews Power Plant is a 29 megawatt gas-fired, combined-cycle cogeneration facility located on the East Campus of the state-owned Agnews Developmental Center in San Jose, California. We hold a 20% ownership interest in GATX Calpine-Agnews, Inc., which is the sole stockholder of O.L.S. Energy-Agnews, Inc. ("O.L.S. Energy-Agnews"). O.L.S. Energy-Agnews leases the Agnews Power Plant under a sale leaseback arrangement. Electricity generated by the Agnews Power Plant is sold to PG&E under a power sales agreement terminating in 2021 which contains payment provisions for capacity and energy. In addition, the Agnews Power Plant produces and sells electricity and approximately 7,000 lbs/hr of steam to the Agnews Developmental Center pursuant to a 30-year energy service agreement. During 1998, the Agnews Power Plant generated approximately 215,180,000 kilowatt hours of electrical energy and total revenue of $11.7 million.
Watsonville Power Plant. The Watsonville Power Plant is a 28.5 megawatt gas-fired, combined cycle cogeneration facility located in Watsonville, California. We operate the Watsonville Power Plant under an operating lease with the Ford Motor Credit Company, terminating in 2009. Electricity generated by the Watsonville Power Plant is sold to PG&E under a power sales agreement terminating in 2009 which contains payment provisions for capacity and energy. During 1998, the Watsonville Power Plant produced and sold steam to Farmers Processing, a food processor. In addition, the Watsonville Power Plant sold process water produced from its water distillation facility to Farmer's Cold Storage, Farmer's Processing and Cascade Properties. For 1998, the Watsonville Power Plant generated approximately 206,007,000 kilowatt hours of electrical energy for sale to PG&E and approximately $11.4 million in revenue.
West Ford Flat Power Plant. The West Ford Flat Power Plant consists of a 27 megawatt geothermal power plant and associated steam fields located in northern California. Electricity generated by the West Ford Flat Power Plant is sold to PG&E under a power sales agreement terminating in 2008 which contains payment provisions for capacity and energy. During 1998, the West Ford Flat Power Plant generated approximately 235,529,000 kilowatt hours of electrical energy for sale to PG&E and approximately $34.6 million of revenue.
Bear Canyon Power Plant. The Bear Canyon Power Plant consists of a 20 megawatt geothermal power plant and associated steam fields located in northern California, two miles south of the West Ford Flat Power Plant. Electricity generated by the Bear Canyon Power Plant is sold to PG&E under two 10 megawatt power sales agreements terminating in 2008 which contain payment provisions for capacity and energy. During 1998, the Bear Canyon Power Plant generated approximately 176,508,000 kilowatt hours of electrical energy and approximately $20.4 million of revenue.
Aidlin Power Plant. The Aidlin Power Plant consists of a 20 megawatt geothermal power plant and associated steam fields located in northern California. We hold an indirect 5% ownership interest in the Aidlin Power Plant. Electricity generated by the Aidlin Power Plant is sold to PG&E under two 10 megawatt power sales agreements terminating in 2009 which contain payment provisions for capacity and energy. During 1998, the Aidlin Power Plant generated approximately 170,046,000 kilowatt hours of electrical energy and revenue of $24.4 million.
PROJECT DEVELOPMENT AND ACQUISITIONS
We are actively engaged 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 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, financing and operations.
ACQUISITIONS
We will 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 an ownership interest in facilities that offer us attractive opportunities for revenue and 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. We generally seek to obtain a significant equity interest in a project and to obtain the operation and maintenance contract for that project. See "-- Strategy" and "Risk Factors -- " We face risks associated with our power project development and acquisition activities.
We have grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields. We believe that although the domestic power industry is undergoing consolidation and that significant acquisition opportunities are available, we are likely to confront significant competition for acquisition opportunities. In addition, there can be no assurance that we will continue to identify attractive acquisition opportunities at favorable prices or, to the extent that any opportunities are identified, that we will be able to consummate such acquisitions.
Pending Acquisitions
Sonoma County Power Plants. On January 26, 1999, we announced that we had entered into definitive agreements to acquire 12 geothermal facilities from PG&E in Sonoma County, California (the "Sonoma County Power Plants"), having a combined capacity of 544 megawatts, for an aggregate investment of $139.0 million. We currently own a portion of the steam fields supplying the Sonoma County Power Plants and have agreed to purchase the remaining steam fields from Unocal Corporation for $101.0 million. We expect to complete the steam field acquisition in March 1999 and the acquisition of the Sonoma County Power Plants upon receipt of approval by the California Public Utilities Commission ("CPUC") and FERC, currently anticipated to occur in April 1999. There can be no assurance that such approvals will be obtained or that we will successfully complete these acquisitions.
Lake County Power Plants. On December 1, 1998, we announced that we had exercised our right of first refusal to acquire two geothermal facilities from PG&E in Lake County, California (the "Lake County Power Plants"), having a combined capacity of 150 megawatts, for $75.3 million. We currently own the steam field operations currently supplying the Lake County Power Plants. We expect to complete this acquisition upon receipt of the approval by the CPUC and FERC, currently anticipated to occur in April 1999. There can be no assurance that such approvals will be obtained or that we will successfully consummate this acquisition.
We anticipate that these acquisitions will enable us to consolidate our operations in The Geysers into a single ownership structure and to integrate the power plant and steam field operations, allowing us to optimize the efficiency and performance of the facilities. We believe that these acquisitions will provide us with significant synergies that leverage our expertise in geothermal power generation and position us to benefit from the demand for "green" energy in the competitive market.
PROJECT DEVELOPMENT
The development of power generation projects involves numerous elements, including evaluating and selecting development opportunities, designing and engineering the project, obtaining power sales agreements, acquiring necessary land rights, permits and fuel resources, obtaining financing and managing construction. We intend to focus primarily on development opportunities where we are able to capitalize on our expertise in implementing an innovative and fully integrated approach to project development in which we control the entire development process. Utilizing this approach, we believe that we are able to enhance the value of our projects throughout each stage of development in an effort to maximize our return on investment.
We are pursuing the development of highly efficient, low-cost power plants that seek to take advantage of inefficiencies in the electricity market. We intend to sell all or a portion of the power generated by such plants into the competitive market through a portfolio of short-, medium-and long-term power sales agreements. We expect that these projects will represent a prototype for our future plant developments. See "-- Strategy" and "Risk Factors -- " We face risks associated with our power project development and acquisition activities.
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 power sales agreements, governmental permits and approvals, fuel supply and transportation agreements, sufficient equity capital and debt financing, electrical transmission agreements, site agreements and construction contracts, and there can be no assurance that we will be successful in doing so. In addition, project development is subject to certain 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 long-term power sales agreement, entering into power marketing transactions, and obtaining all required governmental permits and approvals, the development of a power project may require us to expend significant sums for preliminary engineering, permitting and legal and other expenses before it can be determined whether a project is feasible, economically attractive or financeable. If we were unable to complete the development of a facility, we would generally not be able to recover our investment in such a facility. 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. As a result of competition, it may be difficult to obtain a power sales agreement for a proposed project, and the prices offered in new power sales agreements for both electric capacity and energy may be less than the prices in prior agreements. We cannot assure that we will be successful in the development of power generation facilities in the future.
Projects Under Construction
Westbrook Power Plant. In February 1999, we acquired from Genesis Power Corporation ("Genesis"), a New England based power developer, the development rights to a 540 megawatt gas-fired combined-cycle power plant to be located in Westbrook, Maine (the "Westbrook Power Plant"). It is estimated that the development of the Westbrook Power Plant will cost approximately $300.0 million. Construction commenced in February 1999 and commercial operation is scheduled for early 2001. Upon completion, the Westbrook Power Plant will be operated by our company. It is anticipated that the output generated by the Westbrook Power Plant will be sold into the New England power market and to wholesale and retail customers in the northeastern United States.
Pasadena Expansion. We are currently expanding the Pasadena Power Plant by an additional 510 megawatts. Construction began in November 1998 and commercial operation is expected to begin in June 2000. The electricity output from this expansion will be sold into the competitive market through our power sales activities.
Tiverton Power Plant. In September 1998, we invested $40.0 million of equity in the development of a 265 megawatt gas-fired power plant to be located in Tiverton, Rhode Island (the "Tiverton Power Plant"). The Tiverton Power Plant is being developed by Energy Management Inc. ("EMI"). It is estimated that the development of the Tiverton Power Plant will cost approximately $172.5 million. For our investment in the Tiverton Power Plant, we will earn 62.8% of the Tiverton Power Plant project cash flow until a specified pre-tax return is reached, whereupon our company and EMI will share projected cash flows equally through the
remaining life of the project. Construction commenced in late 1998 and commercial operation is currently scheduled for 2000. Upon completion, the Tiverton Power Plant will be operated by EMI and will sell its output in the New England power market and to wholesale and retail customers in the northeastern United States.
Rumford Power Plant. In November 1998, we invested $40.0 million of equity in the development of a 265 megawatt gas-fired power plant to be located in Rumford, Maine (the "Rumford Power Plant"). The Rumford Power Plant is being developed by EMI. It is estimated that the development of the Rumford Power Plant will cost approximately $160.0 million. For our investment in the Rumford Power Plant, we will earn 66.7% of the Rumford Power Plant project cash flow until a specified pre-tax return is reached, whereupon our company and EMI will share projected cash flows equally through the remaining life of the project. Construction commenced in late 1998 and commercial operation is currently scheduled for 2000. Upon completion, the Rumford Power Plant will be operated by EMI and will sell its output in the New England power market and to wholesale and retail customers in the northeastern United States.
Dighton Power Plant. In October 1997, we invested $16.0 million in the development of a 169 megawatt gas-fired combined-cycle power plant to be located in Dighton, Massachusetts (the "Dighton Power Plant"). This investment, which is structured as subordinated debt, will provide us with a preferred payment stream at a rate of 12.07% per annum for a period of twenty years from the commercial operation date. It is estimated that the development of the Dighton Power Plant will cost approximately $120.0 million. The Dighton Power Plant is being developed by EMI. Construction commenced in the fourth quarter of 1997 and commercial operation is scheduled to begin in May 1999. Upon completion, the Dighton Power Plant will be operated by EMI and will sell its output into the New England power market and to wholesale and retail customers in the northeastern United States.
Clear Lake Expansion. We are currently expanding the Clear Lake Plant by 35 megawatts through certain capital improvements. Improvements began in late 1998 and commercial operation is expected to begin in December 1999. The electricity output from this expansion will be sold into the competitive market through our power sales activities.
Announced Development Projects
Delta Energy Center. On February 3, 1999, we, together with Bechtel Enterprises, announced plans to develop an 880 megawatt gas-fired cogeneration project in Pittsburg, California (the "Delta Energy Center"). The Delta Energy Center will provide steam and electricity to the nearby Dow Chemical Company facility and market the excess electricity into the California power market. We anticipate that construction will commence in early 2000 and that operation of the facility will commence in 2002. We are currently pursuing regulatory agency permits for this project. On February 3, 1999, our company and Bechtel announced that the Delta Energy Center has met the California Energy Commission's Data Adequacy requirements in its Application for Certification.
Magic Valley Power Plant. On May 26, 1998, we announced that we had signed a 20-year power sales agreement to provide electricity to the Magic Valley Electric Cooperative, Inc. of Mercedes, Texas beginning in 2001. The power will be supplied by our Magic Valley Generating Station, a 700 megawatt natural gas-fired power plant under development in Edinburg, Texas. Magic Valley, a 51,000 member non-profit electric cooperative, initially will purchase from 250 to 400 megawatts of capacity, with an option to purchase additional capacity. We are marketing additional capacity to other wholesale customers, initially targeting south Texas. Permitting for the Magic Valley plant is underway, with construction expected to begin in late 1999.
South Point Power Plant. In May 1998, we announced that we had entered into a long-term lease agreement with the Fort Mojave Indian Tribe to develop a 500 megawatt gas-fired power plant (the "South Point Power Plant") on the tribe's reservation in Mojave County, Arizona. The electricity generated will be sold to the Arizona, Nevada and California power markets. We anticipate that the South Point Power Plant will commence operation in 2000.
Sutter Power Plant. In February 1997, we announced plans to develop a 500 megawatt gas-fired combined cycle project in Sutter County, in northern California (the "Sutter Power Plant"). The Sutter Power Plant would be northern California's first newly constructed power plant. The Sutter Power Plant is expected to provide electricity to the deregulated California power market commencing in the year 2000. We are currently pursuing regulatory agency permits for this project. On January 21, 1998, we announced that the Sutter Power Plant has met the California Energy Commission's Data Adequacy requirements in its Application for Certification.
GAS FIELDS
Montis Niger. On January 31, 1997, we purchased Montis Niger, Inc. a gas production and pipeline company operating primarily in the Sacramento Basin in northern California. On July 25, 1997, Montis Niger, Inc. was renamed Calpine Gas Company. As of January 1, 1998, Calpine Gas Company had approximately 8.1 billion cubic feet of proven natural gas reserves and approximately 13,837 gross acres and 13,738 net acres under lease in the Sacramento Basin. In addition, Calpine Gas Company owns and operates an 80-mile pipeline delivering gas to the Greenleaf 1 and 2 Power Plants which had been either produced by Calpine Gas Company or purchased from third parties. Calpine Gas Company currently supplies approximately 79% of the fuel requirements for the Greenleaf 1 and 2 Power Plants.
Sheridan. On January 27, 1999, we announced that we had acquired a 20% interest in 82 billion cubic feet of proven natural gas reserves located in the Sacramento Basin in northern California. Sheridan Energy, Inc. ("Sheridan") owns the remaining 80% interest in these reserves. In addition, we signed a 10-year agreement with Sheridan under which we will purchase all of Sheridan's Sacramento Basin production, which currently approximates 20,000 mmbtu per day.
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 its energy generation facilities. Federal laws and regulations govern transactions by electrical and gas utility companies, the types of fuel which may be utilized by an electric generating plant, the type of energy which may be produced by such a plant and the ownership of a plant. State utility regulatory commissions must approve the rates and, in some instances, other terms and conditions under which public utilities purchase electric power from independent producers and sell retail electric power. 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 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).
A domestic electricity generating project must be a 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 (the "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 currently meets the requirements under PURPA necessary for QF status.
PURPA provides two primary benefits to QFs. First, QFs generally are relieved of compliance with extensive federal, state and local regulations that control the financial structure of an electric generating plant and the prices and terms on which electricity may be sold by the plant. Second, the 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. The FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates lower than the utility's 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 or hydroelectric QF or other qualifying small power producer) must not be controlled or more than 50% owned by an electric utility or by most electric utility holding companies, or a subsidiary 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 trigger certain rights of termination under the power sales agreement, could subject the project to rate regulation as a public utility under the FPA and state law and could result in us inadvertently becoming a public 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 public 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.
Under the Energy Policy Act of 1992, if a project can be qualified as an exempt wholesale generator ("EWG"), 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 and approval of the utility would be required. In addition, the project would be required to cease selling electricity to any retail customers (such as the thermal energy customer) 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 amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at avoided costs. We do not know whether such legislation will be passed or what form it may take. We believe that if any such legislation is passed, it would
apply only to new projects. As a result, although such legislation may adversely affect our ability to develop new projects, we believe it would not affect our existing QFs. There can be no assurance, however, that any legislation passed would not adversely impact our existing 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 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-QFs 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 the amendments could benefit us by expanding our ability to own and operate facilities that do not qualify for QF status, but they have also resulted in increased competition by allowing utilities to develop such facilities which are not subject to the constraints of PUHCA.
Federal Natural Gas Transportation Regulation
We have an ownership interest in 18 gas-fired cogeneration projects. The cost of natural gas is ordinarily the largest expense (other than debt costs) of a project and is critical to the project's economics. The risks associated with using natural gas can include the need to arrange 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, and whether firm or non-firm transportation is purchased); 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, pipeline rates and terms and conditions for such services are subject to continuing FERC oversight.
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 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 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 an independent power contract to the utility's retail customer. However, a regulatory commission under certain circumstances may disallow the full reimbursement to a utility for the cost to purchase power from a QF. In addition, retail sales of electricity or thermal energy by an independent power producer may be subject to PUC regulation depending on state law. Independent power producers which are not QFs under PURPA, or EWGs pursuant to the Energy Policy Act of 1992, are considered to be public utilities in many states and are subject to broad regulation by a PUC, ranging from requirement of certificate of public convenience and necessity to regulation of organizational, accounting, financial and other corporate matters. States may assert jurisdiction over the siting and
construction of electric generating facilities including QFs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities.
In the State of California, restructuring legislation was enacted in September 1996 and was implemented in 1998. This legislation established an Independent Systems Operator ("ISO") responsible for centralized control and efficient and reliable operation of the state-wide electric transmission grid, and a Power Exchange responsible for an efficient competitive electric energy auction open on a non-discriminatory basis to all electric services providers. Other provisions include the quantification and qualification of utility stranded costs to be eligible for recovery through competitive transition charges ("CTC"), market power mitigation through utility divestiture of fossil generation plants, the unbundling and establishment of rate structure for historical utility functions, the continuation of public purpose programs and issues related to issuance of rate reduction bonds.
The California Energy Commission ("CEC") and Legislature have responsibility for development of a competitive market mechanism for allocation and distribution of funds made available by the legislation for enhancement of in-state renewable resource technologies and public interest research and development programs. Funds are to be available through the four-year transition period to a fully competitive electric services industry.
In addition to the significant opportunity provided for power producers such as us through implementation of customer choice (direct access), the California restructuring legislation both recognizes the sanctity of existing contracts, provides for mitigation of utility horizontal market power through divestiture of fossil generation and provides funds for continuation of public services programs including fuel diversity through enhancement for in-state renewable technologies (includes geothermal) for the four-year transition period to a fully competitive electric services industry.
Other states in which we conduct operations either have implemented or are actively considering similar restructuring legislation.
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 LDC's generally applicable tariffs do not cover the proposed transaction. LDC rates are usually subject to continuing PUC oversight.
REGULATION OF CANADIAN GAS
The Canadian natural gas industry is subject to extensive regulation by governmental authorities. At the federal level, a party exporting gas from Canada must obtain an export license from the Canadian 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 provincial authorities before natural gas may be removed from the province, and provincial authorities may 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 and the construction and operation of power projects are subject to extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, 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 are in compliance with federal performance standards mandated for such plants under the Clean Air Act and the 1990 Amendments. With respect to its Aidlin geothermal plant and one of its steam field pipelines, our operations have, in certain instances, necessitated variances under applicable California air pollution control laws. However, we believe that we are in material compliance with such laws with respect to such facilities.
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 a wastewater and storm water discharge permit for wastewater and runoff, respectively, from certain of our facilities. We believe that, with respect to our geothermal operations, we are exempt from newly promulgated federal storm water requirements. We believe that we are in material compliance with applicable discharge requirements under the Clean Water Act.
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 its 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. We believe that our operations are in material compliance with 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 ("EPA") 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 sends 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.
RISK FACTORS
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, 1998, our total consolidated indebtedness was $1.1 billion, our total consolidated assets were $1.7 billion and our stockholders' equity was $287.0 million. Whether we will be able to meet our
debt service obligations and to repay our outstanding indebtedness will be dependent primarily upon the performance of our power generation facilities.
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, and
- limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in government regulation.
The operating and financial restrictions and covenants in our existing debt agreements, including the indentures relating to our outstanding senior notes and our $100.0 million revolving credit facility, contain restrictive covenants. Among other things these restrictions limit or prohibit our ability to:
- incur indebtedness,
- make prepayments of indebtedness in whole or in part,
- pay dividends,
- make investments,
- engage in transactions with affiliates,
- create liens,
- sell assets, and
- acquire facilities or other businesses.
Also, if our management or ownership changes, our indentures may require us to make an offer to purchase our outstanding notes, including the senior notes. We cannot assure you that we will have the financial resources necessary to purchase such notes, and our board of directors cannot waive provisions in the indentures.
We believe that our cash flow from operations, together with other available sources of funds, including borrowings under our existing borrowing arrangements, will be adequate to pay principal and interest on our debt and to enable us to comply with the terms of our debt agreements. If we are unable to comply with the terms of our debt agreements and fail to generate sufficient cash flow from operations in the future, we may be required to refinance all or a portion of our existing 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 debt agreements. If cash flow is insufficient and refinancing or additional financing is unavailable, we may be forced to default on our 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.
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 on and principal of our senior notes. The non-recourse project 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 other obligations, including operating expenses, debt service and reserves.
Our subsidiaries and other affiliates are separate and distinct legal entities and have no obligation to pay any amounts due on our senior notes, and do not guarantee the payment of interest on or principal of these notes. The right of our senior note holders 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).
While the indentures impose limitations on our ability and the ability of our subsidiaries to incur additional indebtedness, the indentures do not limit the amount of non-recourse project financing that our subsidiaries may incur to finance new power generation facilities.
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 and the cost of the financing are dependent upon numerous factors. These factors include:
- general economic and capital market conditions,
- conditions in energy markets,
- regulatory developments,
- credit availability from banks or other lenders,
- 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.
Financing for new facilities may not be available to us on acceptable terms in the future. We have financed our existing power generation facilities using a variety of leveraged financing structures, primarily consisting of non-recourse project financing and lease obligations. As of December 31, 1998, we had approximately $1.1 billion of total consolidated indebtedness, of which approximately 11% represented non-recourse project financing. Each non-recourse project financing and lease obligation is structured to be fully paid out of cash flow provided by the facility or facilities. 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. We do not believe the existence of non-recourse or lease financing will significantly affect our ability to continue to borrow funds in the future in order to finance new facilities. However, it is possible that we may be unable to obtain the financing required to develop our power generation facilities on terms satisfactory to us.
We have from time to time guaranteed certain obligations of our subsidiaries and other affiliates. Our lenders or lessors may also require us to guarantee the indebtedness for future facilities. This would render our general corporate funds vulnerable in the event of a default by the facility or related subsidiary. Additionally, 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.
Revenue under some of our power sales agreements may be reduced significantly upon their expiration or termination. Most of the electricity we generate from our existing portfolio is sold under long-term power sales agreements that expire at various times. When the terms of each of these power sales agreements expire, it is possible that the price paid to us for the generation of electricity may be reduced significantly, which would greatly reduce our revenue under such agreements. The fixed price periods in some of our long-term power sales agreements have recently expired, and the electricity under those agreements is now sold at a fluctuating market price. For example, the price for electricity for two of our power plants, the Bear Canyon (20 megawatts) and West Ford Flat (27 megawatts) power plants, was 13.83 cents per kilowatt hour under the fixed price periods that recently expired for these facilities, and is now set at the energy clearing price, which averaged 2.66 cents per kilowatt hour during 1998. As a result, our energy revenue under these power sales agreements has been materially reduced. This reduction may lower our results of operations. We expect the forecasted decline in energy revenues will be partially mitigated by decreased royalties and planned operating cost reductions at these facilities. In addition, we will continue our strategy of offsetting these reductions through our acquisition and development program.
Our power project development and acquisition activities may not be successful. The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, we must generally obtain:
- necessary power generation equipment,
- governmental permits and approvals,
- fuel supply and transportation agreements,
- sufficient equity capital and debt financing,
- electrical transmission agreements, 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 and legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. If we were unable to complete the development of a facility, we would generally 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.
We have grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields. We believe that although the domestic power industry is undergoing consolidation and that significant acquisition opportunities are available, we are likely to confront significant competition for acquisition opportunities. In addition, we may be unable to continue to identify attractive acquisition opportunities at favorable prices or, to the extent that any opportunities are identified, we may be unable to complete the acquisitions.
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 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 could result in losing our interest in a power generation facility.
In addition, 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.
Our power generation facilities may not operate as planned. Upon completion of our pending acquisitions and projects currently under construction, we will operate 31 of the 40 power plants in which we will have an interest. The continued operation of power generation facilities 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. As of December 31, 1998, our power generation facilities have operated at an average availability of approximately 96.5%. 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 the power generation facility.
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 fluids,
- the geology of the reservoir,
- the total amount of recoverable reserves,
- operating expenses relating to the extraction of fluids,
- price levels relating to the extraction of fluids, 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 lower our results of operations.
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. While we have extensive experience in the operation and development of geothermal energy resources and in preparing such estimates, 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.
We depend on our electricity and thermal energy customers. Each of our power generation facilities currently relies on one or more power sales agreements with one or more utility or other customers for all or substantially all of such facility's revenue. In addition, the sales of electricity to two utility customers during 1998 comprised approximately 64% of our total revenue during that year. The loss of any one power sales agreement with any of these customers 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.
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 require numerous permits, approvals and certificates from appropriate 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 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 new laws and regulations may become applicable to us that may have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed facilities may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain 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.
Our operations are potentially subject to the provisions of various energy laws and regulations, including the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as amended ("PUHCA"), and state and local regulations. PUHCA provides for the extensive regulation of public utility holding companies and their subsidiaries. PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and owners of QFs certain exemptions from certain federal and state regulations, including rate and financial regulations.
Under present 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 exempt wholesale generators ("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility must be not more than 50% owned by an electric utility company or electric utility holding company. 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. Any geothermal power facility which produces up to 80 megawatts of electricity and meets PURPA ownership requirements is considered a QF.
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 our other power plants could lose QF status because, under FICC 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 any 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, including our senior notes. See "Business -- Government Regulation -- Federal Energy Regulation."
Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at prices based on avoided costs of energy. We do not know whether this legislation will be passed or, if passed, what form it may take. We cannot assure that any legislation passed would not adversely impact 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. In particular, the state of California has restructured its electric industry by providing for a phased-in competitive power generation industry, with a power pool and an independent system operator, and for direct access to generation for all
power purchasers outside the power exchange under certain circumstances. Although existing QF power sales contracts are to be honored under such restructuring, and all of our California operating projects are QFs, until the new system is fully implemented, it is impossible to predict what impact, if any, it may have on the operations of those projects.
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 and short-, medium- and long-term supply contracts. 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. 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. If gas is not available, or if gas prices increase above the fuel component of the facilities' power sales agreements, there could be a negative impact on our results of operations.
Competition could adversely affect our performance. The power generation industry is characterized by intense competition. We encounter competition from utilities, industrial companies and other power producers. In recent years, there has been increasing competition in an effort to obtain power sales agreements. This competition has contributed to a reduction in electricity prices. In addition, many states have implemented or are considering regulatory initiatives designed to increase competition in the domestic power industry. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity.
Our international investments may face uncertainties. We have one investment in geothermal steam fields located in Mexico and may pursue additional international investments. 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:
- risks of fluctuations in currency valuation,
- currency inconvertibility,
- expropriation and confiscatory taxation,
- increased regulation, and
- approval requirements and governmental policies limiting returns to foreign investors.
We depend on our senior management. Our success is largely dependent on the skills, experience and efforts of our senior management. The loss of the services of one or more members of our senior management could have a negative effect on our business and development.
Seismic disturbances could damage our project. 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 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:
- the timing and size of acquisitions,
- the completion of development projects, and
- variations in levels of production.
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 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:
- announcements of developments related to our business,
- fluctuations in our results of operations,
- sales of substantial amounts of our securities into the marketplace,
- general conditions in our industry or the worldwide economy,
- 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 thus, the current market price may not be indicative of future market prices.
YEAR 2000 COMPLIANCE
Year 2000 Compliance -- The "Year 2000 problem" refers to the fact that some computer hardware, software and embedded systems were designed to read and store dates using only the last two digits of the year.
We are coordinating our efforts to address the impact of Year 2000 on our business through a Year 2000 Project Team comprised of representatives from each business unit and our Year 2000 Project Office. The Year 2000 Project Office is charged with addressing additional Year 2000 related issues including, but not limited to, business continuation and other contingency planning. The Year 2000 Project Team meets regularly to monitor the efforts of assigned staff and contractors to identify, remediate and test our technology.
The Year 2000 Project Team is focusing on four separate technology domains:
- corporate applications, which include core business systems,
- non-information technology, which includes all operating and control systems,
- end-user computing systems (that is, systems that are not considered core business systems but may contain date calculations), and
- business partner and vendor systems.
Corporate Applications -- Corporate applications are those major core systems, such as customer information, human resources and general ledger, for which our Management Information Systems department has responsibility. We utilize PeopleSoft for our major core systems. The PeopleSoft applications we utilize are in operation and have been determined to be Year 2000 compliant.
Non-Information Technology/Embedded Systems -- Non-information technology includes such items as power plant operating and control systems, telecommunications and facilities-based equipment (e.g. telephones and two-way radios) and other embedded systems. Each business unit is responsible for the inventory and remediation of its embedded systems. In addition, we are working with the Electric Power Research Institute, a consortium of power companies, including investor-owned utilities, to coordinate vendor contacts and product evaluation. Because many embedded systems are similar across utilities, this concentrated effort should help to reduce total time expended in this area and help to ensure that our efforts are consistent with the efforts and practices of other power companies and utilities.
An Inventory phase for non-information technology/embedded systems was completed in October 1998. An Initial Assessment phase was completed in December 1998. We plan to complete remediation of non-compliant systems by the second quarter of 1999. To date, all embedded systems that we have identified can be upgraded or modified within our current schedule. The schedule for addressing Year 2000 issues with respect to mission critical embedded systems is as follows:
Testing of embedded systems is complex because some of the testing must be completed during power plant scheduled maintenance outages. Much of the testing will be accomplished in the spring of 1999 during regularly scheduled maintenance outage periods. At that time, at least one typical unit of each critical type will be tested by us or in cooperation with other power companies, and the requirement for further testing will be determined.
End-User Computing Systems -- Some of our business units have developed systems, databases, spreadsheets, etc. that contain date calculations. Compliance of individual workstations is also included in this domain. These systems comprise a relatively small percentage of the required modification in terms of both number and criticality.
Our end-user computing systems are being inventoried by each business unit and evaluated and remediated by our MIS staff. We have completed approximately 10% of remediation and testing of the end-user computing systems, and we expect to complete this process by mid-1999.
Business Partner and Vendor Systems -- We have contracts with business partners and vendors who provide products and services to us. We are vigorously seeking to obtain Year 2000 assurances from these third parties. The Year 2000 Project Team and appropriate business units are jointly undertaking this effort. We have sent letters and accompanying Year 2000 surveys to about 800 vendors and suppliers. Over 400 responses have been received as of January 31, 1999. These responses outline to varying degrees the approaches vendors are undertaking to resolve Year 2000 issues within their own systems. Follow-up letters will be sent to those vendors who have not responded or whose responses were inadequate.
Contingency Planning -- Contingency and business continuation planning are in various stages of development for critical and high-priority systems. Our existing disaster response plan and other contingency plans are currently being evaluated and will be adopted for use in case of any Year 2000-related disruption. We expect to complete our contingency planning by September 1999.
Costs -- The costs of expected modifications are currently estimated to be approximately $1.7 million which will be charged to expense as incurred. From January 1, 1998 through December 31, 1998, $158,000 has been charged to expense. Approximately 9% of the estimated total cost was incurred in 1998, and the remainder will be incurred in 1999 and 2000. These costs have been and will be funded through operating cash flow. These estimates may change as additional evaluations are completed and remediation and testing progress.
Risks -- We currently expect to complete our Year 2000 efforts with respect to critical systems by mid-1999. This schedule and our cost estimates may be affected by, among other things, the availability of Year 2000 personnel, the readiness of third parties, the timing for testing our embedded systems, the availability of vendor resources to complete embedded system assessments and produce required component upgrades and our ability to implement appropriate contingency plans.
We produce revenues by selling power we produce to customers. We depend on transmission and distribution facilities that are owned and operated by investor-owned utilities to deliver power to our
customers. If either our customers or the providers of transmission and distribution facilities experience significant disruptions as a result of the Year 2000 problem, our ability to sell and deliver power may be hindered, which could result in a loss of revenue.
The cost or consequences of a materially incomplete or untimely resolution of the Year 2000 problem could adversely affect our future operations, financial results or our financial condition.
COMPETITION
The power generation industry is characterized by intense competition, and we encounter competition from utilities, industrial companies and other power producers. In recent years, there has been increasing competition in an effort to obtain power sales agreements, and this competition has contributed to a reduction in electricity prices. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power industry. In California, the CPUC issued decisions which provide for direct access for all customers as of April 1, 1998. Regulatory initiatives are also being considered in other states, including Texas, New York and states in New England. See "Business -- Government Regulation -- State Regulation." This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the future will increase this pressure.
EMPLOYEES
As of December 31, 1998, we employed 458 people. None of our employees are covered by collective bargaining agreements, and we have never experienced a work stoppage, strike or labor dispute. We consider relations with our employees to be good.
ITEM 2.
ITEM 2. PROPERTIES
Our principal executive office is located in San Jose, California, under a lease that expires in June 2001.
We, through our ownership of CGC and TPC, have leasehold interests in 109 leases comprising 27,263 acres of federal, state and private geothermal resource lands in The Geysers area in northern California. These leases comprise its West Ford Flat Power Plant, Bear Canyon Power Plant, PG&E Unit 13 and Unit 16 Steam Fields, SMUDGEO #1 Steam Fields and TPC's 100% undivided interest in the Thermal Power Company Steam Fields which are operated by Union Oil. In the Glass Mountain and Medicine Lake areas in northern California, we hold leasehold interests in 18 leases comprising approximately 25,028 acres of federal geothermal resource lands.
In general, under the 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 has complied with all the requirements and conditions material to their continued effectiveness. 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 cannot assure that we will decide to renew any expiring leases.
We own 77 acres in Sutter County, California where we operate the Greenleaf 1 & 2 Power Plants.
We own Calpine Gas Company, which leases property covering approximately 13,837 gross acres and 13,738 net acres.
We own the Texas City, Clear Lake, and Pasadena Power Plants, who lease 9, 21, and 18 acres, respectively.
We own 40 gross acres and 38 net acres in Edinburg, Texas where we are developing the Magic Valley project, a 700 megawatt power plant.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and certain other parties, including the Company. Some of Indeck's claims relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville Energy Limited Partnership from Northern Hydro Limited and Calpine Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously interfered with Indeck's contractual rights to purchase such interests and conspired with other parties to do so. Indeck is seeking $25.0 million in compensatory damages, $25.0 million in punitive damages, and the recovery of attorneys' fees and costs. In July 1998, the court granted motions to dismiss, without prejudice, the claims against Calpine Gordonsville, Inc. and Calpine Auburndale, Inc. In August 1998, Indeck filed an amended complaint and the defendants filed motions to dismiss. A hearing on those motions is scheduled for February 1999. The Company is unable to predict the outcome of these proceedings, but does not believe this will have a material adverse effect on the Consolidated Financial Statements.
There is currently a dispute between Texas-New Mexico Power Company ("TNP") and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear Lake Power Plant, regarding certain costs and other amounts that TNP has withheld from payments due under the power sales agreement from August 1997 until October 1998. TNP has withheld approximately $450,000 per month related to transmission charges. In October 1997, CLC filed a petition for declaratory order with the Texas Public Utilities Commission ("Texas PUC") requesting a declaration that TNP's withholding is in error, which petition is currently pending. Also, as of December 31, 1998, TNP has withheld approximately $7.7 million of standby power charges. In addition to the Texas PUC petition, CLC filed an action in Texas courts on October 2, 1997, alleging TNP's breach of the power sales agreement and is seeking refund of the standby charges. In October 1998, TNP and CLC reached an agreement in principle to settle all outstanding disputes. The parties are currently finalizing the documentation of the settlement which must be approved by the Texas PUC. Both the Texas PUC action and the court action have been put on hold pending completion of the settlement and we do not believe that these proceedings will have a materially adverse effect on the Consolidated Financial Statements.
An action was filed against Lockport Energy Associates, Limited Partnership ("LERA") and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG has requested the Court to direct NYPSC and the Federal Energy Regulatory Commission (the "FERC") to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated Public Utility Regulatory Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing to reform the NYSEG contract that was previously approved by the NYPSC. Although it is unable to predict the outcome of this case, in any event, the Company retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase the Company's interest in the Lockport Power Plant for $18.9 million, less equity distributions received by the Company, at any time before December 19, 2001.
The Company is involved in various other claims and legal actions arising out of the normal course of 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, although no assurance can be given in this regard.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information required hereunder is set forth under "Quarterly Consolidated Financial Data" included in Appendix F, Note 16 of the Notes to Consolidated Financial Statements to this report. The Company made no sales of unregistered equity securities in the last three years.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The information required hereunder is set forth under "Selected Consolidated Financial Data" included in Appendix F to this report.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required hereunder is set forth under "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in Appendix F to this report.
Item 7a.
Item 7a. Quantitative Qualitative Disclosure
The information required hereunder is set forth under "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in Appendix F to this report.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is set forth under "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Operations," "Consolidated Statements of Shareholder's Equity," "Consolidated Statements of Cash Flows," and "Notes to Consolidated Financial Statements" included in Appendix F of this report. Other financial information and schedules are included in Appendix F of this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE
None.
ITEM 10.
ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
Incorporated by reference from Proxy Statement relating to the 1999 Annual Meeting of Shareholders to be filed.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Proxy Statement relating to the 1999 Annual Meeting of Shareholders to be filed.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Proxy Statement relating to the 1999 Annual Meeting of Shareholders to be filed.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14.
ITEM 14. 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:
Selected Consolidated Financial Data Management's Discussion and Analysis of Financial Condition and Results of Operations Report of Independent Public Accountants Consolidated Balance Sheets, December 31, 1998 and 1997 Consolidated Statements of Operations for the Years Ended December 31, 1998, 1997 and 1996 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1998, 1997 and 1996 Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996 Notes to Consolidated Financial Statements for the Years Ended December 31, 1998, 1997 and 1996
(a)-2. FINANCIAL STATEMENTS AND SCHEDULES
CALPINE CORPORATION AND SUBSIDIARIES
Schedule II: Valuation and Qualifying Accounts
The following items appear in Appendix F of this report:
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report Consolidated Balance Sheet, December 31, 1998 and 1997 Consolidated Statement of Income for the Years Ended December 31, 1998, 1997 and 1996 Consolidated Statements of Changes in Partners' Deficit for the Years Ended December 31, 1998, 1997 and 1996 Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996 Notes to Consolidated Financial Statements for the Years Ended December 31, 1998, 1997 and 1996
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore have been omitted.
(a)-3. EXHIBITS
The following exhibits are filed herewith unless otherwise indicated:
- --------------- (a) Incorporated by reference to Registrant's Registration Statement on Form S-1 (Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Registration Statement on Form S-1 (Registration Statement No. 333-07497).
(c) Incorporated by reference to Registrant's Current Report on Form 8-K dated May 1, 1996 and filed on May 14, 1996.
(d) Incorporated by reference to Registrant's Current Report on Form 8-K dated August 29, 1996 and filed on September 13, 1996.
(e) Incorporated by reference to Registrant's Annual Report on Form 10-K dated December 31, 1996, filed on March 27, 1996.
(f) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated March 31, 1997 and filed on May 12, 1997.
(g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated June 30, 1997 and filed on August 14, 1997.
(h) Incorporated by reference to Registrant's Annual Report on Form 10-K/A dated December 31, 1997 and filed on April 1, 1998.
(i) Incorporated by reference to Registrant's Current Report on Form 8-K dated March 31, 1998 and filed on April 14, 1998.
(j) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated March 31, 1998 and filed on April 14, 1998.
(k) Incorporated by reference to Registrant's Current Report on Form 8-K dated May 26, 1998 and filed on June 9, 1998.
(l) Incorporated by reference to Registrant's Registration Statement on Form S-4, filed on August 10, 1998 (Registration Statement No. 333-61047).
* Filed herewith.
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.
Date: CALPINE CORPORATION
By /s/ PETER CARTWRIGHT ------------------------------------ Peter Cartwright President, Chief Executive Officer and Chairman of the Board
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS:
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, the Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND OTHER INFORMATION DECEMBER 31, 1998
CALPINE CORPORATION AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA (IN THOUSANDS, EXCEPT EARNINGS PER SHARE AND RATIO DATA)
(The information contained in the Selected Consolidated Financial Data is derived from the audited Consolidated Financial Statements of Calpine Corporation and Subsidiaries.)
(Footnotes on following page)
- --------------- (1) EBITDA is defined as income from operations plus depreciation, capitalized interest, other income, non-cash charges and cash received from investments in power projects, reduced by the income from unconsolidated investments in power projects. EBITDA is presented not as a measure of operating results, but rather as a measure of our ability to service debt. EBITDA should not be construed as an alternative to either (i) income from operations (determined in accordance with generally accepted accounting principles) or (ii) cash flows from operating activities (determined in accordance with generally accepted accounting principles).
(2) Consolidated Interest Expense is defined as total interest expense plus one-third of all operating lease obligations, capitalized interest, dividends paid in respect of preferred stock and cash contributions to any employee stock ownership plan used to pay interest on loans incurred to purchase our capital stock.
(3) Earnings are defined as income before provision for taxes, extraordinary charge and cumulative effect of change in accounting principle plus cash received from investments in power projects and fixed charges reduced by the equity in income from investments in power projects and capitalized interest. Fixed charges consist of interest expense, capitalized interest, amortization of debt issuance costs and the portion of rental expenses representative of the interest expense component.
CALPINE CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Except for historical financial information contained herein, the matters discussed in this annual report may be considered forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended and subject to the safe harbor created by the Securities Litigation Reform Act of 1995. Such statements include declarations regarding our intent, belief or current expectations. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties; actual results could differ materially from those indicated by such forward-looking statements. Among the important factors that could cause actual results to differ materially from those indicated by such forward-looking statements are: (i) that the information is of a preliminary nature and may be subject to further adjustment, (ii) the possible unavailability of financing, (iii) risks related to the development, acquisition and operation of power plants, (iv) the impact of avoided cost pricing, energy price fluctuations and gas price increases, (v) the impact of curtailment, (vi) the seasonal nature of our business, (vii) start-up risks, (viii) general operating risks, (ix) the dependence on third parties, (x) risks associated with international investments, (xi) risks associated with the power marketing business, (xii) changes in government regulation, (xiii) the availability of natural gas, (xiv) the effects of competition, (xv) the dependence on senior management, (xvi) volatility in the our stock price, (xvii) fluctuations in quarterly results and seasonality, and (xviii) other risks identified from time to time in our reports and registration statements filed with the Securities and Exchange Commission.
OVERVIEW
Calpine is engaged in the development, acquisition, ownership and operation of power generation facilities and the sale of electricity and steam principally in the United States. At December 31, 1998, we had interests in 22 power plants and three steam fields predominantly in the United States, having an aggregate capacity of 3,018 megawatts.
On February 5, 1998, we acquired the remaining 55% interest in, and assumed operations and maintenance of, the Bethpage Power Plant. We purchased the remaining interests for approximately $5.0 million. Additionally, on March 31, 1998 we repaid all outstanding project debt of $37.4 million related to the Bethpage Power Plant.
On March 31, 1998, we completed the acquisition of the remaining 50% interest in the Texas Cogeneration Company ("TCC"), which is the owner of the Texas City and Clear Lake Power Plants. We paid $52.8 million in cash and agreed to make certain contingent purchase payments that could approximate 2.2% of project revenue beginning in the year 2000, increasing to 2.9% in 2002. As part of this acquisition, we own a 7.5% interest in the Bayonne Power Plant, a 165 megawatt gas-fired cogeneration power plant located in Bayonne, New Jersey. In addition, we paid $105.3 million to restructure certain gas contracts related to this acquisition.
On July 13, 1998, we signed a letter of intent to enter into a joint venture to develop, own and operate approximately 2,000 megawatts of gas-fired power plants in northern California primarily to serve the San Francisco Bay Area. The gas-fired plants are to be constructed by Bechtel and operated by us. We have announced that the first plant to be developed under the joint venture will be the Delta Energy Center, an 880 megawatt gas-fired plant located at the Dow Chemical facility in Pittsburg, California.
On July 17, 1998, we completed the purchase of a 60 megawatt geothermal power plant located in Sonoma County, California, from the Sacramento Municipal Utility District ("SMUD") for $13.0 million. We are the owner and operator of the geothermal steam fields that provide steam to this facility. Under the agreement, we paid SMUD $10.6 million at closing, and agreed to pay an additional $2.4 million over the next two years. In connection with the acquisition, SMUD agreed to purchase up to 50 megawatts of electricity from the plant at current market prices plus a renewable power premium through 2001. In addition, SMUD
has the option to purchase 10 megawatts of off-peak power production through 2005. We currently market the excess electricity into the California power market.
On July 21, 1998, we completed the acquisition of a 70 megawatt gas-fired power plant from The Dow Chemical Company for approximately $13.1 million. The power plant is located at Dow's Pittsburg, California chemical facility. We will sell up to 18 megawatts of electricity to Dow under a ten-year power sales agreement, with the balance sold to Pacific Gas & Electric Company ("PG&E") under an existing power sales agreement. In addition, we will sell approximately 200,000 lbs./hr of steam to Dow and to USS-POSCO Industries' nearby steel mill.
In August 1998, we entered into a sale and leaseback transaction for certain plant and equipment of our Greenleaf 1 & 2 Power Plants, two 49.5 megawatt gas-fired cogeneration facilities located in Sutter County, California, for a net book value of $108.6 million. Under the terms of the agreement, we received approximately $559,000 for the sale of all our rights, title and interest in the stock of Calpine Greenleaf Corporation, and transferred all non-recourse project financing of $71.6 million and deferred taxes of $21.4 million. A loss of $15.6 million was recorded on the balance sheet and is being amortized over the term of the lease through June 2014. Additionally, we have an early purchase option expiring September 30, 2003.
On September 28, 1998, we entered into a partnership agreement with Energy Management, Inc. ("EMI") to acquire an ownership interest in a 265 megawatt gas-fired plant under construction in Tiverton, Rhode Island. EMI and Calpine will be co-general partners for this project, with EMI acting as the managing general partner. We invested $40.0 million of equity in the power project, which is scheduled to commence commercial operation in May 2000. We will receive 62.8% of all cash and income distributions from the Tiverton project until we receive a 10.5% pre-tax rate of return. Thereafter, we will receive 50% of all distributions.
On November 18, 1998, we entered into a partnership agreement with EMI to acquire an ownership interest in a 265 megawatt gas-fired plant under construction in Rumford, Maine. EMI and Calpine will be co-general partners for this project, with EMI acting as the managing general partner. We invested $40.0 million of equity in the power project, which is scheduled to commence commercial operation in July 2000. We will receive 66 2/3% of all cash and income distributions from the Rumford project until we receive a 10.5% pre-tax rate of return. Thereafter, we will receive 50% of all distributions.
SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for the power plants and steam fields, for which results are consolidated in our consolidated statements of operations. The information set forth under power plants consists of the results for the West Ford Flat Power Plant, Bear Canyon Power Plant, Greenleaf 1 & 2 Power Plants, Watsonville Power Plant, King City Power Plant, Gilroy Power Plant, the Bethpage Power Plant since its acquisition on February 5, 1998, the Texas City and Clear Lake Power Plants since their acquisition on March 31, 1998, the Pasadena Power Plant since it began commercial operation on July 7, 1998, the Sonoma Power Plant since its acquisition on July 17, 1998 and the Pittsburg Power Plant since its acquisition on July 21, 1998. The information set forth under steam fields consists of the results for the PG&E
Unit 13 and Unit 16 Steam Fields, the SMUDGEO #1 Steam Fields and the Thermal Power Company Steam Fields.
- --------------- (1) Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production.
(2) Represents variable energy revenue divided by the kilowatt-hours produced. The significant increase in capacity revenue and the accompanying decline in average energy price per kilowatt-hour since 1994 primarily reflects the increase in our megawatt hour production as a result of additional gas-fired power plants.
(3) The decline in steam revenue between 1998 and 1997 reflects the acquisition and consolidation of the Sonoma Power Plant and the related steam fields. We recently announced several acquisitions which we expect to be completed during the first part of 1999. Once these acquisitions are completed we will only record electricity revenue.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Revenue -- Total revenue increased 101% to $555.9 million in 1998 compared to $276.3 million in 1997.
Electricity and steam sales revenue increased 114% to $507.9 million in 1998 compared to $237.3 million in 1997. The increase is primarily attributable to the acquisition of the remaining interest in the Texas City, Clear Lake and Bethpage Power Plants and the acquisition of the Pittsburg Power Plant. These power plants accounted for $245.2 million in additional electricity revenues in 1998. We benefited from the startup of our power plant in Pasadena, Texas, which became operational in July 1998. This power plant contributed $30.5 million in revenue during 1998. During 1998, we produced 9,864,080 total electricity megawatt hours, which was 7,706,072 megawatt hours higher than the same period in 1997, as a result of the factors described above. We recently announced three acquisitions, which we expect to complete during 1999, upon government approval. These acquisitions when completed will eliminate steam revenue for The Geysers, reflecting the consolidation of the acquired power plants and related steam fields.
Service contract revenue increased 98% to $20.2 million in 1998 compared to $10.2 million in 1997. The $10.0 million increase was primarily due to $3.3 million for fuel management fees, and $7.5 million for third party excess gas sales.
Income from unconsolidated investments in power projects increased 59% to $25.2 million in 1998 compared to $15.8 million in 1997. The increase of $9.4 million is primarily attributable to our investments in
the Lockport, Stony Brook and Kennedy International Airport Power Plants, which contributed $5.2 million of equity income during 1998, as well as $2.5 million of equity income from the Bayonne Power Plant. For the year ended December 31, 1998, we also recorded $11.7 million of equity income from the Sumas Power Plant compared to $8.5 million for the same period in 1997. These increases in equity income were partially offset by a $1.1 million decrease from the Auburndale Power Plant.
Interest income on loans to power projects decreased 80% to $2.6 million in 1998 compared to $13.0 million in 1997. This decrease was attributable to the acquisition of the remaining 50% interest in TCC on March 31, 1998 and the sale of a note receivable in December 1997.
Cost of revenue -- Cost of revenue increased to $375.3 million in 1998 compared to $153.3 million in 1997. The increase of $222.0 million in 1998 was primarily attributable to increased plant operating, fuel and depreciation expenses as a result of the acquisition of the remaining interest in the Texas City, Clear Lake and Bethpage Power Plants, the acquisition of the Pittsburg Power Plant and the startup of the Pasadena Power Plant. Additionally, service contract expenses increased $8.8 million for the year ended December 31, 1998, of which $6.6 million was related to costs associated with the sale of third party excess gas and a $1.8 million increase for fuel management contracts.
General and administrative expenses -- General and administrative expenses increased 46% to $26.8 million in 1998 compared to $18.3 million in 1997. The increase was attributable to the continued growth in personnel and overhead costs necessary to support the overall growth in our operations.
Interest expense -- Interest expense increased 41% to $86.7 million in 1998 compared to $61.5 million in 1997. The increase was primarily attributable to interest expense of $35.0 million related to the senior notes issued in 1998 and 1997. This increase was partially offset by $3.5 million for the repayment of non-recourse project financing for our Geysers facilities, $2.9 million for reduction of the TCC debt, $2.0 million for reduction of the indebtedness of the Greenleaf 1 & 2 Power Plants and $1.7 million of interest capitalized on the development and construction of power projects.
Interest income -- Interest income decreased 14% to $12.3 million in 1998 compared to $14.3 million in 1997. The decrease was primarily attributable to less interest earned on restricted cash in 1998.
Other income, net -- Other income decreased 66% to $1.1 million in 1998 compared to $3.2 million in 1997. The decrease was primarily attributable to gas refunds received in 1997.
Provision for income taxes -- The effective income tax rate was approximately 37% in 1998 compared to 35% in 1997. The effective rates were lower than the statutory rate (federal and state) primarily due to depletion in excess of tax basis benefits at our geothermal facilities, and a decrease in the California tax liability due to our expansion into states other than California.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Revenue -- Total revenue increased 29% to $276.3 million in 1997 compared to $214.6 million in 1996.
Electricity and steam sales revenue increased 19% to $237.3 million in 1997 compared to $199.5 million in 1996. Electricity and steam sales revenue for 1997 reflected a full year of operation at the Gilroy and King City Power Plants, which contributed to increases in electricity and steam sales revenue in 1997 compared to 1996 of $25.4 million, and $4.3 million, respectively. Electricity and steam sales revenue for 1997 compared to 1996 was also $6.0 million higher at the Bear Canyon and West Ford Flat Power Plants as a result of increased production and an increase in fixed energy prices to 13.83c per kilowatt-hour. During 1996, the Bear Canyon and West Ford Flat Power Plants experienced the maximum curtailment allowed under their power sales agreements with PG&E. In May 1997, the power sales agreements for the Bear Canyon and West Ford Flat Power Plants were modified to remove curtailment. Without such curtailment, these plants generated an additional $4.2 million in revenues in 1997 as compared to 1996. In addition, Thermal Power Company ("TPC") also contributed $2.7 million more revenue for 1997 than 1996, primarily due to increased steam sales under the alternative pricing agreement entered into with PG&E in March 1996.
Service contract revenue increased to $10.2 million in 1997 compared to $6.5 million in 1996. Service contract revenue during 1996 reflected a $2.8 million loss from our electricity trading operations. The increase in service contract revenue for 1997 was also attributable to $2.8 million of revenue from the Texas City and Clear Lake Power Plants, which were acquired in June 1997.
Income from unconsolidated investments in power projects increased to $15.8 million in 1997 compared to $6.5 million during 1996. The increase in 1997 compared to 1996 was primarily due to equity income of $6.3 million from our June 1997 investment in the Texas City and Clear Lake Power Plants and an increase in equity income of $2.2 million from our investment in Sumas Cogeneration Company ("Sumas"). In accordance with a power sales agreement with Puget Sound Power and Light Company, operations at Sumas were significantly displaced from February to July 1997, and, in exchange, the Sumas Power Plant received a higher price for energy sold and certain other payments. In addition, the partnership agreement governing Sumas was amended in September 1997 to increase our percentage of distributions.
Interest income on loans to power projects increased to $13.0 million in 1997 compared to $2.1 million in 1996. The increase was primarily related to interest income on the loans made by Calpine Finance Company, a wholly-owned subsidiary of our company, to the Texas City and Clear Lake Power Plants, and to interest income on the loans to the sole shareholder of Sumas Energy, Inc., our partner in Sumas.
Cost of revenue -- Cost of revenue increased 19% to $153.3 million in 1997 compared to $129.2 million in 1996. Plant operating, depreciation, and operating lease expenses at the Gilroy and King City Power Plants for 1997 reflected a full year of operations, which contributed to increases in cost of revenue in 1997 compared to 1996 of $13.0 million and $8.3 million, respectively.
Project development expenses -- Project development expenses increased 92% to $7.5 million in 1997 compared to $3.9 million in 1996, due primarily to expanded acquisition and development activities.
General and administrative expenses -- General and administrative expenses increased 24% to $18.3 million in 1997 compared to $14.7 million in 1996. The increases were primarily due to additional personnel and related expenses necessary to support our expanding operations.
Interest expense -- Interest expense increased 36% to $61.5 million in 1997 from $45.3 million in 1996. The increase was attributable to: (1) $10.8 million of interest expense related to the 8 3/4% Senior Notes Due 2007 issued in July and September 1997, (2) a $7.3 million increase in interest expense related to the 10 1/2% Senior Notes Due 2006 issued May 1996, (3) a $6.4 million increase in interest expense on debt related to the Gilroy Power Plant acquired in August 1996 and (4) $5.4 million of interest expense on debt related to the acquisition of the Texas City and Clear Lake Power Plants. These increases were offset by $6.2 million of interest capitalized for the development and construction of power plants, and a $7.6 million decrease in interest expense at Calpine Geysers Company and TPC due to repayment of debt.
Interest income -- Interest income increased 66% to $14.3 million for 1997 compared with $8.6 million for 1996. Interest income earned on collateral securities purchased in April 1996 in connection with the King City Power Plant contributed to an increase in interest income of $1.2 million in 1997 as compared to 1996. In addition, higher cash and cash equivalent balances resulting from the issuance of the 8 3/4% Senior Notes Due 2007 during 1997 resulted in higher interest income for 1997 as compared to 1996.
Other income, net -- Other income, net, increased to $3.2 million for 1997 compared with expense of $2.3 million for 1996. In 1997, we recorded a $1.1 million gain on the sale of a note receivable and received a refund of $961,000 from PG&E. In 1996, we recorded a $3.7 million loss for uncollectible amounts related to an acquisition project.
Provision for income taxes -- The effective rate for the income tax provision was approximately 35% in 1997 and 33% in 1996. The effective rates were lower than the statutory tax rate (federal and state) primarily due to depletion in excess of tax basis benefits at our geothermal facilities, a decrease in the California taxes paid due to our expansion into states other than California, and a revision of prior years' tax estimates.
LIQUIDITY AND CAPITAL RESOURCES
To date, we have obtained cash from our operations, borrowings under our credit facilities and other working capital lines, sale of debt and equity, and proceeds from non-recourse project financing. We utilized this cash to fund our operations, service debt obligations, fund the acquisition, development and construction of power generation facilities, finance capital expenditures and meet our other cash and liquidity needs. The following table summarizes our cash flow activities for the periods indicated:
Operating activities for 1998 provided $171.2 million, consisting of approximately $74.3 million of depreciation and amortization, $45.7 million of net income, $34.4 million of distributions from unconsolidated investments in power projects, $13.6 million of deferred income taxes, $5.2 million net decrease in operating assets, and a $23.4 million net increase in operating liabilities. This was offset by $25.2 million of income from unconsolidated investments.
Investing activities for 1998 used $406.7 million, primarily due to $158.1 million for the acquisition of the remaining 50% interest in the Texas City and Clear Lake Power Plants, $42.4 million for the acquisition of the remaining 55% interest in the Bethpage Power Plant, $24.0 million of capital expenditures related to the construction of the Pasadena Power Plant, $13.1 million for the acquisition of the Pittsburg Power Plant, $11.9 million for the acquisition of the Sonoma Power Plant, $74.2 million of other capital expenditures, $16.2 million of capitalized project development costs, $40.0 million for the acquisition of an equity interest in the Tiverton Power Plant, $40.0 million for the acquisition of an equity interest in the Rumford Power Plant, $7.0 million of interest capitalized on construction projects, offset by $559,000 related to the sale and leaseback transaction of the Greenleaf 1 & 2 Power Plants, the receipt of $13.8 million of loan payments, $6.0 million of maturities of collateral securities in connection with the King City Power Plant, and $1.1 million of restricted cash.
Financing activities for 1998 provided $283.4 million of cash consisting of $52.1 million of borrowings for the construction of the Pasadena Power Plant, $5.8 million of borrowings for contingent consideration in connection with the acquisition of the Gilroy Power Plant, $394.9 million of net proceeds from additional financings, and $1.1 million for the issuance of common stock, partially offset by $162.1 million in repayment of non-recourse project financing, $8.3 million of repurchase of Senior Notes Due 2006 which includes a premium paid and accrued interest to the date of repurchase.
At December 31, 1998, cash and cash equivalents were $96.5 million and working capital was $86.9 million. For 1998, cash and cash equivalents increased by $48.0 million and working capital increased by $112.6 million as compared to December 31, 1997.
As a developer, owner and operator of power generation facilities, we are required to make long-term commitments and investments of substantial capital for our projects. We historically have financed these capital requirements with cash from operations, borrowings under our credit facilities, other lines of credit, non-recourse project financing or long-term debt, and the sale of equity. We expect to commit significant capital in the near future as a result of development projects and pending acquisitions which have been announced, including the Westbrook, Sutter, South Point and Magic Valley Power Plants. We are also in the process of completing three acquisitions comprising of 14 geothermal power plants located in The Geysers and certain related steam fields.
We continue to evaluate current and forecasted cash flow as a basis for financing operating requirements and capital expenditures. We believe that we will have sufficient liquidity from cash flow from operations, borrowings available under the lines of credit and working capital to satisfy all obligations under outstanding indebtedness, to finance anticipated capital expenditures and to fund working capital requirements for the next twelve months.
On March 31, 1998, we sold $300.0 million of 7 7/8% Senior Notes Due 2008 which mature on April 1, 2008, with interest payable semi-annually on April 1 and October 1 of each year commencing October 1, 1998 (See Note 7 to the Notes to Consolidated Financial Statements). On July 24, 1998, we sold an additional $100.0 million of 7 7/8% Senior Notes Due 2008. After deducting discounts to initial purchasers and expenses of the offerings, the net proceeds from the sale of the Senior Notes Due 2008 were approximately $392.3 million. (See Note 7 to the Notes to Consolidated Financial Statements).
At December 31, 1998, we had a $100.0 million revolving credit facility available with a consortium of commercial lending institutions. We had no borrowings and $26.4 million of letters of credit outstanding under the credit facility (See Note 8 to the Notes to Consolidated Financial Statements). The credit facility contains certain restrictions that limit or prohibit, among other things, the ability of Calpine or its subsidiaries to incur indebtedness, make payments of certain indebtedness, pay dividends, make investments, engage in transactions with affiliates, create liens, sell assets and engage in mergers and consolidations.
At December 31, 1998, we also had $105.0 million of outstanding 9 1/4% Senior Notes Due 2004, which mature on February 1, 2004, with interest payable semi-annually on February 1 and August 1 of each year. In addition, we had $171.8 million of outstanding 10 1/2% Senior Notes Due 2006, which mature on May 15, 2006, with interest payable semi-annually on May 15 and November 15 of each year. During 1997, we issued $275.0 million of 8 3/4% Senior Notes Due 2007, which mature on July 15, 2007, with interest payable semi-annually on January 15 and July 15 of each year.
At December 31, 1998, we had a $12.0 million letter of credit outstanding with The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant.
We have a $1.1 million working capital line with a commercial lender that may be used to fund short-term working capital commitments and letters of credit. At December 31, 1998, we had no borrowings under this working capital line and $74,000 of letters of credit outstanding. Borrowings accrue interest at prime plus 1%.
OUTLOOK
Our strategy is to continue our rapid growth by capitalizing on the significant opportunities in the power market, primarily through our active development and acquisition programs. In pursuing our proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach uses our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations and power marketing, which we believe provide us with a competitive advantage. The key elements of our strategy are as follows:
- Development and expansion of power plants. We are actively pursuing the development and expansion of highly efficient, low-cost, gas-fired power plants that replace old and inefficient generating facilities and meet the demand for new generation. Our strategy is to develop power plants in strategic geographic locations that enable us to leverage existing power generation assets and operate the power plants as integrated electric generation systems. This allows us to achieve significant operating synergies and efficiencies in fuel procurement, power marketing and operations and maintenance.
In July 1998, we achieved a key milestone in our development program by completing the development of our 240 megawatt gas-fired power plant in Pasadena, Texas. The Pasadena project serves as a prototype for future development projects. We currently have six new projects under construction, representing an additional 1,784 megawatts of capacity. Of these new projects, we are expanding our Pasadena and Clear Lake facilities by an aggregate of 545 megawatts. In addition, four new gas-fired
power plants, which will produce an estimated 1,239 megawatts of electricity, are currently under construction in Dighton, Massachusetts; Tiverton, Rhode Island; Rumford, Maine; and Westbrook, Maine. We have also announced plans to develop additional power generation facilities, totaling an estimated 2,580 megawatts of electricity, in California, Texas, Arizona and Maine.
- Acquisition of power plants. Our strategy is to acquire power generating facilities that meet our stringent acquisition criteria and that provide significant potential for revenue, cash flow and earnings growth and that provide the opportunity to enhance the operating efficiencies of the plants. We have significantly expanded and diversified our project portfolio through the acquisition of power generation facilities through the completion of 22 acquisitions to date.
We are currently in the process completing two acquisitions comprising 14 geothermal power plants with an aggregate capacity of 694 megawatts, located in The Geysers, California. Historically, we have served as the steam supplier for these facilities, which have been owned and operated by PG&E. We anticipate that these acquisitions will enable us to consolidate our operations in The Geysers into a single ownership structure and to integrate the power plant and steam field operations, allowing us to optimize the efficiency and performance of the facilities. We believe that these acquisitions provide us with significant synergies that leverage our expertise in geothermal power generation and position us to benefit from the demand for "green" energy in the competitive market.
- Enhance the performance and efficiency of existing power projects. We continually seek to maximize the power generation potential of our operating assets and minimize our operating and maintenance expenses and fuel costs. This will become even more significant as our portfolio of power generation facilities expands to an aggregate of 40 power plants with an aggregate capacity of 4,667 megawatts, after completion of our pending acquisitions and projects currently under construction. We focus on operating our plants as an integrated system of power generation, which enables us to minimize costs and maximize operating efficiencies. As of December 31, 1998, our power generation facilities have operated at an average availability of approximately 96.5%. We believe that achieving and maintaining a low-cost of production will be increasingly important to compete effectively in the power generation market.
RISK FACTORS
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, 1998, our total consolidated indebtedness was $1.1 billion, our total consolidated assets were $1.7 billion and our stockholders' equity was $287.0 million. Whether we will be able to meet our debt service obligations and to repay our outstanding indebtedness will be dependent primarily upon the performance of our power generation facilities.
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, and
- limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in government regulation.
The operating and financial restrictions and covenants in our existing debt agreements, including the indentures relating to our outstanding senior notes and our $100.0 million revolving credit facility, contain restrictive covenants. Among other things these restrictions limit or prohibit our ability to:
- incur indebtedness,
- make prepayments of indebtedness in whole or in part,
- pay dividends,
- make investments,
- engage in transactions with affiliates,
- create liens,
- sell assets, and
- acquire facilities or other businesses.
Also, if our management or ownership changes, our indentures may require us to make an offer to purchase our outstanding notes, including the senior notes. We cannot assure you that we will have the financial resources necessary to purchase such notes, and our board of directors cannot waive provisions in the indentures. (See Note 7 to Notes to Consolidated Financial Statements).
We believe that our cash flow from operations, together with other available sources of funds, including borrowings under our existing borrowing arrangements, will be adequate to pay principal and interest on our debt and to enable us to comply with the terms of our debt agreements. If we are unable to comply with the terms of our debt agreements and fail to generate sufficient cash flow from operations in the future, we may be required to refinance all or a portion of our existing 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 debt agreements. If cash flow is insufficient and refinancing or additional financing is unavailable, we may be forced to default on our 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.
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 on and principal of our senior notes. The non-recourse project 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 other obligations, including operating expenses, debt service and reserves.
Our subsidiaries and other affiliates are separate and distinct legal entities and have no obligation to pay any amounts due on our senior notes, and do not guarantee the payment of interest on or principal of these notes. The right of our senior note holders 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).
While the indentures impose limitations on our ability and the ability of our subsidiaries to incur additional indebtedness, the indentures do not limit the amount of non-recourse project financing that our subsidiaries may incur to finance new power generation facilities.
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 and the cost of the financing are dependent upon numerous factors. These factors include:
- general economic and capital market conditions,
- conditions in energy markets,
- regulatory developments,
- credit availability from banks or other lenders,
- 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.
Financing for new facilities may not be available to us on acceptable terms in the future. We have financed our existing power generation facilities using a variety of leveraged financing structures, primarily consisting of non-recourse project financing and lease obligations. As of December 31, 1998, we had approximately $1.1 billion of total consolidated indebtedness, of which approximately 11% represented non-recourse project financing. Each non-recourse project financing and lease obligation is structured to be fully paid out of cash flow provided by the facility or facilities. 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. We do not believe the existence of non-recourse or lease financing will significantly affect our ability to continue to borrow funds in the future in order to finance new facilities. However, it is possible that we may be unable to obtain the financing required to develop our power generation facilities on terms satisfactory to us.
We have from time to time guaranteed certain obligations of our subsidiaries and other affiliates. Our lenders or lessors may also require us to guarantee the indebtedness for future facilities. This would render our general corporate funds vulnerable in the event of a default by the facility or related subsidiary. Additionally, 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.
Revenue under some of our power sales agreements may be reduced significantly upon their expiration or termination. Most of the electricity we generate from our existing portfolio is sold under long-term power sales agreements that expire at various times. When the terms of each of these power sales agreements expire, it is possible that the price paid to us for the generation of electricity may be reduced significantly, which would greatly reduce our revenue under such agreements. The fixed price periods in some of our long-term power sales agreements have recently expired, and the electricity under those agreements is now sold at a fluctuating market price. For example, the price for electricity for two of our power plants, the Bear Canyon (20 megawatts) and West Ford Flat (27 megawatts) power plants, was 13.83 cents per kilowatt hour under the fixed price periods that recently expired for these facilities, and is now set at the energy clearing price, which averaged 2.66 cents per kilowatt hour during 1998. As a result, our energy revenue under these power sales agreements has been materially reduced. This reduction may lower our results of operations. We expect the forecasted decline in energy revenues will be partially mitigated by decreased royalties and planned operating cost reductions at these facilities. In addition, we will continue our strategy of offsetting these reductions through our acquisition and development program.
Our power project development and acquisition activities may not be successful. The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, we must generally obtain:
- necessary power generation equipment,
- governmental permits and approvals,
- fuel supply and transportation agreements,
- sufficient equity capital and debt financing,
- electrical transmission agreements, 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 and legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. If we were unable to complete the development of a facility, we would generally 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.
We have grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields. We believe that although the domestic power industry is undergoing consolidation and that significant acquisition opportunities are available, we are likely to confront significant competition for acquisition opportunities. In addition, we may be unable to continue to identify attractive acquisition opportunities at favorable prices or, to the extent that any opportunities are identified, we may be unable to complete the acquisitions.
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 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 could result in losing our interest in a power generation facility.
In addition, 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.
Our power generation facilities may not operate as planned. Upon completion of our pending acquisitions and projects currently under construction, we will operate 31 of the 40 power plants in which we will have an interest. The continued operation of power generation facilities 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. As of December 31, 1998, our power generation facilities have operated at an average availability of approximately 96.5%. 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 the power generation facility.
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 fluids,
- the geology of the reservoir,
- the total amount of recoverable reserves,
- operating expenses relating to the extraction of fluids,
- price levels relating to the extraction of fluids, 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 lower our results of operations.
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. While we have extensive experience in the operation and development of geothermal energy resources and in preparing such estimates, 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.
We depend on our electricity and thermal energy customers. Each of our power generation facilities currently relies on one or more power sales agreements with one or more utility or other customers for all or substantially all of such facility's revenue. In addition, the sales of electricity to two utility customers during 1998 comprised approximately 64% of our total revenue during that year. The loss of any one power sales agreement with any of these customers 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.
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 require numerous permits, approvals and certificates from appropriate 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 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 new laws and regulations may become applicable to us that may have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed facilities may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain 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.
Our operations are potentially subject to the provisions of various energy laws and regulations, including the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as amended ("PUHCA"), and state and local regulations. PUHCA provides for the extensive regulation of public utility holding companies and their subsidiaries. PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and owners of QFs certain exemptions from certain federal and state regulations, including rate and financial regulations.
Under present 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 exempt wholesale generators ("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility must be not more than 50% owned by an electric utility company or electric utility holding company. 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. Any geothermal power facility which produces up to 80 megawatts of electricity and meets PURPA ownership requirements is considered a QF.
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 our other power plants could lose QF status because, under FICC 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 any 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, including our senior notes. See "Business -- Government Regulation -- Federal Energy Regulation."
Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at prices based on avoided costs of energy. We do not know whether this legislation will be passed or, if passed, what form it may take. We cannot assure that any legislation passed would not adversely impact 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. In particular, the state of California has restructured its electric industry by providing for a phased-in competitive power generation industry, with a power pool and an independent system operator, and for direct access to generation for all power purchasers outside the power exchange under certain circumstances. Although existing QF power sales contracts are to be honored under such restructuring, and all of our California operating projects are QFs, until the new system is fully implemented, it is impossible to predict what impact, if any, it may have on the operations of those projects.
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 and short-, medium- and long-term supply contracts. 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. 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. If gas is not available, or if gas prices increase above the fuel component of the facilities' power sales agreements, there could be a negative impact on our results of operations.
Competition could adversely affect our performance. The power generation industry is characterized by intense competition. We encounter competition from utilities, industrial companies and other power producers. In recent years, there has been increasing competition in an effort to obtain power sales agreements. This competition has contributed to a reduction in electricity prices. In addition, many states have implemented or are considering regulatory initiatives designed to increase competition in the domestic power industry. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity.
Our international investments may face uncertainties. We have one investment in geothermal steam fields located in Mexico and may pursue additional international investments. 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:
- risks of fluctuations in currency valuation,
- currency inconvertibility,
- expropriation and confiscatory taxation,
- increased regulation, and
- approval requirements and governmental policies limiting returns to foreign investors.
We depend on our senior management. Our success is largely dependent on the skills, experience and efforts of our senior management. The loss of the services of one or more members of our senior management could have a negative effect on our business and development.
Seismic disturbances could damage our project. 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 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:
- the timing and size of acquisitions,
- the completion of development projects, and
- variations in levels of production.
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 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:
- announcements of developments related to our business,
- fluctuations in our results of operations,
- sales of substantial amounts of our securities into the marketplace,
- general conditions in our industry or the worldwide economy,
- 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 thus, the current market price may not be indicative of future market prices.
FINANCIAL MARKET RISKS
From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations. We do not use derivative financial instruments for speculative or trading purposes. The following table summarized the fair market value of our existing interest rate swap agreements as of December 31, 1998 (in thousands):
Short-term investments. As of December 31, 1998, we has short-term investments of $19.0 million. These short-term investments consist of highly liquid investments with maturities between three and twelve months. These investments are subject to interest rate risk and will fall in value if market interest rates increase. We have the ability to hold these investments to maturity, and as a result, we would not expect the value of these investments to be affected to any significant degree by the effect of a sudden change in market interest rates. Declines in interest rates over time will reduce our interest income.
Outstanding debt. As of December 31, 1998, we have outstanding long-term debt of approximately $1.1 billion primarily made up of $951.8 million of senior notes and $119.6 million of non-recourse project financing. Our non-recourse project financing is stated at fair market value and bears a weighted average interest rate of 6.8%. Our outstanding long-term debt as of December 31, 1998 are as follows (in thousands):
Gas prices fluctuations. We enter into derivative commodity instruments to hedge our exposure to the impact of price fluctuations on gas purchases. Such instruments include regulated natural gas contracts and over-the-counter swaps and basis hedges with major energy derivative product specialists. All hedge transactions are subject to our risk management policy which does not permit speculative positions. These transactions are accounted for under the hedge method of accounting. Cash flows from derivative instruments are recognized as incurred through changes in working capital.
We use a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of natural gas may have on the fair value of our derivative instruments. This analysis measures the impact on the
commodity derivative instruments and, thereby, does not consider the underlying exposure related to the commodity. However, gains and losses on derivative contracts are expected to be similarly offset by sales at the spot market price. Due to the short duration of the contracts, time value of money is ignored. The hypothetical change in fair value is calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS
In April 1998, the American Institute of Certified Public Accountants ("AICPA") issued Statement of Position ("SOP") No. 98-5, "Reporting on the Costs of Start-Up Activities," which is effective for financial statements for fiscal years beginning after December 15, 1998. For purposes of this SOP, start-up activities are defined broadly as those one-time activities related to opening a new facility, conducting business in a new territory, conducting business with a new class of customer or beneficiary, initiating a new process in an existing facility, or commencing some new operation. Start-up activities include activities related to organizing a new entity (commonly referred to as organization costs). We have assessed the impact and adopted SOP 98-5 as of December 31, 1998, and determined it to be immaterial to our consolidated financial statements.
In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 131, "Disclosures about Segments of an Enterprise and Related Information." This Statement establishes the reporting of information about operating segments in annual financial statements and requires that enterprises report selected information about operating segments in interim financial reports to shareholders. SFAS No. 131 also establishes standards for related disclosures about products and services, geographic areas and major customers. SFAS No. 131 is effective for fiscal years beginning after December 15, 1997. During 1998, we started the process of decentralization of our operations and will complete this process during 1999. This Statement will become effective upon completion of this process. We do not believe that this pronouncement will have a material impact on our consolidated financial statements.
In June 1998, FASB also issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards, requiring every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and require that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999. The Statement must be applied to derivative instruments and to certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997.
We have not yet analyzed the impact of adopting SFAS No. 133 on the financial statements and have not determined the timing of or method of the adoption of SFAS No. 133. However the Statement could increase the volatility of our earnings.
YEAR 2000 COMPLIANCE
Year 2000 Compliance -- The "Year 2000 problem" refers to the fact that some computer hardware, software and embedded systems were designed to read and store dates using only the last two digits of the year.
We are coordinating our efforts to address the impact of Year 2000 on our business through a Year 2000 Project Team comprised of representatives from each business unit and our Year 2000 Project Office. The Year 2000 Project Office is charged with addressing additional Year 2000 related issues including, but not limited to, business continuation and other contingency planning. The Year 2000 Project Team meets regularly to monitor the efforts of assigned staff and contractors to identify, remediate and test our technology.
The Year 2000 Project Team is focusing on four separate technology domains:
- corporate applications, which include core business systems,
- non-information technology, which includes all operating and control systems,
- end-user computing systems (that is, systems that are not considered core business systems but may contain date calculations), and
- business partner and vendor systems.
Corporate Applications -- Corporate applications are those major core systems, such as customer information, human resources and general ledger, for which our Management Information Systems department has responsibility. We utilize PeopleSoft for our major core systems. The PeopleSoft applications we utilize are in operation and have been determined to be Year 2000 compliant.
Non-Information Technology/Embedded Systems -- Non-information technology includes such items as power plant operating and control systems, telecommunications and facilities-based equipment (e.g. telephones and two-way radios) and other embedded systems. Each business unit is responsible for the inventory and remediation of its embedded systems. In addition, we are working with the Electric Power Research Institute, a consortium of power companies, including investor-owned utilities, to coordinate vendor contacts and product evaluation. Because many embedded systems are similar across utilities, this concentrated effort should help to reduce total time expended in this area and help to ensure that our efforts are consistent with the efforts and practices of other power companies and utilities.
An Inventory phase for non-information technology/embedded systems was completed in October 1998. An Initial Assessment phase was completed in December 1998. We plan to complete remediation of non-compliant systems by the second quarter of 1999. To date, all embedded systems that we have identified can be upgraded or modified within our current schedule. The schedule for addressing Year 2000 issues with respect to mission critical embedded systems is as follows:
Testing of embedded systems is complex because some of the testing must be completed during power plant scheduled maintenance outages. Much of the testing will be accomplished in the spring of 1999 during regularly scheduled maintenance outage periods. At that time, at least one typical unit of each critical type will be tested by us or in cooperation with other power companies, and the requirement for further testing will be determined.
End-User Computing Systems -- Some of our business units have developed systems, databases, spreadsheets, etc. that contain date calculations. Compliance of individual workstations is also included in this domain. These systems comprise a relatively small percentage of the required modification in terms of both number and criticality.
Our end-user computing systems are being inventoried by each business unit and evaluated and remediated by our MIS staff. We have completed approximately 10% of remediation and testing of the end-user computing systems, and we expect to complete this process by mid-1999.
Business Partner and Vendor Systems -- We have contracts with business partners and vendors who provide products and services to us. We are vigorously seeking to obtain Year 2000 assurances from these third parties. The Year 2000 Project Team and appropriate business units are jointly undertaking this effort. We have sent letters and accompanying Year 2000 surveys to about 800 vendors and suppliers. Over 400 responses have been received as of January 31, 1999. These responses outline to varying degrees the approaches vendors
are undertaking to resolve Year 2000 issues within their own systems. Follow-up letters will be sent to those vendors who have not responded or whose responses were inadequate.
Contingency Planning -- Contingency and business continuation planning are in various stages of development for critical and high-priority systems. Our existing disaster response plan and other contingency plans are currently being evaluated and will be adopted for use in case of any Year 2000-related disruption. We expect to complete our contingency planning by September 1999.
Costs -- The costs of expected modifications are currently estimated to be approximately $1.7 million which will be charged to expense as incurred. From January 1, 1998 through December 31, 1998, $158,000 has been charged to expense. Approximately 9% of the estimated total cost was incurred in 1998, and the remainder will be incurred in 1999 and 2000. These costs have been and will be funded through operating cash flow. These estimates may change as additional evaluations are completed and remediation and testing progress.
Risks -- We currently expect to complete our Year 2000 efforts with respect to critical systems by mid-1999. This schedule and our cost estimates may be affected by, among other things, the availability of Year 2000 personnel, the readiness of third parties, the timing for testing our embedded systems, the availability of vendor resources to complete embedded system assessments and produce required component upgrades and our ability to implement appropriate contingency plans.
We produce revenues by selling power we produce to customers. We depend on transmission and distribution facilities that are owned and operated by investor-owned utilities to deliver power to our customers. If either our customers or the providers of transmission and distribution facilities experience significant disruptions as a result of the Year 2000 problem, our ability to sell and deliver power may be hindered, which could result in a loss of revenue.
The cost or consequences of a materially incomplete or untimely resolution of the Year 2000 problem could adversely affect our future operations, financial results or our financial condition.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors of Calpine Corporation:
We have audited the accompanying consolidated balance sheets of Calpine Corporation (a Delaware corporation) and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Sumas Cogeneration Company, L.P. ("Sumas"), the investment in which the Company recorded income of $11.7 million, $8.6 million and $6.4 million for the years ended December 31, 1998, 1997 and 1996, respectively. The financial statements of Sumas were audited by other auditors whose report has been furnished to us and our opinion, insofar as it relates to the amounts included for Sumas, is based solely on the report of the other auditors.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the financial statements referred to above present fairly, in all material respects, the financial position of Calpine Corporation and subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
Our audit was conducted for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
San Jose, California February 5, 1999
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1998 AND 1997 (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries (collectively, the "Company") is engaged in the development, acquisition, ownership and operation of power generation facilities and the sale of electricity and steam in the United States and selected international markets. The Company has ownership interests in and operates gas-fired cogeneration facilities, geothermal steam fields and geothermal power generation facilities in northern California, Washington, Texas and various locations on the East Coast. 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 cogeneration facilities is primarily sold to governmental and industrial users and steam produced by geothermal steam fields is sold to utility-owned power plants.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The accompanying consolidated financial statements include accounts of the Company. Wholly-owned and majority-owned subsidiaries are consolidated. Less-than-majority-owned subsidiaries, and subsidiaries for which control is deemed to be temporary, 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 4). All significant intercompany accounts and transactions are eliminated in consolidation. The Company uses the proportionate consolidation method to account for Thermal Power Company's ("TPC") 25% interest in jointly owned geothermal properties.
Use of Estimates in Preparation of Financial Statements -- The preparation of financial statements in conformity with generally accepted accounting principles 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 revenues and expenses during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to future development costs and total productive resources of the geothermal facilities (see Property, Plant and Equipment), and the realization of deferred income taxes (see Note 9).
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.
Inventories -- Operating supplies are valued at the lower of cost or market. Cost for large replacement parts is determined using the specific identification method. For the remaining supplies, cost is determined using the weighted average cost method.
Property, Plant and Equipment, net -- Property, plant and equipment, net are stated at cost less accumulated depreciation and amortization.
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. Geothermal properties include the value attributable to the geothermal resources of Calpine Geysers Company, L.P. ("CGC") and all of the property, plant and equipment of TPC. Proceeds from the sale of geothermal properties are applied against capitalized costs, with no gain or loss recognized. At December 31, 1998 and 1997, the Company had $4.0 million of geothermal leases at Glass Mountain in northern California recorded as property, plant and equipment, net in the accompanying consolidated balance sheets. The Company is continuing to pursue the development of Glass Mountain, and expects to recover the cost of such leases from the future development of the resource.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Geothermal costs, including an estimate of future development costs to be incurred 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 units 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 steam and 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.
Gas-fired power production facilities include the cogeneration plants and related equipment and are stated at cost. Depreciation is recorded utilizing the straight-line method over the estimated original useful life of up to 38 years. The value of the above-market pricing provided in power sales agreements acquired is recorded in property, plant and equipment, net and is amortized over the above-market pricing period in the power sales agreement with lives of 22 and 23 years. When assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and the resulting gains or losses are included in results of operations.
As of December 31, 1998 and 1997, the components of property, plant and equipment, net are as follows (in thousands):
Construction in progress includes costs primarily attributable to the purchase of four gas-fired turbines which were purchased during 1998 for projects currently under development.
Capitalized Interest -- The Company capitalizes interest on projects during the development and construction period. For the years ended December 31, 1998 and 1997, the Company capitalized $7.0 million and $6.2 million, respectively, of interest in connection with the development and construction of power plants. There was no capitalized interest in 1996.
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 new project. Outside services and other third party costs are capitalized for acquisition projects. Upon the start-up of plant operations or the completion of an acquisition, these costs are generally transferred to property, plant and equipment, net and amortized over the estimated useful life of the project. Capitalized
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
project costs are charged to expense when the Company determines that the project will not be consummated or is impaired.
Collateral Securities -- The Company maintains certain investments in investment grade collateral securities which are classified as held-to-maturity and stated at amortized cost. The investments in debt securities mature at various dates through August 2018 in amounts equal to a portion of the King City Power Plant lease payments. The fair value of held-to-maturity securities was determined based on the quoted market prices at the reporting date for the securities.
The components of held-to-maturity securities by major security type as of December 31, 1998 and 1997 are as follows (in thousands):
Restricted Cash -- The Company is required to maintain cash balances that are restricted by provisions of its debt agreements, lease agreements and by regulatory agencies. The Company's debt agreements specify restrictions based on debt service payments and drilling costs for the following year. Regulatory agencies require cash to be restricted to ensure that funds will be available to restore property to its original condition. 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 for the purposes of the consolidated statements of cash flows.
Deferred Financing Costs -- Costs incurred in connection with obtaining financing are deferred and amortized over the term of the related financings, which range up to 18 years.
Revenue Recognition -- Revenue from electricity and steam sales is recognized upon transmission to the customer. Revenues from contracts entered into or acquired since May 1992 are recognized at the lesser of amounts billable under the contract or amounts recognizable at an average rate over the term of the contract. The Company's power sales agreements related to CGC were entered into prior to May 1992. Had the Company applied the methodology described above to the CGC power sales agreements, the revenues recorded for the years ended December 31, 1998, 1997, and 1996, would have been approximately $5.5 million, $20.1 million, and $16.1 million less, respectively.
The Company performs operations and maintenance services for all consolidated projects in which it has an interest, except for the TPC steamfields. Revenue from investees is recognized on these contracts when the services are performed.
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 loans
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
receivable. The Company's cash accounts are held by seven FDIC insured banks. The Company's accounts, and notes receivable are concentrated within entities engaged in the energy industry (see Note 13), mainly within the United States, some of which are related parties. The Company also maintains a note receivable with a company in Mexico (see Note 5). The Company generally does not require collateral for accounts receivable.
Derivative Financial Instruments -- The Company engages in activities to manage risks associated with changes in interest rates. The Company has entered into swap agreements to reduce exposure to interest rate fluctuations in anticipation of certain debt commitments. The instruments' cash flows mirror those of the underlying exposure. Unrealized gains and losses relating to the instruments are being deferred over the lives of the contracts. The premiums paid on the instruments, as measured at inception, are being amortized over their respective lives as components of interest expense. Any gains or losses realized upon the early termination of these instruments are being amortized over the respective lives of the underlying transaction or recognized immediately if the transaction is terminated earlier than initially anticipated. Gains and losses on any instruments not meeting the above criteria would be recognized in income in the current period. Subsequent gains or losses on the related financial instrument are recognized in income in each period until the instrument matures, is terminated or is sold.
Power Marketing -- The Company, through its wholly-owned subsidiary Calpine Power Services Company ("CPSC"), markets power and energy services to utilities, wholesalers, and end users. CPSC provides these services by entering into contracts to purchase or supply electricity at specified delivery points and specified future dates. In some cases, CPSC utilizes financial instruments to manage its exposure to commodity price fluctuations. On December 31, 1998, CPSC held swap contracts with several entities in order to hedge fuel costs and sale prices.
At December 31, 1998, CPSC had no net open positions which would expose the Company to risks of fluctuating market prices. The Company actively manages its positions, and it is the Company's policy to not have any open positions. Net gains and losses related to swap contracts are recognized when realized. The Company's credit risk associated with power contracts results from the risk-of-loss on non-performance by counter parties. The Company reviews and assesses counter party risk to limit any material impact to its financial position and results of operations. The Company does not anticipate non-performance by the counter parties.
New Accounting Pronouncements -- In April 1998, the American Institute of Certified Public Accountants ("AICPA") issued Statement of Position ("SOP") No. 98-5, "Reporting on the Costs of Start-Up Activities," which is effective for financial statements for fiscal years beginning after December 15, 1998. For purposes of this SOP, start-up activities are defined broadly as those one-time activities related to opening a new facility, conducting business in a new territory, conducting business with a new class of customer or beneficiary, initiating a new process in an existing facility, or commencing some new operation. Start-up activities include activities related to organizing a new entity (commonly referred to as organization costs). The Company has assessed the impact and adopted SOP 98-5 as of December 31, 1998 and determined it to be immaterial to the Consolidated Financial Statements.
In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 131, "Disclosures about Segments of an Enterprise and Related Information." This Statement establishes the reporting of information about operating segments in annual financial statements and requires that enterprises report selected information about operating segments in interim financial reports to shareholders. SFAS No. 131 also establishes standards for related disclosures about products and services, geographic areas and major customers. SFAS No. 131 is effective for fiscal years beginning after December 15, 1997. During 1998, the Company started the process of decentralization of its operations and will complete this process during 1999. This Statement will become effective upon completion
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
of this process. We do not believe that this pronouncement will have a material impact on the Consolidated Financial Statements.
In June 1998, FASB also issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". The Statement establishes accounting and reporting standards, requiring every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and require that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999. The Statement must be applied to derivative instruments and to certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997. The Company has not yet analyzed the impact of adopting SFAS No. 133 on the financial statements and has not determined the timing of or method of the adoption of SFAS No. 133. However, the Statement could increase volatility in earnings.
Reclassifications -- Certain prior years' amounts in the Consolidated Financial Statements have been reclassified where necessary to conform to the 1998 presentation.
3. ACQUISITIONS AND INVESTMENTS
The following acquisitions and investments were consummated during the year ended December 31, 1998:
Bethpage Transaction
On February 5, 1998, the Company acquired the remaining 55% interest in TBG Cogen Partners ("TBG Cogen"). The partnership owns the Bethpage Power Plant, a 57 megawatt gas-fired cogeneration facility located on Long Island, NY. The total purchase price of $5.0 million consisted of: (i) a $4.6 million cash payment and (ii) a $375,000 option applied toward the purchase, subject to final adjustments. The Company was also assigned all of General Electric's interest as operator of the Bethpage Power Plant.
Upon the acquisition of the remaining 55% interest, the Company assumed the outstanding debt of TBG Cogen. On March 31, 1998, the Company made a payment to Toronto Dominion, Inc. of approximately $37.4 million to pay off the existing project debt, accrued interest, and a related interest rate swap with a portion of the net proceeds from the Senior Notes Due 2008 (see Note 7). The acquisition was accounted for as a purchase.
Texas City and Clear Lake Transaction
On March 31, 1998, the Company acquired the remaining 50% interest in the Texas City Power Plant, a 450 megawatt gas-fired cogeneration facility, and the Clear Lake Power Plant, a 377 megawatt gas-fired cogeneration facility for a purchase price of $52.8 million in cash. The Company must make certain contingent purchase payments that could approximate 2.2% of project revenue beginning in the year 2000, increasing to 2.9% in 2002. The Company acquired the remaining interests in these plants by purchasing the capital stock of Texas Cogeneration Company ("TCC") from Dominion Cogen, Inc. ("DCI"). As part of this transaction, the Company now owns a 7.5% interest in the Bayonne Power Plant, a gas-fired power plant located in Bayonne, New Jersey. The Company purchases the majority of its natural gas for the Texas power plants from Enron Capital & Trade Resources Corp. In connection with the acquisition, the Company paid approximately $105.3 million to restructure certain gas contracts with Enron Capital & Trade Resources Corp.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The purchase of the capital stock from DCI and the payment for the restructuring of certain gas contracts were funded with a portion of the net proceeds from the issuance of the Senior Notes Due 2008 (see Note 7). The acquisition was accounted for as a purchase.
On June 23, 1997, the Company acquired the initial 50% interest in the Texas City and Clear Lake Power Plants through the acquisition of 50% of the capital stock of Enron/Dominion Cogen Corp. ("EDCC") from a subsidiary of Enron Corp. EDCC was subsequently renamed TCC. In addition to the purchase of the capital stock of TCC in June 1997, the Company purchased from the project lenders $155.6 million of outstanding debt on the Texas City and Clear Lake Power Plants (approximately $53.0 million and $102.6 million, respectively).
The following represents unaudited pro forma results of operations for the years ended December 31, 1998 and 1997 assuming the acquisition occurred as of January 1, 1997 (in thousands, except per share data):
Sonoma Transaction
On July 17, 1998, the Company completed the purchase of a 60 megawatt geothermal power plant located in Sonoma County, California from the Sacramento Municipal Utility District ("SMUD") for $13.0 million. The Company is the owner and operator of the Sonoma geothermal steam fields (formerly the SMUDGEO#1 Steam Fields), that provide steam to this facility (the "Sonoma Power Plant"). Under the agreement, the Company paid SMUD $10.6 million at closing and agreed to pay an additional $2.4 million over the next two years. In connection with the acquisition, SMUD agreed to purchase 50 megawatts of electricity from the plant at current market prices plus a renewable power premium through 2001. In addition, SMUD has the option to purchase 10 megawatts of peak power production through 2005. The Company currently markets the excess electricity into the California power market.
Dow Pittsburg Transaction
On July 21, 1998, the Company completed the acquisition of a 70 megawatt natural gas-fired power plant from The Dow Chemical Company ("Dow") for approximately $13.1 million. The power plant is located at Dow's Pittsburg, California chemical facility. The Company's Pittsburg Power Plant will sell up to 18 megawatts of electricity to Dow under a ten-year power sales agreement, with the balance sold to Pacific Gas & Electric Company under an existing power sales agreement. In addition, the Company will sell approximately 200,000 lbs/hr of steam to Dow and to USS-POSCO Industries' nearby steel mill.
Tiverton Transaction
On September 28, 1998, the Company entered into a partnership agreement with Energy Management, Inc. ("EMI") to acquire an ownership interest in a 265 megawatt gas-fired plant under development in Tiverton, Rhode Island. EMI and the Company will be co-general partners for this project, with EMI acting as the managing general partner. The Company invested $40.0 million of equity in the power plant, which is scheduled to go into commercial operation in May 2000. The Company will receive up to 62.8% of all cash and income distributions from the Tiverton project until it receives a 10.5% pre-tax rate of return. Thereafter, the Company will receive 50% of all distributions.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Rumford Transaction
On November 18, 1998, the Company entered into a partnership agreement with EMI to acquire an ownership interest in a 265 megawatt gas-fired plant under construction in Rumford, Maine. EMI and the Company will be co-general partners for this project, with EMI acting as the managing general partner. The Company invested $40.0 million of equity in the merchant power plant, which is scheduled to commence commercial operation in July 2000. The Company will receive up to 66 2/3% of all cash and income distributions from the Rumford project until it receives a 10.5% pre-tax rate of return. Thereafter, the Company will receive 50% of all distributions.
4. UNCONSOLIDATED INVESTMENTS
Investments in power projects, which are accounted for under the equity method, are as follows (in thousands):
The combined results of operations and financial position of the Company's equity method affiliates are summarized below (in thousands):
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The following details the Company's income from investments in unconsolidated power projects and the service contract revenue recorded by the Company related to those power projects (in thousands):
The Company received $11.9 million and $20.3 million in distributions from Sumas for the years ended December 31, 1998 and 1997, respectively. The Company received $3.3 million and $767,000 in distributions from Lockport for the years ended December 31, 1998 and 1997. The Company received $4.1 million, $3.1 million, $2.7 million, $2.5 million and $120,000 in distributions from Kennedy International Airport, Gordonsville, Bayonne, Auburndale and Agnews, respectively, for the year ended December 31, 1998. - ---------------
(1) On March 31, 1998, the Company acquired the remaining 50% interest in Texas Cogeneration Company.
(2) On December 31, 1998, the Partnership agreement governing Sumas Cogeneration Company, L.P. ("Sumas") was amended changing the distributions schedule for the Company from the previously amended agreement dated September 30, 1997. The newly amended agreement reflects the earnings the Company was entitled to under that agreement from a variable payment schedule to a fixed payment schedule. On September 30, 1997, the partnership agreement was amended changing the distribution percentages to the partners. As provided for in the amendment, the Company's percentage share of the project's cash flow increased from 50% to approximately 70% through June 30, 2001, based on certain specified payments. Thereafter, the Company will receive 50% of the project's cash flow until a 24.5% pre-tax rate of return on its original investment is achieved, at which time the Company's equity interest in the partnership will be reduced to 0.1%. As a result of the amendment of the partnership agreement and the receipt of certain distributions during 1997, the Company's investment in Sumas was reduced to zero. Because the investment has been reduced to zero and there are no continuing obligations of the Company related to Sumas, the Company expects that income recorded in future periods will approximate the amount of cash received from partnership distributions.
(3) On February 5, 1998, the Company acquired the remaining 55% interest in TBG Cogen Partners.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
5. NOTES RECEIVABLE
In November 1995, Calpine Vapor Inc. ("Vapor") entered into agreements with Constructora y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain Mexican bank lenders to loan $18.5 million to Coperlasa in connection with a geothermal steam production contract at the Cerro Prieto geothermal resource ("Cerro Prieto Project") in Baja California, Mexico (see Note 2). The resource currently produces electricity from geothermal power plants owned and operated by Comision Federal de Electricidad ("CFE"), Mexico's national utility. The steam field contract is between Coperlasa and CFE. Vapor receives fees for technical services provided to the project. At December 31, 1998 and 1997, notes receivable were $9.4 million and $16.1 million, respectively. Interest accrues on the outstanding notes receivable at approximately 18.9%. The Company is deferring the recognition of interest income from this note until the Cerro Prieto Project generates sufficient cash flows available for distribution to support the collectibility of accrued interest.
6. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1998 and 1997 are (in thousands):
- --------------- (1) Weighted average rate before giving effect to amortization of financing cost or interest rate swaps.
Gilroy Power Plant Debt
In August 1996, the Company entered into an agreement with Banque Nationale de Paris ("BNP") to finance the acquisition of the Gilroy Power Plant. As of December 31, 1998, BNP had provided a $119.6 million loan consisting of a 15-year tranche in the amount of $87.4 million and an 18-year tranche in the amount of $32.2 million. As of December 31, 1997, BNP had provided a $120.5 million loan consisting of a 15-year tranche in the amount of $86.9 million and an 18-year tranche in the amount of $33.6 million. The debt is secured by all of the assets of the Gilroy Power Plant. Interest accrues at BNP's base rate plus an applicable margin or at the London Interbank Offered Rate ("LIBOR") plus an applicable margin. Interest on the loans is payable at least quarterly. The effective interest rate for 1998, after amortization of financing costs was 6.9%. At the Company's discretion, LIBOR based loans may be held for various maturity periods of at least 1 month and up to 12 months. The $119.6 million debt is repaid semi-annually with a final maturity date of August 28, 2014. Commitment fees are charged based on the amount of committed unused credit.
The Company entered into five interest rate swap agreements to minimize the impact of changes in interest rates. These agreements fix the interest on $108.0 million of principal of the Gilroy Power Plant debt at a weighted average interest rate of 6.7%. The interest rate swap agreements mature through August 2014. The Company is exposed to credit risk in the event of non-performance by the other parties to the swap agreements.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The non-recourse project financing is held by a subsidiary of Calpine. The debt agreement governing the non-recourse project financing generally restrict the subsidiary's ability to pay dividends, make distributions or otherwise transfer funds. The dividend restrictions require that the subsidiary provide for the payment of other obligations, including operating expenses, debt service and reserves, prior to the payment of dividends, distributions or other transfers to the Company.
The fair market value of these swaps at December 31, 1998 was approximately ($8,520,000).
Greenleaf Power Plants Debt
In June 1995, the Company entered into an agreement with Sumitomo Bank to finance the acquisition of the Greenleaf Power Plants. In August 1998, the Company entered into a sales and leaseback transaction, which resulted in the transfer of the $71.9 million of project debt to the lessor (see Note 14). Of the $71.9 million debt outstanding at December 31, 1997, $56.8 million bore interest at a fixed rate while $15.1 million bore interest at LIBOR, plus an applicable margin. The effective interest rate for 1998, after amortization for financing costs was 8.5%. The debt was secured by all of the assets of the Greenleaf Power Plants. Interest on the loans was payable at least quarterly.
TCC Debt
In June 1997, the Company entered into an agreement with The Bank of Nova Scotia to finance its acquisition of a 50% interest in TCC and the purchase from the lenders of $155.6 million of outstanding non-recourse project financing. On March 31, 1998, the Company repaid $89.6 million from a portion of the net proceeds from the initial $300.0 million offering of Senior Notes Due 2008 and the balance of $13.8 million from working capital. The outstanding debt bore interest at the Bank of Nova Scotia's base rate or LIBOR, plus an applicable margin. The effective interest rate for 1998, after amortization for financing costs was 8.6%.
On April 9, 1998, the Company terminated an existing interest rate swap agreement related to $102.6 million of debt for the Clear Lake Power Plant, which the Company purchased on June 23, 1997. The Company paid approximately $3.7 million to close its position with the Bank of Nova Scotia and recorded a purchase price adjustment of approximately $2.3 million, which was the market value of the swap on June 23, 1997. The remaining $1.4 million was deferred and is being amortized over the remaining life of the swap.
Pasadena Power Plant Debt
In December 1996, the Company entered into an agreement with ING (U.S.) Capital LLC ("ING") to provide $151.8 million of non-recourse project financing for construction of the Pasadena Power Plant. There were no borrowings as of December 31, 1997. Borrowings commenced in January 1998. On July 24, 1998, the Company repaid the $52.1 million remaining balance outstanding from a portion of the net proceeds of the secondary $100.0 million offering of Senior Notes due 2008. The remaining project construction costs were funded by Senior Notes due 2008 and working capital of the Company. The outstanding debt bore interest at ING's base rate or the Federal Funds Rate plus an applicable margin or at LIBOR plus an applicable margin. The effective interest rate for 1998, after giving effect to the interest rate swap, was 7.9%. Interest on the loans was payable at least quarterly.
The Company entered into an interest rate swap to minimize the impact of changes in interest rates. The Company retained this interest swap upon termination of the underlying project financing and redesignated it to other floating rate financings. At December 31, 1998, the fair market value of this interest rate swap was approximately ($9,674,000).
The Company has entered into two anticipatory hedges to fix the interest rates on future project financings. The Company intends to enter into this project financings during the first six months of 1999.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
These anticipatory hedges fix an interest rate on $175.0 million at $6.1% interest. At December 31, 1998, the fair market value of these hedges was approximately ($7,960,000) and is being deferred and will be amortized over the future project financings.
7. SENIOR NOTES
Senior Notes payable consist of the following as of December 31, 1998 and 1997 (in thousands):
The Company has completed a series of public debt offerings since 1994. Transaction costs in connection with the debt offerings are capitalized as Deferred Financing Costs in the accompanying Consolidated Financial Statements and are being amortized over the ten-year life of the related offerings. Interest is payable semiannually at specified rates. There are no sinking fund or mandatory redemptions of principal before the maturity dates of each offering. The Senior Note indentures limit the Company's ability to incur additional debt, pay dividends, sell assets and enter into certain transactions.
Senior Notes Due 2004
The Senior Notes due 2004 bear interest at 9 1/4% per year, payable semi-annually on February 1 and August 1 each year and mature on February 1, 2004. The Senior Notes are redeemable, at the option of the Company, at any time on or after February 1, 1999 at various redemption prices. In addition, the Company may redeem up to $ 36.8 million of the Senior Notes from the proceeds of any public equity offering. The effective interest rate on the $105.0 million, after amortization of deferred financing costs, was 9.6%. Based on the traded yield to maturity, the approximate fair market value of the Senior Notes due 2004 was $108.2 million and $108.7 million as of December 31, 1998 and 1997, respectively.
Senior Notes Due 2006
The Senior Notes due 2006 bear interest at 10 1/2% per year, payable semi-annually on May 15 and November 15 each year and mature on May 15, 2006. The Senior Notes 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 from the proceeds of any public equity offering. The effective interest rate on the $171.8 million, after amortization of deferred financing costs, was 10.8%. Based on the traded yield to maturity, the approximate fair market value of the Senior Notes due 2006 was $188.9 million and $196.2 million as of December 31, 1998 and 1997, respectively.
During the second and third quarter of 1998, the Company repurchased a total of $8.3 million of the Senior Notes due 2006 and recognized an extraordinary charge of $641,000 (net of tax benefit of $441,000). The Senior Notes due 2006 were redeemed at a premium plus accrued interest to the date of repurchase (see Note 12).
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Senior Notes Due 2007
The Senior Notes due 2007 bear interest at 8 3/4% per year, payable semi-annually on January 15 and July 15 each year and mature on July 15, 2007. The Senior 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 from the proceeds of any public equity offering.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
In the second quarter of 1997, the Company executed five interest rate hedging transactions related to debt. The notional value of the interest rate swaps were $182.0 million and were designed to eliminate interest rate risk for the period from May 1997 to July 1997 when the $200.0 million of 8 3/4% Senior Notes Due 2007 were priced. These interest rate hedging transactions were designated as a hedge of the anticipated bond offering, and the resulting $3.0 million cost resulting from the hedges is being amortized over the life of the bonds. The effective interest rate on the $275.0 million, after amortization of deferred financing costs, was 9.1%. Based on the traded yield to maturity, the approximate fair market value of the Senior Notes due 2007 was $288.8 million and $280.5 million as of December 31, 1998 and 1997, respectively.
Senior Notes Due 2008
On March 5, 1998, the Company terminated an existing forward Treasury bond entered into in February 1998 in anticipation of the Senior Notes due 2008 offering. The Company closed its position prior to the pricing date of the debt, which resulted in a gain of $2.3 million. The gain was deferred and is recognized as an offset to interest expense over the remaining life of the Senior Notes due 2008 using the effective interest method.
On March 31, 1998, the Company sold $300.0 million Senior Notes due 2008. After deducting discounts to initial purchasers and expenses of the offering, the net proceeds from the sale of the Senior Notes due 2008 were approximately $293.5 million. Proceeds from Senior Notes due 2008 were used as follows: (i) $52.8 million for the purchase of the remaining 50% interest in TCC (See Note 3), (ii) $105.3 million for the restructuring of certain gas contracts associated with the TCC acquisition (See Note 3), (iii) $89.6 million for the outstanding principal on the non-recourse project financing provided by The Bank of Nova Scotia, and (iv) $38.2 million for the outstanding debt on the Bethpage Power Plant (See Note 3). Transaction costs incurred in connection with the debt offering were recorded as a deferred charge and are amortized over the ten-year life of the Senior Notes due 2008 using the effective interest rate method.
Subsequent to this offering, on July 24, 1998, the Company sold $100.0 million Senior Notes due 2008. After deducting discounts to initial purchasers and expenses of the offering, the net proceeds from the sale of the Senior Notes due 2008 were approximately $98.8 million. With the net proceeds, the Company has repaid in full the non-recourse project financing on the Pasadena Power Plant of $52.1 million to ING, and has used $46.7 million for a portion of the remaining construction costs for the Pasadena Power Plant. Transaction costs incurred in connection with the debt offering were recorded as a deferred charge and are amortized over the ten-year life of the Senior Notes due 2008 using the effective interest rate method.
The Senior Notes Due 2008 bear interest at 7 7/8% per year, payable semi-annually on April 1 and October 1 each year and mature on April 1, 2008. The Senior Notes are not redeemable prior to maturity. The effective interest rate on the $400.0 million, after amortization of deferred financing costs, was 8.1%. Based on the traded yield to maturity, the approximate fair market value of the Senior Notes due 2008 was $403.0 million as of December 31, 1998.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The annual principal maturities of the non-recourse project and corporate financings as of December 31, 1998 are as follows (in thousands):
8. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
On May 15, 1998, the Company replaced its $50.0 million credit facility with a $100.0 million credit facility, which has a three-year term expiring in May 2001. The Company's $100.0 million credit facility is available through a consortium of commercial lending institutions with The Bank of Nova Scotia as agent. A maximum of $50.0 million of the credit facility may be allocated to letters of credit. At December 31, 1998, the Company had no borrowings and $26.4 million of letters of credit outstanding under the credit facility. This amount includes $8.2 million to secure performance of the Magic Valley and Pasadena Power Plants. Borrowings bear interest at The Bank of Nova Scotia's base rate plus an applicable margin or at LIBOR plus an applicable margin. Interest is paid on the last day of each interest period for such loans, at least quarterly. The credit agreement specifies that the Company maintain certain covenants, with which the Company was in compliance, as of December 31, 1998. Commitment fees related to this line of credit are charged based on 0.375% of committed unused credit.
At December 31, 1998, the Company had a loan facility with Union Bank with available borrowings totaling $1.1 million. As of December 31, 1998, the Company had no borrowings and $74,196 of letters of credit outstanding.
At December 31, 1998, the Company had a $12.0 million letter of credit outstanding with The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant.
9. PROVISION FOR INCOME TAXES
The components of the deferred tax liability, net as of December 31, 1998 and 1997 are as follows (in thousands):
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The net operating loss and credit carryforwards consist of federal net operating loss carryforwards which expire 2005 through 2010 and federal and state alternative minimum tax credit carryforwards which can be carried forward indefinitely. At December 31, 1998, the federal and state net operating loss carryforwards have been fully utilized. At December 31, 1998, federal and state alternative minimum tax credit carryforwards were approximately $15.5 million and $4.0 million, respectively. In 1998, and 1997, the Company decreased its deferred income tax liability by $4.8 million and $2.1 million, respectively, to reflect the decrease in the California tax rate due to the Company's expansion into states other than California. Realization of the deferred tax assets and federal 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 carry- forward period are reduced.
The provision for income taxes for the years ended December 31, 1998, 1997 and 1996 consists of the following (in thousands):
The Company's effective rate for income taxes for the years ended December 31, 1998, 1997 and 1996 differs from the United States statutory rate, as reflected in the following reconciliation.
10. 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 automatically become participants on the first quarterly entry date after completion of three months of service. Contributions include employee salary deferral contributions and a 3% employer profit-
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
sharing contribution. Employer profit-sharing contributions in 1998, 1997 and 1996 totaled $829,000, $588,000 and $485,000, respectively.
1996 Employee Stock Purchase Plan
The Company adopted the 1996 Employee Stock Purchase Plan ("ESPP") in July 1996. Eligible employees may purchase up to 275,000 shares of common stock at semi-annual intervals through periodic payroll deductions. Purchases are limited to 15 percent of an employee's eligible compensation, up to a maximum of $25,000 per year. Shares are purchased on January 31 and July 31 of each year. Under the ESPP, 67,086 shares were issued at a weighted average fair value of $13.79 per share in 1998. In January 1999, employees participating in the ESPP purchased an additional 42,216 shares at a weighted average fair value of $37.00 per share. 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.
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. The Company accounts for the SIP under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" under which no compensation cost has been recognized. Had compensation cost for the SIP been determined consistent with the methodology of SFAS No. 123, "Accounting for Stock-Based Compensation", the Company's net income and earnings per share would have been reduced to the following pro forma amounts (in thousands, except per share amounts):
The fair value of options granted in 1998, 1997 and 1996 was $7.22, $10.28 and $3.29 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 35%, 44%, and 27% for 1998, 1997 and 1996, risk-free interest rates of 5.25%, 5.8%, and 6.2% for 1998, 1997 and 1996, respectively, expected lives of 7 years for 1998 and 1997 and 3 years for 1996.
Because the SFAS No. 123 methodology of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. The Company may grant options for up to 4,440,899 shares under the SIP. As of December 31, 1998, the Company had granted options to purchase 2,884,440 shares of common stock. Under the SIP, the option exercise price equals the stock's fair market value on date of grant. The SIP options generally vest after
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
four years and expire after 10 years. Changes in options outstanding, granted, exercisable and cancelled by the Company during the years 1998, 1997, and 1996, whether under the option or purchase plan were as follows:
On May 1, 1998, the Company granted CCNG Investments, L.P. ("CCNG") options to purchase 1.1 million shares of the Company's common stock ("Stock Purchase Agreement"). Under the terms of the Stock Purchase Agreement, CCNG had the one-time right prior to September 28, 1998, to elect to purchase from the Company up to 1.0 million shares of the Company's common stock, $0.001 par value. CCNG did not exercise any part of this right. Additionally, prior to December 31, 1998, CCNG had the one-time right to purchase from the Company up to 50,000 shares of common stock at a price of $17 7/8 per share. On December 31, 1998, CCNG notified the Company of its intent to exercise 50,000 shares on January 4, 1999, of which the Company has determined to be immaterial.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The following tables summarizes information concerning outstanding and exercisable options at December 31, 1998:
11. STOCKHOLDERS' EQUITY
Preferred Stock and Preferred Share Purchase Rights
On June 5, 1997, the Board of Directors adopted a Stockholders Rights Plan ("Rights Plan") to strengthen the Board of Directors ability to protect the Company's stockholders. The Rights Plan is designed to protect against abusive or coercive takeover tactics that are not in the best interests of the Company and its stockholders. To implement the Rights Plan, the Board of Directors declared a dividend of one preferred share purchase right (a "Right") for each outstanding share of common stock, par value $0.001 per share, held on record as of June 18, 1997, and directed the issuance of one Right with respect to each share of Common Stock that shall become outstanding between the Record Date and the Distribution Date. On December 31, 1998, there were 20,161,581 Rights outstanding. Each Right initially represents a contingent right to purchase, under certain circumstances, one one-thousandth of a share (a "Unit") of Series A Junior Participating Preferred Stock, par value $0.001 per share (the "Preferred Stock"), of the Company at a price of $80.00 per Unit, subject to adjustment. The Rights become exercisable and trade independently from the Company's common stock upon the public announcement of the acquisition by a person or group of 15% or more of the Company'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 the Company's common stock. Each Unit of Preferred Stock purchased upon exercise of the Rights will be entitled to a dividend equal to any dividend declared per share of common stock and will have one vote, voting together with the common stock. In the event of liquidation, each share of Preferred Stock will be entitled to any payment made per share of common stock.
If the Company is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of the Company's common stock, each Right will entitle its holder to purchase at the Right's exercise price a number of the acquiring company's common shares having a market value of twice such exercise price. In addition, if a person or group acquires 15% or more of the Company'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 the Company's Preferred Stock or shares of common stock having a market value of twice such exercise price.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The Rights expire June 18, 2007, unless redeemed earlier by the Company's Board of Directors. The Board of Directors can redeem the Rights at a price of $0.01 per Right at any time before the Rights become exercisable, and thereafter only in limited circumstances.
12. 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 reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table (dollars in thousands except share data).
In 1998, the Company recognized a $641,000 extraordinary charge (net of tax benefit of $441,000), for the repurchase of $8.3 million of the 10 1/2% Senior Notes Due 2006. The notes were redeemed at a premium plus accrued interest to the date of repurchase.
Unexercised employee stock options to purchase 385,000 shares of the Company's common stock during the year ended December 31, 1997 were not included in the computation of diluted shares outstanding because such inclusion would be anti-dilutive.
13. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from three sources -- Pacific Gas & Electric Company ("PG&E"), Texas Utilities Electric Company ("TUEC"), and SMUD.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Revenues earned from these sources for the years ended, December 31, 1998, 1997 and 1996 were as follows (in thousands):
Accounts receivable at December 31, 1998, and 1997 were as follows (in thousands):
14. COMMITMENTS AND CONTINGENCIES
Production Royalties and Leases -- The Company is committed under several 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 and are not material. Under the terms of certain geothermal leases, royalties accrue at rates ranging from 7% to 12.5% of steam and effluent revenue. Certain properties also have net profits and overriding royalty interests ranging from approximately 1.45% to 28%, which are in addition to the land royalties. Most lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level.
Expenses under these agreements for the years ended December 31, 1998, 1997, and 1996 are (in thousands):
Natural Gas Purchases -- The Company enters into short-term gas purchase contracts with third parties to supply gas to its gas-fired cogeneration projects.
Cogeneration Facilities Operating and Land Leases -- The Company entered into long-term operating leases in June 1995, April 1996 and August 1998 for its Watsonville, King City, and Greenleaf cogeneration
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
facilities and the land lease for the Pasadena Power Plant. Future minimum lease payments under these leases are as follows (in thousands):
In 1998, 1997 and 1996, rent expense for cogeneration facilities operating leases amounted to $15.7 million, $16.6 million and $12.0 million, respectively. The Watsonville operating lease provides for additional contingent rents payable during the period from July through December. Contingent rent expense for 1998, 1997 and 1996 amounted to $1.5 million, $864,000 and $671,000, respectively.
The King City operating lease commitment is supported by $90.7 million of collateral securities consisting of investment grade and U.S. Treasury securities that mature serially in amounts equal to a portion of the semi-annual lease payment (see Note 2).
In August 1998, the Company entered into a sales and leaseback transaction for certain plant and equipment of its Greenleaf 1 & 2 Power Plants, two 49.5 megawatt gas-fired cogeneration facilities located in Sutter County, California, for a net book value of $108.6 million. Under the terms of the agreement, the Company received approximately $559,000 for the sale of its rights, title and interest in the stock of Calpine Greenleaf Corporation and transferred all of its non-recourse financing of $71.6 million (see Note 6) and deferred taxes of $21.4 million. A loss of $15.6 million was recorded on the balance sheet and is being amortized over the term of the lease through June 2014.
Office and Equipment Leases -- The Company leases its corporate office and regional offices in Boston, Massachusetts, Houston, Texas, Pleasanton, California, and Santa Rosa, California under noncancellable operating leases expiring through 2002. Future minimum lease payments under these leases are as follows (in thousands):
Lease payments are subject to adjustments for the Company's pro rata portion of annual increases or decreases in building operating costs. In 1998, 1997 and 1996 rent expense for noncancellable operating leases amounted to $1.2 million, $1.2 million and $1.0 million, respectively.
Capital expenditures -- At December 31, 1998, the Company is under contract with Siemens Westinghouse Power Corporation for a total of $322.2 million for the purchase of six turbines related to three power
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
development projects. Approximate payments related to these turbines are $231.7, $85.3 and $5.2 million in 1999, 2000, and 2001, respectively.
Litigation
Legal Matters -- On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and certain other parties, including the Company. Some of Indeck's claims relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously interfered with Indeck's contractual rights to purchase such interests and conspired with other parties to do so. Indeck is seeking $25.0 million in compensatory damages, $25.0 million in punitive damages, and the recovery of attorneys' fees and costs. In July 1998, the court granted motions to dismiss, without prejudice, the claims against Calpine Gordonsville, Inc. and Calpine Auburndale, Inc. In August 1998, Indeck filed an amended complaint and the defendants filed motions to dismiss. A hearing on those motions is scheduled for the end of February 1999. The Company is unable to predict the outcome of these proceedings, but does not believe this will have a material adverse effect on the Consolidated Financial Statements.
There is currently a dispute between Texas-New Mexico Power Company ("TNP") and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear Lake Power Plant, regarding certain costs and other amounts that TNP has withheld from payments due under the power sales agreement from August 1997 until October 1998. TNP has withheld approximately $450,000 per month related to transmission charges. In October 1997, CLC filed a petition for declaratory order with the Texas Public Utilities Commission ("Texas PUC") requesting a declaration that TNP's withholding is in error, which petition is currently pending. Also, as of December 31, 1998, TNP has withheld approximately $7.7 million of standby power charges. In addition to the Texas PUC petition, CLC filed an action in Texas courts on October 2, 1997, alleging TNP's breach of the power sales agreement and is seeking refund of the standby charges. In October 1998, TNP and CLC reached an agreement in principle to settle all outstanding disputes. The parties are currently finalizing the documentation of the settlement which must be approved by the Texas PUC. Both the Texas PUC action and the court action have been put on hold pending completion of the settlement. The Company does not believe this has a material adverse effect on the consolidated financial statements.
An action was filed against Lockport Energy Associates, L.P. ("LEA") and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG has requested the Court to direct NYPSC and the Federal Energy Regulatory Commission (the "FERC") to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated the Public Utility Regulatory Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing to reform the NYSEG contract that was previously approved by the NYPSC. Although it is unable to predict the outcome of this case, in any event, the Company retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase the Company's interest in the Lockport Power Plant for $18.9 million, less equity distributions received by the Company, at any time before December 19, 2001.
The Company is involved in various other claims and legal actions arising out of the normal course of 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, although no assurance can be given in this regard.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
15. SUBSEQUENT EVENTS
On January 4, 1999, the Company entered into a credit agreement with ING to provide $265.0 million of non-recourse project financing for the Pasadena expansion, a 510 megawatt gas-fired cogeneration project.
16. 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, and variations in levels of production. Furthermore, the majority 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 50 common stockholders of record at December 31, 1998. No dividends were paid for the years ended December 31, 1998 and 1997.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
CALPINE CORPORATION AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS (IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, 1998
FOR THE YEAR ENDED DECEMBER 31, 1997
FOR THE YEAR ENDED DECEMBER 31, 1996
- --------------- (1) Provision for write-off of project development expenses.
INDEPENDENT AUDITOR'S REPORT
To the Partners Sumas Cogeneration Company, L.P. and Subsidiary
We have audited the accompanying consolidated balance sheet of Sumas Cogeneration Company, L.P. and Subsidiary as of December 31, 1998 and 1997, and the related consolidated statements of income, changes in partners' deficit, and cash flows for each of the three years ended December 31, 1998, 1997 and 1996. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sumas Cogeneration Company, L.P. and Subsidiary as of December 31, 1998 and 1997, and the results of their operations and cash flows for each of the three years ended December 31, 1998, 1997 and 1996 in conformity with generally accepted accounting principles.
MOSS ADAMS LLP
Everett, Washington January 20, 1999
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEET
ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF INCOME
The accompanying notes are an integral part of these consolidated financial statements.
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' DEFICIT FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The accompanying notes are an integral part of these consolidated financial statements.
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General -- Sumas Cogeneration Company, L.P. (the Partnership) is a Delaware limited partnership formed in 1991 between Sumas Energy, Inc. (SEI), the general partner which currently holds a 50% interest in the profits and losses of the Partnership, and Whatcom Cogeneration Partners, L.P. (Whatcom), the sole limited partner which holds the remaining 50% Partnership interest. In addition, Whatcom is entitled certain additional distribution amounts through December 31, 2000. Whatcom is owned through affiliated companies by Calpine Corporation (Calpine). The Partnership has a wholly-owned Canadian subsidiary, ENCO Gas, Ltd. (ENCO), which is incorporated in New Brunswick, Canada. The consolidated financial statements include the accounts of the Partnership and ENCO (collectively, the Company) whose functional currency is deemed to be in U.S. dollars. All intercompany profits, transactions and balances have been eliminated in consolidation.
The Partnership owns and operates an electrical generation facility (the Generation Facility) in Sumas, Washington. The Generation Facility is a natural gas-fired combined cycle electrical generation plant which has a nameplate capacity of approximately 125 megawatts. Commercial operation of the Generation Facility commenced in April 1993. The Generation Facility includes a lumber dry kiln facility and a 3.5 mile private natural gas pipeline.
ENCO owns and operates a portfolio of natural gas reserves in British Columbia and Alberta, Canada, which provide a dedicated fuel supply for the Generation Facility (collectively, the Project). ENCO produces and supplies natural gas to the Generation Facility and to third parties. Prior to November 1, 1998, the Generation Facility also received a portion of its fuel under contracts with third parties.
The Partnership produces and sells its entire electrical output to Puget Sound Energy, Inc. (Puget) under a 20-year electricity sales contract. The electricity sales contract provides for the sale of electrical output at stated prices through 2012. The electricity sales contract also provides for the electrical output of the Generation Facility to be displaced when the cost of Puget's replacement power is less than the Company's incremental power generation costs. The Company receives a share of the net savings from displacement. During 1998 and 1997, the Generation Facility was displaced for approximately one month and six months, respectively. Under the electricity sales contract, the Partnership is required to be certified as a qualifying cogeneration facility as established by the Public Utility Regulatory Policy Act of 1978, as amended, and as administered by the Federal Energy Regulatory Commission.
The Generation Facility produced and sold kilowatt hours of electricity to Puget as follows:
The Partnership leases a kiln facility and sells steam under a 20-year agreement for the purchase and sale of steam, and lease of the kiln (Note 6) to Socco, Inc. (Socco), a custom lumber drying operation owned by an affiliate of the Partnership. Steam use requirements under the agreement with Socco were established to maintain the qualifying cogeneration facility status of the Generation Facility.
The Partnership -- SEI assigned all its rights, title, and interest in the Project, including the Puget contract, to the Partnership in exchange for its Partnership interest. During 1998, the Partnership Agreement was amended to reallocate distributions among the partners. SEI and Whatcom are both currently entitled to a 50% interest in the profits, losses and cash flow of the Partnership. In addition, Whatcom is entitled to an additional allocation of profits, losses and cash flows for the period through December 31, 2000. After
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Whatcom has received cumulative distributions representing its target return, SEI's share of operating distributions will increase to 99.9% and Whatcom's share of operating distributions will decrease to 0.1%.
Distributions -- Distributions of operating cash flows are permitted quarterly after required deposits are made and minimum cash balances are met, and are subject to certain other restrictions. For the year ended December 31, 1998, distributions totaling $16,601,858 were paid or accrued. On January 29, 1999, the December 31, 1998 accrued distributions in the amount of $2,922,603 will be paid.
Revenue recognition -- Revenue from the sale of electricity is recognized based on kilowatt hours generated and delivered to Puget at contractual rates. Revenue from displacement is recognized in the period to which the displacement relates. Revenue from the sale of natural gas is recognized based on volumes delivered to customers at contractual delivery points and rates. The costs associated with the generation of electricity and the delivery of gas, including operating and maintenance costs, gas transportation and royalties, are recognized in the same period in which the related revenue is earned and recorded.
Gas acquisition and development costs -- ENCO follows the full cost method of accounting for gas acquisition and development expenditures, wherein all costs related to the development of gas reserves in Canada are initially capitalized. Costs capitalized include land acquisition costs, geological and geophysical expenditures, rentals on undeveloped properties, cost of drilling productive and nonproductive wells, and well equipment. Gains or losses are not recognized upon disposition or abandonment of natural gas properties unless a disposition or abandonment would significantly alter the relationship between capitalized costs and proven reserves.
All capitalized costs of gas properties, including the estimated future costs to develop proven reserves, are depleted using the unit-of-production method based on estimated proven gas reserves as determined by independent engineers. ENCO has not assigned any value to its investment in unproven gas properties and, accordingly, no costs have been excluded from capitalized costs subject to depletion.
Costs subject to depletion under the full cost method include estimated future costs of dismantlement and abandonments of ENCO of $3,327,000 in 1998, $3,560,000 in 1997 and $3,718,000 in 1996. This includes the cost of production equipment removal and environmental cleanup based upon current regulations and economic circumstances. The provisions for future removal and site restoration costs of $162,000 in 1998, $168,000 in 1997 and $177,000 in 1996, are included in depletion expense.
Capitalized costs are subject to a ceiling test which limits such costs to the aggregate of the net present value of the estimated future cash flows from the related proven gas reserves. The ceiling test calculation is made by estimating the future net cash flows, based on current economic operating conditions, plus the lower of cost or fair market value of unproven reserves, and discounting those cash flows at an annual rate of 10%.
Joint venture accounting -- A significant portion of ENCO's natural gas production activities are conducted jointly with others and, accordingly, these consolidated financial statements reflect only ENCO's proportionate interest in such activities.
Foreign exchange gains and losses -- Foreign exchange gains and losses as a result of translating Canadian dollar transactions and Canadian dollar denominated cash, accounts receivable and accounts payable transactions are recognized in the statement of income.
Cash and cash equivalents -- For purposes of the statement of cash flows, cash and cash equivalents consist of cash and short-term investments in highly liquid instruments such as certificates of deposit, money market accounts and U.S. treasury bills with an original maturity of three months or less.
Concentration of credit risk -- Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash and short-term investments in highly liquid instruments such as
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
certificates of deposit, money market accounts and U.S. treasury bills with maturities of three months or less, and accounts receivable. The Company's cash and cash equivalents are primarily held with two financial institutions. Accounts receivable are primarily due from Puget.
Spare parts inventory -- Spare parts inventory includes major components of plant and equipment which are expected to be utilized in the normal course of maintenance and repair. All spare parts are carried at the lower of cost (first in, first out method) or market.
Depreciation -- The Company provides for depreciation of property, plant and equipment using the straight-line method over estimated useful lives which range from 7 to 40 years for plant and equipment, and 3 to 7 years for furniture and fixtures.
Amortization of other assets -- The Company provides for amortization of other assets using the straight-line method as follows:
Income taxes -- Profits or losses of the Partnership are allocated directly to the partners for income tax purposes.
ENCO is subject to Canadian income taxes and accounts for income taxes on the liability method. The liability method recognizes the amount of tax payable at the date of the consolidated financial statements, as a result of all events that have been recognized in the consolidated financial statements, as measured by currently enacted tax laws and rates. Deferred income taxes are provided for temporary differences in recognition of revenues and expenses for financial and income tax reporting purposes.
Use of estimates -- The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Reclassifications -- Certain 1997 amounts have been reclassified to conform with the 1998 presentation.
2. PROPERTY, PLANT AND EQUIPMENT
Depreciation expense was $3,163,108 in 1998, $3,184,659 in 1997 and $3,159,774 in 1996. Depletion expense was $2,137,000 in 1998, $1,861,800 in 1997 and $1,606,000 in 1996.
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
3. OTHER ASSETS
Amortization expense was $1,219,949 in 1998, $1,851,652 in 1997 and $1,805,748 in 1996.
4. LONG-TERM DEBT
The Partnership and ENCO have four loan agreements with The Prudential Insurance Company of America (Prudential) and Credit Suisse First Boston (Credit Suisse), (collectively, the Lenders). On December 31, 1998, the Partnership entered into its fourth loan agreement with Prudential, the Secured Junior Subordinated Loan (the Junior Subordinated Loan). The Junior Subordinated Loan provides up to $40 million for cash distributions, development of gas reserves, and working capital purposes. At December 31, 1998 and 1997, amounts outstanding under the loan agreements, by entity, were as follows:
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Scheduled annual principal payments under the loan agreements as of December 31, 1998 are as follows:
The Partnership's loans are comprised of fixed and variable interest rate loans. Fixed rate interest is payable quarterly and variable rate interest is payable monthly at either the London Interbank Offered Rate (LIBOR), certificate of deposit rate or Credit Suisse's base rate, plus an applicable margin which ranges from .5% to 1.75% as stated in the loan agreements. During the year ended December 31, 1998, variable interest rates ranged from 6.03% to 7.44%. The loans mature between May 2008 and December, 2010. In addition, the Subordinated Loan includes a Revolving Line of Credit in the amount of $1,000,000 of which there were no balances outstanding at December 31, 1998 or 1997.
The Partnership pays Prudential an agency fee of $50,000 per year until the loans mature. The Partnership pays Credit Suisse an agency fee of $40,000 per year, adjusted annually by an inflation index, until the loans mature. The loans are collateralized by substantially all the Company's assets and interests in the Project. Additionally, the Company's rights under all contractual agreements are assigned as collateral. The Partnership and ENCO loans are cross-collateralized and contain cross-default provisions.
Under the terms of the loan agreements and the deposit and disbursement agreements with the Lenders, the Company is required to establish and fund certain accounts held by Credit Suisse and Royal Trust as security agents. The accounts require specified minimum deposits and funding levels to meet current and future operating, maintenance and capital costs, and to provide certain other reserves for payment of principal, interest and other contingencies. These accounts are presented as restricted cash and cash equivalents and include cash, certificates of deposit, money market accounts and U.S. treasury bills, all with maturities of 3 months or less. The current portion of restricted cash and cash equivalents is based on the amount of current liabilities for obligations, which may be funded from the restricted accounts. The balance of restricted cash and cash equivalents has been classified as a non-current asset.
5. INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of the following:
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The principal sources of temporary differences resulting in deferred tax assets and liabilities are as follows:
The Company believes, based upon available information, that all deferred assets will be realized in the normal course of business and no valuation allowance is necessary.
The provision for income taxes differs from the Canadian statutory rate principally due to the following:
As of December 31, 1998, ENCO has non-capital loss carryforwards of approximately $3,161,000, which may be applied against taxable income of future periods which expire from 1999 through 2004.
6. RELATED PARTY TRANSACTIONS AND COMMITMENTS
Administrative services -- As managing partner of the Partnership, SEI receives a fee of $300,000 per year for periods after December 1995. The fee is subject to annual adjustment based upon an inflation index. Approximately $334,000 in 1998, $333,000 in 1997 and $311,000 in 1996, was paid to SEI under this agreement.
Operating and maintenance services -- The Partnership has an operating and maintenance agreement with a related party to operate, repair and maintain the Project. For these services, the Partnership pays a fixed fee of $1,140,000 per year, adjustable based on the Consumer Price Index, an annual base fee of $150,000 per year, also adjustable based on the Consumer Price Index, and certain other reimbursable expenses as defined in the agreement. In addition, the agreement provides for an annual performance bonus of up to $250,000, adjustable based on the Consumer Price Index, based on the achievement of certain annual performance levels. Payment of the performance bonus is subordinated to the payment of operating expenses, debt service and required deposits, and minimum balances under the loan agreements, and deposit and disbursement
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
agreements. This agreement expires on the later of the date Whatcom receives Target Return or the date on which certain loans to affiliates of SEI are repaid. The agreement contains optional renewal terms. Approximately $2,200,050 in 1998, $2,074,000 in 1997, and $2,014,000 in 1996 was earned under this agreement.
Thermal energy and kiln lease -- The Partnership has a 20-year thermal energy and kiln lease agreement with Socco. Under this agreement, Socco leases the premises and the kiln, and purchases certain amounts of thermal energy delivered to dry lumber. Income recorded from Socco was approximately $44,000 in 1998, and $9,000 in 1996.
Consulting services -- ENCO has an agreement with National Energy Systems Company (NESCO), an affiliate of SEI, to provide consulting services for $8,000 per month, adjustable based upon an inflation index. The agreement automatically renews for one-year periods, unless written notice of termination is served by either party. Approximately $112,000 in 1998, $119,000 in 1997, and $107,000 in 1996 was paid under this agreement.
Fuel supply and purchase agreements -- The Partnership has a fixed price natural gas sale and purchase agreement with ENCO. The agreement requires ENCO to deliver up to a maximum daily contract quantity of 24,900 MMBtu's of natural gas per day. Partnership payments to ENCO under the agreement are eliminated in consolidation. The agreement expires on the twentieth anniversary of the date of commercial operation.
The Partnership and ENCO have a gas management agreement with Engage Energy Canada L.P. (Engage). The gas management agreement was assigned to Engage by Westcoast Gas Services, Inc. during 1997. Engage is paid a gas management fee for each MMBtu of gas delivered to the Generation Facility. The gas management fee is adjusted annually, based on the British Columbia Consumer Price Index. The gas management agreement expires October 31, 2008, unless terminated earlier as provided for in the agreement.
As collateral for the obligations of the Company under the gas supply and gas management agreements with Engage, the Partnership has in place an irrevocable standby letter of credit with Credit Suisse in favor of Engage. As of December 31, 1998 and 1997, the letter of credit had a face amount of $500,000.
ENCO is committed to the utilization of gathering, processing and pipeline capacity on the Westcoast Energy, Inc. (WEI) system. These firm capacity commitments are under contracts of varying lengths. Firm capacity has been accepted at an annual cost of approximately $7,187,000 in 1998, $3,553,000 in 1997 and $3,526,000 in 1996.
Future minimum capacity commitments at December 31, 1998 are as follows:
As collateral for the obligations of ENCO under the capacity contracts with WEI, the Partnership has in place an irrevocable standby letter of credit with Credit Suisse in favor of WEI. As of December 31, 1998 and 1997, the letter of credit had a face amount of approximately $582,000 (Canadian) and $384,000 (Canadian), respectively.
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Utility services -- The Partnership has agreements for utility services with the City of Sumas, Washington (the City). The City provides water and sewer services to the Partnership. Water is provided at the City's wholesale rate charged to external association customers. The City began providing industrial sewer service to the Partnership in December 1998. Sewer rates are charged at the City's industrial rate for large users, plus an amount that will repay the City for sewer improvements made by the City to accommodate the Partnership's industrial sewage. Both the water supply and sewer services agreements provide for minimum payments should the Partnership not purchase certain minimum amounts.
The Partnership maintains a letter of credit in favor of the City to support its obligations to pay future sewer charges to the City. As of December 31, 1998 and 1997, the letter of credit had a face amount of $625,000 and $700,000, respectively.
The Partnership also has an agreement for waste water disposal with the City of Bellingham, Washington. The City of Bellingham has agreed to accept up to 70,000 gallons of waste water daily at a rate of $0.0115 per gallon. The agreement expires on December 31, 2003.
The Partnership has a permit for waste water disposal from the Washington State Department of Ecology which expires June 30, 2000.
Lease commitments -- In December 1990, the Partnership entered into a 23.5-year land lease which may be renewed for five consecutive five-year periods. Rental expense was approximately $55,600 in 1998, $55,600 in 1997 and $56,600 in 1996.
In 1997, ENCO signed an operating lease for office space which expires in March 2001. Monthly rental expense is approximately $1,846. Rental expense was approximately $21,900 in 1998, $19,000 in 1997 and $20,400 in 1996.
Future minimum land and office lease commitments as of December 31, 1998 are as follows:
Affiliate loan -- In 1994, the sole shareholder of SEI obtained a loan from Calpine in the amount of $10,000,000. During 1997, Calpine assigned the loan to a third party. The sole shareholder of SEI entered into an amended and restated loan agreement with the new lender.
Affiliate revolving line of credit -- In 1997, the sole shareholder of SEI entered into a Revolving Loan Agreement with Calpine. The loan agreement provides for Calpine to loan up to $15,000,000 to the SEI shareholder. Loans bear interest at a fixed rate of 12.5% and are due in full on December 31, 2003. As of December 31, 1998 and 1997, no borrowings had been made under the loan.
7. FAIR VALUES OF FINANCIAL INSTRUMENTS
The carrying amount of all cash and cash equivalents, accounts receivable and accounts payable reported in the consolidated balance sheet is estimated by the Company to approximate their fair value.
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The Company is not able to estimate the fair value of its debt with a carrying amount of $143,527,454 and $133,400,004 at December 31, 1998 and 1997, respectively. There is no ability to assess current market interest rates of similar borrowing arrangements for similar projects because the terms of each such financing arrangement is the result of substantial negotiations among several parties.
8. YEAR 2000
The Year 2000 issue is the result of computer programs being written using two digits rather than four to define the applicable year. Any of the Company's computer programs or equipment that have date-sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. In addition, certain hardware components may not function properly as the year 2000 approaches. This could result in a system failure or miscalculations causing disruptions of operations.
Management is reviewing the Company's computer software programs, hardware components and other systems, and believes any Year 2000 issues will be resolved without a material effect on the Company's financial condition and results of operations.
EXHIBIT INDEX