The Calpine Corporation has interests in three geothermal power generation facilities [266] with a total capacity of 67 MW and five geothermal steam fields [267] that supply utility power plants with a total current capacity of approximately 468 MW. Steam produced by the geothermal steam fields is sold to utility-owned power plants. The geothermal power generation projects in which the Company has an interest produce electricity, thermal energy and steam that are typically sold pursuant to long-term, take-and-pay power or steam sales agreements generally having original terms of 20 or 30 years.
Revenue from a power sales agreement usually consist of two components: energy payments and capacity payments. Energy payments are based on a power plant’s net electrical output with payment rates sometimes 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 either a power plant’s net electrical output or its available capacity. Energy payments are made for each kilowatt hour of energy delivered, while capacity payments are made whether or not any electricity is delivered. The Company is paid for steam supplied by its steam fields on the basis of the amount of electrical energy produced or steam delivered.
West Ford Flat Facility The West Ford Flat geothermal facility (the “West Ford Flat Facility”) consists of a 27 MW geothermal power plant and associated steam fields located in the eastern portion of The Geysers area. The West Ford Flat Facility commenced commercial operation in December 1988. Since start-up, the West Ford Flat Facility has operated at an average availability of approximately 98 percent. Electricity generated by the West Ford Flat Facility is sold to PG&E under a 20-year power sales agreement terminating in 2008 which contains payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $167kW/yr for 27 MW of firm capacity for the term of the agreement, so long as the West Ford Flat Facility delivers 80 percent of its firm capacity during certain designated periods of the year. In addition, the power sales agreement provides for energy payments for electricity actually delivered based on a fixed price derived from a scheduled forecast of energy prices over the initial ten-year term of the agreement ending December 1998. The schedule of fixed average energy prices in effect through 1998 under the West Ford Flat Facility power sales agreement is as follows:
| 1996 | $128.90/MWh |
| 1997 | $138.30/MWh |
| 1998 | $138.30/MWh |
Thereafter, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E’s avoided cost of energy (as determined by the CPUC). PG&E’s avoided cost of energy varies from month to month and has ranged from an annual average of $18.40/MWh to $29.60/MWh since 1992. PG&E’s avoided cost of energy varies from month to month and has ranged from an annual average of $18.40/MWh to $29.60/MWh since 1992. During 1995, PG&E’s avoided cost of energy averaged approximately $18.40/MWh. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased under this agreement by 1,000 hours. The Company currently expects the maximum amount of curtailment allowed under the agreement during 1996.
The Company believes that the geothermal reserves that supply energy for use by the West Ford Flat Facility will be sufficient to operate at full capacity for the entire term of the power sales agreement due principally to high reservoir pressures, low projected decline rates, limited development in adjacent areas and the substantial productive acreage dedicated to the West Ford Flat Facility.
The Bear Canyon facility (the “Bear Canyon Facility”) consists of a 20 MW geothermal power plant and associated steam fields located in the eastern portion of The Geysers area two miles south of the West Ford Flat Facility. The Bear Canyon Facility commenced commercial operation in October 1988. Since start-up, the Bear Canyon Facility has operated at an average availability of approximately 98.4 percent.
Electricity generated by the Bear Canyon Facility is sold to PG&E under two 10-MW, 20-year power sales agreements terminating in 2008 which contain payment provisions for capacity and energy. One of the power sales agreements provides for a firm capacity payment of $156/kW/yr four MW for the term of the agreement, so long as the Bear Canyon Facility delivers 80 percent of its firm capacity during certain designated periods of the year, and an as-delivered capacity payment for the additional six MW. The other agreement provides for an as-delivered capacity payment for the entire 10 MW. Both agreements provide for energy payments for electricity actually delivered based on a fixed price basis through the initial ten-year term of the agreement ending September 1998. The following schedule sets forth the fixed average energy prices and the as-delivered capacity prices through 1998 for energy deliveries under the Bear Canyon Facility power sales agreements:
| 1996 | $128.90/MWh | $176/kW/yr |
| 1997 | $138.30/MWh | $188/kW/yr |
| 1998 | $138.30/MWh | $188/kW/yr |
Thereafter, PG&E will pay for energy delivered at prices equal to PG&E’s avoided cost of energy (as determined by the CPUC), and will pay for as-delivered capacity at the greater of $188/kW/yr or PG&E’s then current as-delivered capacity rate. PG&E’s avoided cost of energy varies from month to month and has ranged from an annual average of $18.40/MWh to $29.60/MWh since 1992. During 1995, PG&E’s avoided cost of energy averaged approximately $18.40/MWh. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased under this agreement by 1,000 hours. In the event of any such curtailment, the Company’s results of operations may be materially adversely affected. The Company currently expects the maximum amount of curtailment allowed under the agreement during 1996.
The Company believes that the geothermal reserves for the Bear Canyon Facility will be sufficient to operate at full capacity for substantially all of the remaining term of the power sales agreements due principally to high reservoir pressures, low projected decline rates, limited development in adjacent areas and the substantial productive acreage dedicated to the Bear Canyon Facility. During 1995, the Bear Canyon Facility generated approximately 165 GWh.
The Aidlin geothermal facility (the “Aidlin Facility”) consists of a 20 MW geothermal power plant and associated steam fields located in the western portion of The Geysers area. Since start-up, the Aidlin Facility has operated at an average availability of approximately 99 percent.
Electricity generated by the Aidlin Facility is sold to PG&E under two 10-MW, 20-year power sales agreements terminating in 2009 which contain payment provisions for capacity and energy. The power sales agreements provide for an aggregate firm capacity payment for 17 MW of $167/kW/yr for the term of the agreements, so long as the Aidlin Facility delivers 80 percent of its capacity during certain designated periods of the year. In addition, the Aidlin Facility power sales agreements provide for energy payments for 20 MW based on a schedule of fixed energy prices in effect through 1999 as follows:
| 1996 | $128.90/MWh |
| 1997 | $138.30/MWh |
| 1998 | $138.30/MWh |
| 1999 | $138.30/MWh |
Thereafter, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E’s avoided cost of energy (as determined by the CPUC). PG&E’s avoided cost of energy varies from month to month and has ranged from an annual average of $18.40/MWh to $29.60/MWh since 1992. During 1995, PG&E’s avoided cost of energy averaged approximately $18.40/MWh. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased under this agreement by 1,000 hours. The Company currently expects the maximum amount of curtailment under the agreement in 1996.
The output of the Aidlin Facility is expected to decline over the remaining life of the facility unless additional reserves are developed on existing or adjacent leases and enhanced water injection projects are successful in reducing field declines. During 1995, the Aidlin Facility generated approximately 174 GWh and revenue of $21.7 million.
The Company acquired Thermal Power Company on September 9, 1994 for a purchase price of $66.5 million. Thermal Power Company owns a 25 percent undivided interest in certain geothermal steam fields located at The Geysers. Unocal owns the remaining 75 percent interest in the steam fields and operates and maintains the steam fields. The Thermal Power Company Steam Fields include the leasehold rights to 13,908 acres of steam fields which supply steam to 12 PG&E power plants located in The Geysers and include 247 production wells, 19 injection wells and 52 miles of steam-transporting pipeline. The 12 plants have a nameplate capacity of 978 MW and currently have the capability to operate at 604 MW providing the Company with an effective interest in 151 MW. The steam fields commenced commercial operation in 1960.
The Thermal Power Company Steam Fields produce steam for sale to PG&E under a long-term steam sales agreement. Under this steam sales agreement, the Company is paid on the basis of the amount of electricity produced by the power plants to which steam is supplied. PG&E is obligated to use its best efforts to operate its power plants to maintain monthly and annual steam field capacity. The price paid for steam under the steam sales agreement is determined according to a formula that consists of the average of three indices multiplied by a fixed price of $16.50/MWh. The indices used are the Producer Price Index for Crude Petroleum, the Producer Price Index for Natural Gas and the Consumer Price Index (“CPI”). The price of steam under the steam sales agreement in 1995 was $16.47/MWh.
In 1995 and early 1996, the Company, Unocal, and PG&E entered into certain short-term arrangements under which PG&E purchased a portion of the steam that PG&E would have curtailed under the steam sales agreement at a lower price. Such parties are currently in the process of negotiating an ongoing alternative pricing arrangement for steam that PG&E is entitled to curtail in the future. The steam sales agreement with PG&E also provides for offset payments, which constitute a remedy for insufficient steam. Under the steam sales agreement, the Company is required to pay PG&E for the unamortized costs, including site clean-up, removal and abandonment costs, of power plants that are installed but are unused as a result of steam supply deficiency. The offset payments are calculated based upon a fixed amortization schedule for all power plants, which may be adjusted for future capital expenditures, and upon the steam fields’ capacity in MW.
In accordance with the steam sales agreement, PG&E may curtail the power plants that receive steam to produce energy from lower cost sources. PG&E is contractually obligated to operate all of the power plants at a minimum of 40 percent of the field capacity during any given year, and at 25 percent of the field capacity in any given month. During 1995, the Thermal Power Company Steam Fields experienced extensive curtailment of steam production due to low gas prices and abundant hydro power. The Company receives a monthly fee for PG&E’s right to curtail its power plants. The steam sales agreement with PG&E terminates two years after the closing of the last operating power plant. In addition, PG&E may terminate the contract earlier with a one-year written notice. If PG&E terminates in accordance with the steam sales agreement, the Company will provide capacity maintenance services for five years after the termination date, and will retain a right of first refusal to purchase the PG&E facilities at PG&E’s unamortized cost. Alternatively, the Company may terminate the agreement with a two-year written notice to PG&E. If the Company terminates, PG&E has the right to take assignment of the Thermal Power Company Steam Fields’ facilities on the date of termination. In that case, the Company would continue to pay offset payments for three years following the date of termination. Under the steam sales agreement, PG&E may retire older power plants upon a minimum of six-months’ notice. The Company is unable to predict PG&E’s schedule for the retirement of such power plants, which may change from time to time. If steam is abandoned (i.e., cannot be transported to the remaining plants), the abandoned steam may be delivered for use to other PG&E power plants, subject to existing contract conditions, or to other customers upon closure of a PG&E power plant.
The Thermal Power Company Steam Fields currently supply steam sufficient to operate the PG&E power plants at approximately 60 percent of their combined nameplate capacity. This percentage reflects a decline in productivity since the commencement of operations. While it is not possible to accurately predict long-term steam field productivity, the Company has estimated that the current annual rate of decline in steam field productivity of the Thermal Power Company Steam Fields was approximately 9 percent until 1995, during which year extensive curtailment interrupted the decline trend. The Company expects steam field productivity to continue to decline in the future. The Company plans to work with Union Oil and PG&E to partially offset the expected rate of decline by the development of water injection projects and power plant improvements. During 1995, the PG&E power plants produced 2,688 GWh.
The Company holds the leasehold rights to 1,631 acres of steam fields (the “PG&E Unit 13 and Unit 16 Steam Fields”) that supply steam to PG&E’s Unit 13 power plant (the “Unit 13”) and PG&E’s Unit 16 power plant (the “Unit 16”), all of which are located in The Geysers. Unit 13 and Unit 16 have nameplate capacities of 134 and 113 MW, respectively, and currently operate at outputs of approximately 100 and 78 MW, respectively. The PG&E Unit 13 Steam Field includes 956 acres, 30 production wells, two injection wells and five miles of pipeline, and commenced commercial operations in May 1980. The PG&E Unit 16 Steam Field includes 675 acres, 19 producing wells, two injection wells, and three miles of pipeline, and commenced commercial operation in October 1985.
The PG&E Unit 13 and Unit 16 Steam Fields produce steam for sale to PG&E under long-term steam sales agreements. Under the steam sales agreements with PG&E, the Company is paid for steam on the basis of the amount of electricity produced by Unit 13 and Unit 16. The price paid for steam under the PG&E Unit 13 and Unit 16 Steam Fields agreements is determined according to a formula that is essentially a weighted average of PG&E’s fossil (oil and gas) fuel price and PG&E’s nuclear fuel price. The price of steam for 1995 was $12.07/MWh. The price for 1996 is expected to be approximately $9.95/MWh.
During conditions of hydro-spill, PG&E may curtail energy deliveries from Unit 13 and Unit 16 which would reduce deliveries of steam under this agreement. Curtailments are primarily the result of a higher degree of precipitation during the period, which results in higher levels of energy generation by hydroelectric power facilities that supply electricity for sale by PG&E. In the event of any such curtailment, the Company’s results of operations may be materially adversely affected. PG&E curtailed approximately 64 GWh under the steam sales agreement during 1995. The Company currently expects approximately the same amount of curtailment under the agreement during 1996 that was experienced in 1995.
The steam sales agreement with PG&E continues in effect for as long as either Unit 13 or Unit 16 remains in commercial operation, which depends on maintaining the productive capacity of the respective steam fields. However, PG&E may terminate the agreement if the quantity, quality or purity of the steam is such that the operation of Unit 13 or Unit 16 becomes economically impractical. The Company currently estimates that the productive capacity of the PG&E Unit 13 and Unit 16 Steam Fields is approximately 22 years. However, no assurance can be given that the operation of either Unit 13 or Unit 16 will not become economically impractical at any time during these periods.
The Company is required to supply a sufficient quantity of steam of specified quality to Unit 16. If an insufficient quantity of steam is delivered, the Company may be subject to penalty provisions, including suspension of PG&E’s obligation to pay for steam delivered. Specifically, if the Company fails to deliver to Unit 16 in any calendar month a sufficient quantity of steam adequate to operate the power plant at or above a capacity factor of 50 percent, no payment shall be made for steam delivered to such Unit during such month until the cost of that Unit has been completely amortized by PG&E.
To increase the efficiency of Unit 13 by approximately 20 percent, the Company agreed to purchase new rotors for approximately $10 million. In exchange, PG&E agreed to amend the steam sales agreement to remove the penalty provision for a failure to deliver a sufficient quantity of steam to Unit 13 and to require PG&E to operate at variable pressure operations which will optimize production at the PG&E Unit 13 and Unit 16 Steam Fields.
The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient to operate Unit 13 and Unit 16 at approximately 72 percent of their combined nameplate capacities. This percentage reflects a decline in the productivity of the PG&E Unit 13 and Unit 16 Steam Fields since the commencement of operations of Unit 13 and Unit 16. While it is not possible to accurately predict long-term steam field productivity, the Company has estimated that the annual rate of decline in steam field productivity of the PG&E Unit 13 and Unit 16 Steam Fields was approximately 10 percent until curtailment of neighboring plants and Unit 13 and Unit 16 in 1995 reduced the decline to zero. The Company expects steam field productivity to continue to decline in the future, but at decreasing annual rates of decline. The Company considered these declines in steam field productivity in developing its original projections for the PG&E Unit 13 and Unit 16 Steam Fields at the time the Company acquired its initial interest in 1990. The Company plans to partially offset the expected rate of decline by implementing enhanced water injection and power plant improvements.
During 1995, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient steam to permit Unit 13 and Unit 16 to produce approximately 1,296 GWh.
The Company holds the leasehold rights to 394 acres of steam fields that supply steam to the power plant for SMUD SMUD GEO #1 steam fields (the “SMUD GEO #1 Steam Fields”). The SMUD power plant has a nameplate capacity of 72 MW and currently operates at an output of 59 MW. The SMUD GEO #1 Steam Fields include 19 producing wells, one injection well and two miles of pipeline. Commercial operation of the SMUD power plant commenced in October 1983.
The steam sales agreement with SMUD provides that SMUD will pay for steam based upon the quantity of steam delivered to the SMUD power plant. The current price paid for steam delivered under the steam sales agreement is $1.746 per thousand pounds of steam, which is adjusted semi-annually based on changes in the Gross National Product Implicit Price Deflator Index and Producers Price Index for Fuels, Related Products and Power. SMUD may suspend payments for steam in any month if the Company is unable to deliver 50 percent of the steam requirement until the cost of the plant and related facilities have been completely amortized by the value of such steam delivered to the plant. Based on current estimates and analyses performed by the Company, the Company does not expect SMUD to suspend payments for steam under this provision.
The steam sales agreement with SMUD continues until the expiration or termination of the geothermal lease covering the SMUD GEO #1 Steam Fields, which continues for so long as steam is produced in commercial quantities. The Company and SMUD each have the right to terminate the agreement if their respective operations become economically impractical. In the event that SMUD exercises its right to terminate, the Company will have no further obligation to deliver steam to the power plants.
The SMUD GEO #1 Steam Fields currently supply steam sufficient to operate the SMUD power plant at approximately 82 percent of its nameplate capacity. This percentage reflects a decline in the productivity of the SMUD GEO #1 Steam Fields since commencement of operations. Although the SMUD GEO #1 Steam Fields increased in productivity in 1995 due to curtailment of neighboring plants, the Company expects the SMUD GEO #1 Steam Fields’ productivity to decline in the future. During 1995, the SMUD GEO #1 Steam Fields produced approximately 6,600,835 thousand pounds of steam.
“An Update on The Geysers, November 1994,” Geothermal Resources Council Bulletin, Volume 24, No. 1., January, 1995, pp. 9-20.
Cooley, Dean, “A Report on Cycling Operations at The Geysers Power Plant,” Geothermal Resources Council Transactions, Vol. 20, September/October, 1996, pp. 729-732.
“DJ Electricity Prices,” The Wall Street Journal, August 19, 1996, p. C14.
“Public Utilities Fortnightly/POWERdat Market Indicators,” Public Utilities Fortnightly, May 15, 1996, p. 9.
Pacific Gas & Electric Company 1995 Form 10-K. U.S. Securities and Exchange Commission.
Unocal Corporation 1995 Form 10-K. U.S. Securities and Exchange Commission.
Calpine Corporation Form S-4 Registration Statement. U.S. Securities and Exchange Commission.
Renewable Energy
Annual 1996
April 1997
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