-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Wb2mTnG8giod/IWTcS5SUEVdXBW4jePWTMBs9X9AqNYzd53K97F/Z87mbfH01urW N7DD9Q+J3OcDL1tEb6V8Yw== 0000891618-98-001078.txt : 19980312 0000891618-98-001078.hdr.sgml : 19980312 ACCESSION NUMBER: 0000891618-98-001078 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980311 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CALPINE CORP CENTRAL INDEX KEY: 0000916457 STANDARD INDUSTRIAL CLASSIFICATION: COGENERATION SERVICES & SMALL POWER PRODUCERS [4991] IRS NUMBER: 770031605 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-12079 FILM NUMBER: 98563936 BUSINESS ADDRESS: STREET 1: 50 WEST SAN FERNANDO ST CITY: SAN JOSE STATE: CA ZIP: 95113 BUSINESS PHONE: 4089955115 MAIL ADDRESS: STREET 1: 50 W SAN FERNANDO STREET 2: SUITE 500 CITY: SAN JOSE STATE: CA ZIP: 95113 10-K 1 FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 1997 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ FORM 10-K (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] COMMISSION FILE NUMBER 033-73160 CALPINE CORPORATION (A DELAWARE CORPORATION) I.R.S. EMPLOYER IDENTIFICATION NO. 77-0212977 50 WEST SAN FERNANDO STREET SAN JOSE, CALIFORNIA 95113 TELEPHONE: (408) 995-5115 Securities registered pursuant to Section 12(b) of the Act: Calpine Corporation Common Stock, $0.001 par value Registered on the New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None. Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of the Form 10-K or any amendment to this Form 10-K. [ ] Aggregate market value of the voting stock held by non-affiliates of the Registrant as of March 4, 1998: $334.2 million Common stock outstanding as of March 4, 1998: 20,104,890 DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. (1) Designated portions of the Proxy Statement relating to the 1998 Annual Meeting of Shareholders:... Part III (Items 10, 11 and 12) ================================================================================ 2 CALPINE CORPORATION FORM 10-K ANNUAL REPORT FOR THE YEAR ENDED DECEMBER 31, 1997 TABLE OF CONTENTS PART 1
PAGE ---- ITEM 1. Business.................................................... 1 ITEM 2. Properties.................................................. 41 ITEM 3. Legal Proceedings........................................... 42 ITEM 4. Submission of Matters To A Vote of Security Holders......... 43 PART II ITEM 5. Market for Registrant's Common Equity and Related 43 Stockholder Matters....................................... ITEM 6. Selected Financial Data..................................... 43 ITEM 7. Management's Discussion and Analysis of Financial Condition 43 and Results of Operations................................. ITEM 8. Financial Statements and Supplementary Data................. 43 ITEM 9. Changes In and Disagreements with Accountants and Financial 43 Disclosure................................................ PART III ITEM 10. Executive Officers, Directors and Key Employees............. 43 ITEM 11. Executive Compensation...................................... 43 ITEM 12. Security Ownership of Certain Beneficial Owners and 43 Management................................................ ITEM 13. Certain Relationships and Related Transactions.............. 43 PART IV ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 44 8-K....................................................... Signatures ............................................................ 51 Index to Consolidated Financial Statements and Schedules................ F-1 Schedule 11 Calculation of Earnings per Share Exhibit Index
i 3 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 Corporation ("Calpine"), a Delaware corporation, and subsidiaries (collectively, the "Company") is engaged in the acquisition, development, ownership and operation of power generation facilities and the sale of electricity and steam, principally in the United States. The Company currently has interests in 23 power plants and steam fields having an aggregate capacity of 2,613 megawatts. The Company currently sells electricity and steam to 16 utility and other customers, principally under long-term power and steam sales agreements, generated by power generation facilities located in six states and Mexico. In addition, the Company has a 240 megawatt gas-fired power plant currently under construction in Pasadena, Texas and an investment in a 169 megawatt gas-fired power plant currently under construction in Dighton, Massachusetts. Since its inception in 1984, the Company has developed substantial expertise in all aspects of electric power generation. The Company's vertical integration has resulted in significant growth in recent years as the Company has applied its extensive engineering, construction management, operations, fuel management and financing capabilities to successfully implement its acquisition and development program. The Company's strategy is to capitalize on opportunities in the power market through an ongoing program to acquire, develop, own and operate electric power generation facilities, as well as marketing power and energy services to utilities and other end users. The Company's net interest in power generation facilities has increased from 297 megawatts in 1992 to 1,981 megawatts in 1997, including the facilities currently under construction. Total assets have increased from $55.4 million as of December 31, 1992 to $1.4 billion as of December 31, 1997. The Company's revenue has increased to $276.3 million for 1997, representing a five-year compound annual growth rate of 48% since 1992. The Company's EBITDA (as defined herein) for 1997 increased to $172.6 million from $9.9 million in 1992, representing a five-year compound annual growth rate of 77%. THE MARKET The power generation industry represents the third largest industry in the United States, with an estimated end user market of over $200 billion of electricity sales and 3,300 gigawatt hours of production in 1997. In response to increasing customer demand for access to low-cost electricity and enhanced services, new regulatory initiatives are currently being adopted or considered at both state and federal levels to increase competition in the domestic power generation industry. To date, such initiatives are under consideration at the 1 4 federal level and in approximately 45 states. In April 1996, the Federal Energy Regulatory Commission ("FERC") adopted Order No. 888, opening wholesale power sales to competition and providing for open and fair electric transmission services by public utilities. In addition, the California Public Utilities Commission ("CPUC") has issued an electric industry restructuring decision, which originally provided for commencement of deregulation and implementation of customer choice of electricity supplier by January 1, 1998, and is currently scheduled to commence on April 1, 1998. The Company believes that industry trends and such regulatory initiatives will lead to the transformation of the existing market, which is largely characterized by electric utility monopolies having old, inefficient high-cost generating facilities, selling to a captive customer base, to a more competitive market where end users may purchase electricity from a variety of suppliers, including non-utility generators, power marketers, public utilities and others. The Company believes that these market trends will create substantial opportunities for companies such as themselves that are low cost power producers and have an integrated power services capability which enables them to produce and sell energy to customers at competitive rates. The Company also believes that these market trends will result in the disposition of power generation facilities by utilities, independent power producers and industrial companies. Numerous utilities have announced their intentions to sell their power generation facilities. Many independent producers operating a limited number of power plants are seeking to dispose of such plants in response to competitive pressures, and industrial companies are selling their power plants to redeploy capital in their core businesses. The Company believes that this consolidation will continue in the highly fragmented independent power industry. STRATEGY The Company's objective is to become a leading power company by capitalizing on emerging market opportunities in the domestic power markets. The key elements of the Company's strategy are as follows: Expand and diversify its domestic portfolio of power projects. In pursuing its growth strategy, the Company intends to focus on opportunities where it is able to capitalize on its extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach includes design, engineering, procurement, finance, construction, management, fuel and resource acquisition, operations and power marketing, which the Company believes provides it with a competitive advantage. Acquisition of power plants. The Company has significantly expanded and diversified its project portfolio through the acquisition of power generation facilities. Since 1993, the Company has completed transactions involving thirteen gas-fired cogeneration facilities and two steam fields. As a result of these transactions, the Company has more than quadrupled its aggregate power generation capacity and substantially diversified its fuel mix during this period. The Company intends to continue to pursue an active acquisition program. Development of merchant power plants. The Company is also pursuing the development of highly efficient, low-cost power plants that seek to take advantage of inefficiencies in the electricity market. The Company intends to sell all or a portion of the power generated by such merchant plants into the competitive market through a portfolio of short, medium and long-term power sales agreements. As part of Calpine's initial effort to develop merchant plants, the Company has a 240 megawatt gas-fired power generation facility currently under construction in Pasadena, Texas and a 169 megawatt gas-fired power generation facility currently under construction in Dighton, Massachusetts. The Company currently plans to develop additional low-cost, gas-fired facilities in California, Texas, New England and other high-priced power markets. Enhance the performance and efficiency of existing power projects. The Company continually seeks to maximize the power generation potential of its operating assets and minimize its operating and maintenance expenses and fuel costs. To date, the Company's power generation facilities have operated at an average availability of approximately 97%. The Company believes that achieving and maintaining a low-cost of production will be increasingly important to compete effectively in the power generation market. 2 5 DESCRIPTION OF FACILITIES The Company currently has interests in 23 power generation facilities and steam fields with a current aggregate capacity of approximately 2,613 megawatts, consisting of fifteen gas-fired power plants with a total capacity of 2,127 megawatts, three geothermal power generation facilities (which include a steam field and a power plant) with a total capacity of 67 megawatts and five geothermal steam fields that supply utility power plants with a total current capacity of approximately 419 megawatts. In addition, the Company has a 240 megawatt gas-fired power generation facility under construction in Pasadena, Texas, and an investment in a 169 megawatt gas-fired power generation facility currently under construction in Dighton, Massachusetts. Each of the power generation facilities currently in operation produces electricity for sale to a utility or other thirdparty end user. Thermal energy produced by the gas-fired cogeneration facilities is sold to governmental and industrial users, and steam produced by the geothermal steam fields is sold to utility-owned-power plants. The gas-fired and 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 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. The Company is paid for steam supplied by its steam fields on the basis of the amount of electrical energy produced by, or steam delivered to, the contracting utility's power plants. The Company currently provides operating and maintenance services for 16 of the 23 power plants and steam fields in which the Company has an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps, gathering systems and gas pipelines. The Company also supervises maintenance, materials, purchasing and inventory control, manages cash flow, trains staff and prepares operating and maintenance manuals for each power generation facility. As a facility develops an operating history, the Company analyzes 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 the Company is generally reimbursed for certain costs, is paid an annual operating fee and may also be paid an incentive fee based on the performance of the facility. The fees payable to the Company 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 the Company has an interest, natural gas reserves are acquired or natural gas is purchased from third parties under supply agreements. The Company attempts 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. Certain power generation facilities in which the Company has 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 the Company or any assets of the Company or 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 the Company has an interest are located on sites which are leased on a long-term basis. The Company currently holds interests in geothermal leaseholds in The Geysers that produce steam for sale under steam sales agreements and for use in producing electricity from its wholly-owned geothermal power generation facilities. 3 6 The continued operation of power generation facilities and steam fields 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. To date, the Company's power plants have operated at an average availability of 97%. Although from time to time the Company's power generation facilities have experienced certain equipment breakdowns or failures, such breakdowns or failures have not had a material adverse effect on the operation of such facilities or on the Company's results of operations. Although the Company's facilities contain certain redundancies and back-up mechanisms, there can be no assurance that any such breakdown or failure would not prevent the affected facility or steam field from performing under applicable power and/or steam sales agreements. In addition, although insurance is maintained to protect against certain of these operating risks, the proceeds of such insurance may not be adequate to cover lost revenue or increased expenses, and, as a result, the entity owning such power generation facility or steam field may be unable to service principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation could result in the Company losing its interest in such power generation facility or steam field. Insurance coverage for each power generation facility includes commercial general liability, workers' compensation, employer's liability and property damage coverage, which generally contains business interruption insurance covering debt service and continuing expenses for a period ranging from 12 to 18 months. The Company believes that each of the currently operating power generation facilities in which the Company has an interest is exempt from financial and rate regulation as a public utility under federal and state laws. 4 7 Set forth below is certain information regarding the Company's operating power plants, pending power plant acquisitions, development projects and operating steam fields as of March 4, 1998. POWER PLANTS
TERM OF POWER NAMEPLATE CALPINE CALPINE NET COMMENCEMENT POWER GENERATION CAPACITY INTEREST INTEREST OF COMMERCIAL POWER SALES POWER PLANT TECHNOLOGY (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS) OPERATION PURCHASER AGREEMENT ----------- ---------- -------------- ---------- ----------- ------------- ----------------- --------- OPERATING POWER PLANTS Texas City........... Gas-Fired 450 50% 225 1987 TUEC 2002 UCC(2) 2003 Clear Lake........... Gas-Fired 377 50% 188.5 1984 TNP 2004 HL&P 2005 HCCG(3) 2004 Gordonsville......... Gas-Fired 240 50% 120 1994 VEPCO(4) 2024 Lockport............. Gas-Fired 184 11.36% 20.9 1992 GM 2007 NYSEG(5) Auburndale........... Gas-Fired 150 50% 75 1994 FPC(16) 2013 Sumas(6)............. Gas-Fired 125 70% 87.5 1993 Puget Sound and 2013 Electric Company King City............ Gas-Fired 120 100% 120 1989 PG&E(17) 2019 Gilroy............... Gas-Fired 120 100% 120 1988 PG&E 2018 Kennedy International Airport............ Gas-Fired 107 50% 53.5 1995 Port Authority(7) 2015 Bethpage............. Gas-Fired 57 100% 57 1989 NG Corp. 2004 LILCO(8) Greenleaf 1.......... Gas-Fired 49.5 100% 49.5 1989 PG&E 2019 Greenleaf 2.......... Gas-Fired 49.5 100% 49.5 1989 PG&E 2019 Stony Brook.......... Gas-Fired 40 50% 20 1995 SUNY 2015 LILCO(9) Agnews............... Gas-Fired 29 20% 5.8 1990 PG&E 2021 Watsonville.......... Gas-Fired 28.5 100% 28.5 1990 PG&E 2009 West Ford Flat....... Geothermal 27 100% 27 1988 PG&E 2008 Bear Canyon.......... Geothermal 20 100% 20 1988 PG&E 2008 Aidlin............... Geothermal 20 5% 1 1989 PG&E 2009 PENDING ACQUISITIONS Pittsburgh........... Gas-Fired 70 100% 70 1966 Dow Chemical n/a Corporation PROJECTS UNDER CONSTRUCTION Pasadena(10)......... Gas-Fired 240 100% 240 1998 Phillips 2018 Dighton(11).......... Gas-Fired 169 50% 84.5 1999 Merchant n/a
STEAM FIELDS
APPROXIMATE CALPINE CALPINE NET COMMENCEMENT CAPACITY INTEREST INTEREST OF COMMERCIAL UTILITY ESTIMATED STEAM FIELD (MEGAWATTS)(12) PERCENTAGE (MEGAWATTS) OPERATION PURCHASER LIFE(13) ----------- --------------- ---------- ----------- ------------- ------------- --------- Thermal Power Company 140 100% 140 1960 PG&E 2018 PG&E Unit 13 75 100% 75 1980 PG&E 2018 PG&E Unit 16 74 100% 74 1985 PG&E 2018 SMUDGEO #1 50 100% 50 1983 SMUD 2018 Cerro Prieto 80 100%(14) 80 1973 Comision 2000(15) Federal de Electricidad Electric
- --------------- (1) Nameplate capacity may not represent the actual output for a facility at any particular time. (2) The power purchasers for the Texas City Power Plant are the Texas Utilities Electric Company ("TUEC") and the Union Carbide Corporation ("UCC"). 5 8 (3) The power purchasers for the Clear Lake Power Plant are the Texas-New Mexico Power Company ("TNP"), the Houston Lighting and Power Company ("HL&P") and the Hoechst Celanese Chemical Group, Inc. ("HCCG"). (4) The power purchaser for the Gordonsville Power Plant is Virginia Electric and Power Company ("VEPCO"). (5) The power purchasers for the Lockport Power Plant are General Motors ("GM"), and New York State Electric and Gas ("NYSEG"). (6) See Power Plants-Sumas Power Plants for a description of the Company's interest in the Sumas partnership and current sales of power by the Sumas Power Plant. (7) Electricity generated by the Kennedy International Airport Power Plant is sold to the Port Authority of New York and New Jersey ("Port Authority") and excess energy is sold to other utility customers. (8) Electricity generated by the Bethpage Power Plant is sold to the Northrup Grumman Corporation ("NG Corp"), and excess energy is sold to Long Island Lighting Corporation ("LILCo"). (9) Electricity generated by the Stony Brook Power Plant is sold to the State University of New York at Stony Brook ("SUNY"), and excess energy is sold to LILCo. (10) The Pasadena Power Plant is currently under construction and is expected to commence commercial operation in July 1998. Approximately 90 megawatts will be sold to Phillips Petroleum Company ("Phillips"), with the remaining available electricity generated to be sold into the open market. (11) The Dighton Power Plant is currently under construction and is expected to commence commercial operation in early 1999. The Company invested $16.0 million in the facility, which entitles the Company to receive a preferred payment stream at a rate of 12.07% per annum on its investment. Based on the Company's current estimates, this preferred payment stream will represent approximately 50% of project cash flow beginning at the commencement of commercial operation. A merchant plant is a power generation facility that sells all or a portion of its electricity into the competitive market rather than pursuant to long-term power sales agreements. (12) Capacity is expected to gradually diminish as the production of the related steam fields declines. (13) Other than the Cerro Prieto Steam Field, the steam sales agreements remain in effect so long as steam is produced in commercial quantities. There can be no assurance that the estimated life shown accurately predicts actual productive capacity of the steam fields. (14) See Steam Fields-Cerro Prieto Steam Fields for a description of the Company's interest in and current sales of steam by the Cerro Prieto Steam Field. (15) Represents the actual termination of the steam sales agreement. (16) Florida Power Company ("FPC"). (17) Pacific Gas & Electric Company ("PG&E"). POWER PLANTS Texas City and Clear Lake Power Plants On June 23, 1997, the Company completed the acquisition of a 50% equity interest in the Texas City and the Clear Lake Cogeneration facilities for a total purchase price of $35.4 million. The Company acquired its 50% interest in these plants through the acquisition of 50% of the capital stock of Enron Dominion Cogen Corp., subsequently renamed Texas Cogeneration Company ("TCC") from Enron Power Corp., which is a wholly-owned subsidiary of Enron Corp. ("Enron"). The other 50% shareholder in TCC is Dominion Cogen, Inc., a wholly-owned subsidiary of Dominion Energy, Inc. which in turn is a wholly-owned subsidiary of Dominion Resources, Inc., which is the parent company of VEPCO. In addition to the purchase of 50% of the stock of TCC, the Company, through its wholly-owned subsidiary, Calpine Finance Company ("CFC"), purchased from the existing lenders the $155.6 million of outstanding non-recourse project financing incurred by TCC in connection with the Texas City Power Plant (approximately $53.0 million) and the Clear Lake Power Plant (approximately $102.6 million). The acquisition of the capital stock of TCC and the purchase of 6 9 the outstanding debt from the existing lenders were financed with approximately $125.0 million of non-recourse project financing provided by The Bank of Nova Scotia and $70.0 million of equity provided by the Company. The non-recourse project financing matures on June 22, 1998 and bears interest at London Interbank Offered Rate ("LIBOR") plus an agreed margin, currently 7.2% per annum. The Company currently expects to refinance this non-recourse project financing before June 22, 1998. Texas City Power Plant -- The Texas City Power Plant is a 450 megawatt gas-fired cogeneration facility located in Texas City, Texas. The Texas City Power Plant includes three Westinghouse W-501D5 combustion turbines, three Econotherm heat recovery steam generators and one Hitachi steam turbine. The Texas City Power Plant commenced commercial operation in June 1987. In 1997, the Texas City Power Plant operated at an average availability of 92.9%. Electricity generated by the Texas City Power Plant is sold under two separate long-term agreements to (i) TUEC under a power sales agreement terminating on September 30, 2002 and (ii) Union Carbide Company ("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. It is necessary for the Texas City Power Plant to provide a certain amount of thermal energy to a host facility in order to maintain its qualifying facility ("QF") status. Natural gas requirements for the Texas City Power Plant are allocated between UCC, DEI Texas, Inc. ("DEI"), an affiliate of Dominion Cogen Inc., and Enron Capital & Trade Resources Corporation ("ECT") pursuant to a contractual arrangement. UCC and DEI currently provide approximately 25% and 56%, respectively, of the fuel requirements of the Texas City Power Plant. The three fuel contracts are effective through June 30, 1999. Under the fuel contracts, approximately 19% of the total fuel requirements of the Texas City Power Plant is supplied at spot market prices. The remainder is purchased at fixed rates set forth in the contracts. The Texas City Power Plant is operated and maintained by the Company under a one-year operating and maintenance agreement with automatic renewal provisions, pursuant to which the Company is reimbursed for certain costs and is entitled to a fixed annual fee and an incentive payment based on project performance. The Texas City Power Plant is located on approximately 9 acres of land in Texas City, Texas. During 1997, the Texas City Power Plant generated approximately 2,704,481,000 kilowatt-hours of electric energy for sale to TUEC and UCC and approximately $197.6 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. The Clear Lake Power Plant includes three Westinghouse W-501D5 combustion turbines, three Vogt heat recovery steam generators and two Westinghouse steam turbines. The Clear Lake Power Plant commenced commercial operation in December 1984. In 1997, the Clear Lake Power Plant operated at an average availability of 97.4%. Electricity generated by the Clear Lake Power Plant is sold under three separate long-term agreements to (i) TNP under an original 20-year power sales agreement terminating in 2004, (ii) HL&P under an original 10- year power sales agreement terminating in 2005, and (iii) HCCG under an original 10-year 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. It is necessary for the Clear Lake Power Plant to provide a certain amount of thermal energy to a host facility in order to maintain its QF status. The natural gas for the Clear Lake Power Plant is purchased primarily from TCC, which receives its fuel from ECT. In addition, the facility burns hydrogen provided by HCCG, amounting to about 5% of the Clear Lake Power Plant's total fuel requirements. 7 10 The Clear Lake Power Plant is operated by the Company under a one-year operating and maintenance agreement with automatic renewal provisions, pursuant to which the Company is reimbursed for certain costs and is entitled to a fixed annual fee and an incentive payment based on project performance. The Clear Lake Power Plant is located on approximately 21 acres of land in Pasadena, Texas. During 1997, the Clear Lake Power Plant generated approximately 2,966,250,000 kilowatt-hours of electric energy for sale to TNP, HL&P and HCCG, and approximately $97.6 million of revenue. The Clear Lake Power Plant is currently engaged in litigation with TNP (see Item 3 -- Legal Proceedings). Gordonsville and Auburndale Power Plants On October 9, 1997, the Company completed the acquisition of 50% interests in the Gordonsville Power Plant and the Auburndale Power Plant. The Company acquired its interest in the Gordonsville Power Plant through the acquisition of a 50% general partnership interest in Gordonsville Energy, L.P. from Northern Hydro Limited ("Hydro") for approximately $14.9 million. The other 50% general partnership interest in Gordonsville Energy, L.P. is owned by affiliates of Edison Mission Energy, a subsidiary of Edison International Company. Construction of the Gordonsville Power Plant was financed with non-recourse project financing totaling $223.0 million maturing on June 1, 2009. The Company acquired its interest in the Auburndale Power Plant through the acquisition of a 50% general partnership in Auburndale Power Partners, L.P. from Norweb Power Services (No. 1) Limited ("Norweb") for approximately $27.5 million. The other 50% general partnership interest in Auburndale Power Partners, L.P. is owned by affiliates of Edison Mission Energy, a subsidiary of Edison International Company. The construction of the Auburndale Power Plant was financed with a term loan in the amount of $126.0 million and a final maturity date of December 31, 2012. Gordonsville Power Plant -- The Gordonsville Power Plant is a 240 megawatt gas-fired cogeneration facility located near Gordonsville, Virginia. The Gordonsville Power Plant consists of two General Electric Stag 107EA combined-cycle combustion turbines, two steam turbines, two heat recovery steam generators and an air-cooled condenser. The Gordonsville Power Plant commenced commercial operation in 1994. In 1997, the Gordonsville Power Plant operated at an average availability of 96.1%. Electricity generated by the Gordonsville Power Plant is sold to VEPCO under two 30-year power sales agreements terminating on June 1, 2024, each of which include payment provisions for capacity and energy. The power sales agreements provide for firm capacity payments at a price of $128 per kilowatt year through 2008 and at a price of $102 for years 2009 through 2024. For the term of the power sales agreements, Gordonsville is paid for firm capacity up to 217.4 megawatts in the summer and up to 287.8 megawatts in the winter. The power sales agreements contain dispatch provisions, which allow VEPCO to control the output of the facility. The Gordonsville Power Plant sells steam to Rapidan Service Authority under the terms of a steam purchase and sales agreement for treating wastewater, which expires June 1, 2004. It is necessary for the Gordonsville Power Plant to provide a certain amount of thermal energy to a host facility in order to maintain its QF status. Gordonsville has two separate natural gas supply and transportation agreements. During the summer period, gas is supplied by Union Pacific Fuels Inc. under a 15-year agreement expiring June 2009. During the winter period, gas is supplied by Tejas Power under a 15-year agreement expiring June 2009, subject to renewal for a period of five years. The Gordonsville Power Plant is operated by Edison Mission Operations & Maintenance Inc. ("EMOM"), under an agreement which expires on December 31, 2024. EMOM is paid on a cost-plus basis for all direct labor plus reimbursement of certain costs, an annual operating fee and an incentive fee based on performance. 8 11 The Gordonsville Power Plant is located on approximately 16.7 acres near the town of Gordonsville, Virginia. The site is owned by and is leased from the town of Gordonsville under a lease agreement, which expires on June 1, 2024. During 1997, the Gordonsville Power Plant generated approximately 279,000,000 kilowatt-hours of electrical energy and approximately $38.0 million of revenue. Auburndale Power Plant -- The Auburndale Power Plant is a 150 megawatt gas-fired cogeneration facility located near the city of Auburndale, Florida. The Auburndale Power Plant consists of a single Westinghouse W501D5 combustion turbine generator, a Mitsubishi steam turbine and a Nooter-Erickson heat recovery steam generator. The project uses an on-site zero discharge waste water system. The Auburndale Power Plant commenced commercial operation in July 1994. In 1997, the Auburndale Power Plant operated at an average availability of 95.0%. 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 power sales agreements provide for capacity payments on 114 megawatts at a price of $185 per kilowatt year (1998 dollars) escalating at 5.1% per year. On 17 megawatts, capacity payments are based on $231 per kilowatt year (1998 dollars) escalating at 6.33% per year. 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, for an original term of 20 years expiring on July 1, 2014. The second agreement is with Todhunter International, Inc., doing business as Florida Distillers Company, for an original term of 15 years expiring on July 1, 2009. It is necessary for the Auburndale Power Plant to provide a certain amount of thermal energy to a host facility in order to maintain QF status. The Auburndale Power Plant has an 18-year fuel supply contract with Citrus Trading Corporation, a joint venture between Enron and Sonat Inc., for 25,100 million British thermal units ("mmbtu") per day of natural gas. The fuel supply contract expires in June 2014. The Auburndale Power Plant is operated by EMOM. EMOM is paid on a cost-plus basis for all direct labor plus reimbursement of certain costs, an annual operating fee and an incentive fee based on performance. The Auburndale Power Plant is located on a 10-acre site near the city of Auburndale, Florida. The site is owned by Auburndale Power Partners, L.P. During 1997, the Auburndale Power Plant generated approximately 1,068,574,000 kilowatt-hours of electrical energy and approximately $50.0 million in revenue. Gas Energy Inc. Power Plants On December 19, 1997, Calpine completed the acquisition of 100% of the capital stock of Gas Energy, Inc. ("GEI") and Gas Energy Cogeneration, Inc. ("GECI") from The Brooklyn Union Gas Company("BUG") for an aggregate purchase price of $100.9 million (referred to as the "GEI Transaction"). GEI and GECI indirectly own (i) a 50% general partnership interest in the Kennedy International Airport Power Plant, a 107 megawatt gas-fired cogeneration facility, (ii) a 50% general partnership interest in the Stony Brook Power Plant, a 40 megawatt gas-fired cogeneration facility, (iii) a 45% general partnership interest in the Bethpage Power Plant, a 57 megawatt gas-fired cogeneration facility, (iv) an 11.36% limited partnership interest in the Lockport Power Plant, a 184 megawatt gas-fired cogeneration facility, and (v) a 100% interest in three fuel management contracts. On February 5, 1998, the Company acquired the remaining 55% interest in, and assumed the operations and maintenance of, the Bethpage Power Plant for approximately $4.6 million. 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 ("JFK Airport") in Queens, New York. The facility is owned and operated by KIAC Partners ("KIAC"). The Company owns an indirect 50% general partner interest in KIAC. The remaining 50% general partnership 9 12 interest in the project is owned by CEA KIA, Inc., an indirect special purpose subsidiary of Community Energy Alternatives Incorporated ("CEA"), which is, in turn, an indirect wholly-owned subsidiary of Public Service Enterprise Group Incorporated ("PSEG"). The Kennedy International Airport Power Plant commenced commercial operation in February 1995. The Kennedy International Airport Power Plant consists of two 42.5 megawatt General Electric LM6000 gas combustion turbine generators, two Deltak heat recovery steam generators, a 26 megawatt General Electric steam turbine generator, a renovated and expanded central heating and refrigeration plant, a renovated and modified thermal distribution system and state-of-the-art pollution control equipment. In 1997, the Kennedy International Airport Power Plant operated at an average availability of 97.3%. KIAC constructed and is operating the Kennedy International Airport Power Plant pursuant to a lease expiring in November 2015 (the KIAC Lease Agreement). KIAC is obligated under the lease to pay facility rental in an amount sufficient to pay principal and interest of the $250 million of Special Port Authority Bonds which were issued by the Port Authority in June 1996 to refinance the original financing for the project and to reimburse a portion of the initial equity investment. The Special Port Authority Bonds mature in 2019. 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 Con Ed, NYPA 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 which expires November 2015 and is subject to an automatic four-year extension if the Port Authority extends its lease at least four years beyond 2015 with New York City for JFK Airport. Under the energy purchase agreement, the Port Authority is obligated to purchase the electrical energy output generated by the Kennedy International Airport Power Plant up to JFK Airport's requirements (subject to a maximum of 76.3 megawatts). The purchase price for electric power under the agreement is the prevailing rate the Port Authority would have paid to NYPA for electric service if the project were not serving JFK Airport, plus a surcharge of up to 5%. Under the agreement, the Port Authority is also obligated to purchase the central terminal tenants' requirements for heating and air conditioning at JFK Airport. The Port Authority has a minimum thermal take requirement in an amount sufficient to maintain the Kennedy International Airport Power Plant's QF status. It is necessary for the Kennedy International Airport Power Plant to provide a certain amount of thermal energy to a host facility in order to maintain its QF status. The natural gas requirements of the Kennedy International Airport Power Plant are supplied by Amerada Hess Corporation under a long-term contract in effect through November 30, 2015. Fuel is transported to the Kennedy International Airport Power Plant under two interstate transportation contracts with Energy Development Corporation ("EDC") and EnMark Gas Corp. ("EnMark"). The EDC contract is effective through November 2015, with a five-year extension option. The EnMark gas services agreement provides for transportation through November 2010, subject to renewal at the option of KIAC, for one-year intervals, for up to 10 years. Local transportation is provided by BUG under a transportation services agreement, which agreement expires in January 2019, extendible on a year-to-year basis thereafter. Fuel management and administration services are provided by Idlewild Fuel Management Corp. ("IFM"), a wholly-owned subsidiary of the Company, under a long-term fuel management contract. The agreement is in effect through January 2015. The Kennedy International Airport Power Plant is operated by CEA Kennedy Operators, Inc., under a long-term agreement pursuant to which the operator is reimbursed for certain costs and is entitled to a fixed fee and an incentive payment based on performance. The agreement expires the earlier of February 2020 or the date of the expiration of the KIAC Lease Agreement. The Kennedy International Airport Power Plant is located on a seven-acre site within the JFK Airport. KIAC subleases the land on which the facility is located from the Port Authority for $100,000 annually under a 20-year site lease expiring November 30, 2015, subject to extension. 10 13 For 1997, the Kennedy International Airport Power Plant generated approximately 398,868,000 kilowatt-hours of electrical energy, 206,400 mmbtu of chilled water and 197,500 mmbtu of hot water for sale to the Port Authority, and generated approximately $46.3 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 ("SUNY") at Stony Brook, New York. The facility is owned by Nissequogue Cogen Partners ("NCP"). The Company owns an indirect 50% general partner interest in NCP. The remaining 50% general partner interest is owned by CEA Stony Brook, Inc., an indirect special purpose subsidiary of CEA, which is, in turn, an indirect wholly-owned subsidiary of PSEG. The Stony Brook Power Plant commenced commercial operation in April 1995. The Stony Brook Power Plant consists of a single General Electric LM6000 aeroderivative combustion turbine generator coupled with a Nooter-Erickson heat recovery steam generator. In 1997, the Stony Brook Power Plant operated at an average availability of 94.9%. On December 15, 1993, NCP entered into a lease agreement for the Stony Brook Power Plant with the Suffolk Industrial Development Agency (the "Suffolk IDA") concurrent with the issuance of $79 million of variable rate Industrial Development Revenue Bonds by the Suffolk IDA to finance the construction of the facility. The bonds mature in 2010. Steam and electric power is sold to SUNY under a 20-year energy supply agreement expiring April 2015. 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 per hr of process steam. The remaining electricity is sold to LILCo under a long-term agreement. LILCo is obligated to purchase, on an avoided cost basis, electric power generated by the facility not required by SUNY. SUNY's purchase price for electric power is equal to 80% of LILCo's 2-MRP rate, which is its rate for large industrial customers. The purchase price for steam includes a fixed monthly charge plus a variable charge per pound of steam. SUNY is required to purchase a minimum of 402,000 klbs per year of steam, an amount sufficient to maintain QF status of the Stony Brook Power Plant. It is necessary for the Stony Brook Power Plant to provide a certain amount of thermal energy to a host facility in order to maintain its QF status. Natural Gas Clearinghouse, Inc., the successor to Chevron USA, Inc., has guaranteed a firm supply of up to 12,000 mmbtu per day of gas to NCP for a term of 15 years, expiring April 2010, under a supply agreement. The supply agreement can be extended for two additional terms of five years each. Fuel management services are provided by Stony Brook Fuel Management Corp. ("SBFM"), a wholly-owned subsidiary of the Company, under a long-term fuel management contract entered into on December 28, 1993. Gas is transported under gas transportation agreements with New Jersey Natural Gas Company and LILCo under agreements that expire in December 2010 and March 2015, respectively. The Stony Brook Power Plant is operated by CEA Stonybrook Operators, Inc., an indirect wholly-owned subsidiary of CEA, under a long-term operations and maintenance agreement expiring the earlier of either the termination of the site permit or April 2023. The Stony Brook Power Plant is located on two acres of leased land within the SUNY campus in Stony Brook, New York. NCP leases the site, including all permanent facilities constructed on the site, under a site permit agreement for a term equivalent to that of the energy supply agreement. For 1997, the Stony Brook Power Plant generated approximately 305,954,000 kilowatt-hours of electrical energy and 1,117,000 klbs of steam for sale to SUNY and LILCo, and generated approximately $32.8 million in revenue. Bethpage Power Plant -- The Bethpage Power Plant is a 57 megawatt gas-fired cogeneration facility located adjacent to a Northrup Grumman Corporation ("Grummann") facility in Bethpage, New York. The Bethpage Power Plant commenced commercial operation in August 1989. 11 14 The Bethpage Power Plant consists of two General Electric LM2500 aeroderivative combustion turbines coupled with two Hollandaise Construction Group heat recovery steam generators and a General Electric steam turbine. Since start-up, the Bethpage Power Plant has operated at an average availability of 98%. The Bethpage Power Plant was originally financed with a $54.5 million loan maturing on March 31, 2004. Electricity and steam generated by the Bethpage Power Plant are sold to Grumman under an energy purchase agreement expiring August 2004. Under the energy purchase agreement, the Bethpage Power Plant provides Grumman up to 30 megawatts of electric power and Grumman is obligated to purchase a minimum of 175,000 megawatt hours per year from the facility; provided, however, that Grumman may elect to purchase less than 175,000 megawatts per year, subject to a minimum of 75,000 megawatts per year, upon payment of a demand charge of $0.03 per kilowatt hour on the difference between 175,000 megawatts and the amount purchased. The purchase price for electric power under the Grumman energy purchase agreement is 82.5% of LILCo's 2-MRP rate for large industrial consumers. Excess electricity is sold to LILCo under a 15-year generation agreement expiring on the same date. LILCo is required to purchase all the electric power not consumed by Grumman. LILCo's purchase price is equal to the greater of LILCo's SC-11 capacity and energy buyback tariff rate or $0.06 per-kilowatt hour, subject in either case to a 6.0% discount. Grumman is also obligated to purchase a minimum of 158,000 klbs of steam per year from the Bethpage Power Plant. Grumman has an obligation to purchase a minimum quantity of steam to maintain the QF status of the Bethpage Power Plant. It is necessary for the Bethpage Power Plant to provide a certain amount of thermal energy to a host facility in order to maintain its QF status. Gas is supplied by Enron Gas Marketing Inc. ("EGM") under a long-term gas purchase agreement with a term extending through 2004. Fuel management and administration services are provided by Bethpage Fuel Management Inc. ("BFM"), a wholly-owned subsidiary of the Company, under a 15-year fuel management agreement expiring in 2004. Gas is transported under a gas services contract with New Jersey Natural Energy ("NJNE") and a gas transportation agreement with LILCo for local gas transportation service from the LILCo city gate to the plant. The Bethpage Power Plant is currently operated and maintained by General Electric. The Company will assume operation and maintenance of the Bethpage Power Plant no later than April 6, 1998. The Bethpage Power Plant is located on a three-acre site adjacent to the Grumman facility. The Company currently leases the site from Grumman, but has entered into an agreement to purchase the site. For 1997, the Bethpage Power Plant generated approximately 459,022,000 kilowatt-hours of electrical energy for sale to Grumman and LILCo and approximately $34.8 million in revenue. Lockport Power Plant -- The Lockport Power Plant is a 184 megawatt gas-fired cogeneration facility located in Lockport, New York. The facility is owned and operated by Lockport Energy Associates, L.P. ("LEA"). The Company owns an indirect 11.36% limited partnership interest in LEA. The other limited partners of LEA are: Lockport Power Cogeneration, LLC, an affiliate of Harbert Power Corp. (19.30%); Erie Lockport Power Inc., an affiliate of UtiliCorp Power Services (22.55%); EMPECO III, Inc., an affiliate of Continental Energy Services, Inc. (22.31%); TPC Lockport, Inc., an affiliate of Tomen Power Corporation (18.38%); and Lockport Power Cogeneration II, LLC, an affiliate of Fortistar Capital, Inc. (5.0%). The 1% managing general partner is FCI Lockport GP, Inc., an affiliate of Fortistar Capital, Inc. Affiliates of GEI, UtiliCorp Power Services and Tomen Power Corporation also hold, in aggregate, a 0.1% general partnership interest in LEA. The Lockport Power Plant commenced commercial operation on December 28, 1992. The Lockport Power Plant consists of three 41 megawatt General Electric Frame 6 combustion turbine generators, three supplementary fired Nooter-Erickson heat recovery steam generators, a General Electric steam turbine generator and an auxiliary boiler. In 1997, the Lockport Power Plant operated at an average availability of 97.0%. The Lockport Power Plant was financed through a $177.6 million term loan with the Chase Manhattan Bank, N.A., as agent. The loan matures in 2006. 12 15 Electricity and steam is sold to GM under an energy sales agreement for use at the GM Harrison plant (the "GM Plant"), which is located on a site adjacent to the Lockport Power Plant. The energy sales agreement expires December 2007. The energy sales agreement requires LEA to provide all of the GM Plant's steam needs and a substantial portion of the GM Plant's electric power requirements. Electricity is also sold to New York State Electricity and Gas Company ("NYSEG") under a power purchase agreement expiring October 2007 (the "NYSEG Agreement"). NYSEG is required to purchase all of the electric power produced by the Lockport Power Plant not required by GM. The price for electric power under the NYSEG Agreement is based on fixed contractual rates for various periods. The 1997 price was 7.69c per kilowatt hour. GM is also obligated to purchase all of its steam requirements for the GM Plant in the amount of up to 315,800 lbs per hour from the Lockport Power Plant. GM is obligated to purchase steam in sufficient quantities from LEA to maintain its QF status. It is necessary for the Lockport Power Plant to produce a certain amount of thermal energy to a host facility in order to maintain its QF status. Natural gas for the Lockport Power Plant is supplied under three gas sales contracts expiring October 2007 with each of (i) Aquila Energy Marketing Corporation ("Aquila"), (ii) North American Resource Company ("NARCO"), and (iii) ProGas Limited ("ProGas"). Tennessee Gas Pipeline Company ("Tennessee Gas") provides firm transportation for the domestic gas from Aquila and NARCO under a 20-year gas transportation agreement. The ProGas quantities are transported from the Canadian border to the site by Tennessee Gas. The Lockport Power Plant is operated by North American Energy Services Company, an indirect 50% owned subsidiary of Montana Power Company, under an operations and maintenance agreement terminating December 2007, with LEA having the option to renew the term for an additional one-year period. The Lockport Power Plant is located on a 15-acre site contiguous with the GM Plant. LEA purchased the site from GM, leased it to the Town of Lockport which subsequently leased it back to LEA for a term expiring on May 2025. For 1997, the Lockport Power Plant generated approximately 1,275,233,000 kilowatt hours of electricity and had $119.6 million in revenue. The Lockport Power Plant is involved in current litigation with NYSEG in the Federal District Court of New York (see Item 3 -- Legal Proceedings). Sumas Power Plant The Sumas cogeneration facility (the "Sumas Power Plant") is a 125 megawatt gas-fired cogeneration facility located in Sumas, Washington, near the Canadian border. In 1991, the Company and Sumas Energy, Inc. ("SEI") formed Sumas Cogeneration Company, L.P. ("Sumas") for the purpose of developing, constructing, owning and operating the Sumas Power Plant. The Company is the sole limited partner in Sumas and SEI is the general partner. On September 30, 1997, the partnership agreement governing Sumas was amended changing the distribution percentages to the partners. As provided by the terms of the amendment, the Company increased its percentage share of the project's cash flow from 50% to approximately 70% through June 30, 2001. 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%. The Sumas Power Plant commenced commercial operation in April 1993. The Company managed the engineering, procurement and construction of the power plant and related facilities of the Sumas Power Plant, including the gas pipeline. The Sumas Power Plant was constructed by a Washington joint venture formed by Industrial Power Corporation and Haskell Corporation. The Sumas Power Plant is composed of an MS 7001EA combined cycle gas turbine manufactured by General Electric Company, a Vogt heat recovery steam generator, a General Electric steam turbine and a 3.5-mile gas pipeline. Since start-up in April 1993, the Sumas Power Plant has operated at an average availability of approximately 97.4%. 13 16 The Sumas Power Plant's $135.0 million construction and gas reserves acquisition cost was financed through $120.0 million of construction and term loan financing provided to Sumas and ENCO Gas, Ltd. ("ENCO"), a wholly owned Canadian subsidiary of Sumas, by The Prudential Insurance Company of America ("Prudential") and Credit Suisse First Boston Corporation ("Credit Suisse"). The credit facilities originally included term loans of $70.0 million at a combined fixed interest rate of 10.28% per annum and variable rate loans of $50.0 million currently based on the LIBOR, which are amortized over a 15-year period ending in 2008. In September 1997, Sumas borrowed an additional $20.0 million from Prudential and Credit Suisse. Electrical energy generated by the Sumas Power Plant is sold to Puget Sound Power & Light Company ("Puget") under the terms of a 20-year 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. The power sales agreement provides for the sale of electrical energy at a total price equal to the sum of (i) a fixed price component and (ii) a variable price component multiplied by an escalation factor for the year in which the energy is delivered. The schedule of annual fixed average energy prices (expressed in cents per kilowatt hour) in effect through 2013 under the Sumas power sales agreement is as follows:
FIXED FIXED FIXED ENERGY ENERGY ENERGY YEAR PRICE YEAR PRICE YEAR PRICE ---- ------ ---- ------ ---- ------ 1998................. 3.64c 2004........... 6.33c 2009........... 5.40c 1999................. 3.98c 2005........... 6.45c 2010........... 5.49c 2000................. 4.23c 2006........... 6.57c 2011........... 5.58c 2001................. 6.23c 2007........... 5.23c 2012........... 5.58c 2002................. 6.11c 2008........... 5.31c 2013........... 5.58c 2003................. 6.22c
The variable price component is set according to a scheduled rate set forth in the agreement, which in 1997 was 1.02c per kilowatt hour, and escalates annually by a factor equal to the U.S. Gross National Product Implicit Price Deflator. For 1997, the average price paid by Puget under the power sales agreement was 4.40c per kilowatt hour. Pursuant to the power sales agreement, Puget may displace the production of the Sumas Power Plant when the cost of Puget's replacement power is less than the Sumas Power Plant's incremental power generation costs. Thirty-five percent of the savings to Puget under this displacement provision are shared with the Sumas Power Plant. 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 per hour of low pressure steam to an adjacent lumber-drying facility owned by Sumas, which has been leased to and is operated by Socco, Inc. ("Socco"), an SEI affiliate. It is necessary to continue to operate the dry kiln facility in order to maintain the Sumas Power Plant's QF status. In connection with the development of the Sumas Power Plant, Canadian natural gas reserves located primarily in northeastern British Columbia, Canada were acquired by Sumas through its wholly owned subsidiary, ENCO. The gas reserves owned by ENCO totaled approximately 105 billion cubic feet as of January 1, 1998. Firm transportation is contracted for on the Westcoast Energy Inc. pipeline. Gas is delivered to Huntington, British Columbia, where it is transferred into Sumas' own pipeline for transportation to the plant. ENCO is currently supplying approximately 12,900 mmbtu per day to the Sumas Power Plant. The remaining 12,100 mmbtu per day requirement is being supplied under a one-year contract with West Coast Gas Services, Inc. The Company operates and maintains the Sumas Power Plant under an operating and maintenance agreement pursuant to which the Company is reimbursed for certain costs and is entitled to a fixed annual fee and an incentive payment based on project performance. This agreement has an initial term of ten years expiring in April 2003 and provides for extensions. 14 17 The Sumas Power Plant is located on 13.5 acres located in Sumas, Washington, which are leased from the Port of Bellingham under the terms of a 23.5-year lease expiring in 2014, subject to renewal. The lease provides for rental payments according to a fixed schedule. During 1997, the Sumas Power Plant generated approximately 439,370,000 kilowatt hours of electrical energy and approximately $40.8 million of total revenue. In 1997, the Company recognized income of approximately $8.6 million in accordance with the terms of the Sumas partnership agreement, and recorded revenue of $2.1 million for services performed under the operating and maintenance agreement. King City Power Plant The King City cogeneration facility (the "King City Power Plant") is a 120 megawatt gas-fired combined-cycle facility located in King City, California. In April 1996, the Company entered into a long-term operating lease for this facility with BAF Energy ("BAF"). Under the terms of the operating lease, the Company makes semi-annual lease payments to BAF, a portion of which is supported by a collateral fund owned by the Company. The collateral consists of a portfolio of investment grade and U.S. Treasury Securities that mature serially in amounts equal to a portion of the lease payments. The power plant consists of a General Electric Frame 7 Model EA combustion turbine generator, a Nooter-Erickson heat recovery steam generator, an ASEA Brown Boveri ("ABB") steam turbine generator and two Nebraska Boiler auxiliary boilers. The King City Power Plant commenced commercial operation in 1989. Since April 1996, the King City Power Plant has operated at an average availability of 93.4%. Electricity generated by the King City Power Plant is sold to PG&E under a 30-year power sales agreement terminating in 2019. The power sales agreement contains payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $184 per kilowatt year for 111 megawatts for the term of the agreement so long as the King City Power Plant delivers 80% of the firm capacity during designated periods of the year. Additional capacity payments are received for as-delivered capacity in excess of 111 megawatts delivered during peak and partial peak hours. The as-delivered capacity price is $188 per kilowatt year for 1998. Thereafter, the payment for as-delivered capacity will be the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. From January 1, 1998 through April 30, 1998, payments for electrical energy produced are based on 100% of the interim short-run avoided cost ("SRAC"), which is calculated pursuant to the methodology approved by the CPUC on December 9, 1996. Following the commencement of operations of the independent power exchange (currently scheduled for April 1, 1998), payments for electrical energy produced will be based on the energy clearing price of the independent power exchange (referred to herein as the "Power Exchange Price"). From May 1, 1998 through December 31, 1998, payments for electrical energy are based on 80% of SRAC (or the Power Exchange Price, when available) and 20% at fixed prices. The fixed average energy price in effect for 1998 under the King City power sales agreement is 13.14c per kilowatt hour. Thereafter, PG&E is required to pay for electrical energy actually delivered at SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. Through April 28, 1999, the power sales agreement allows for dispatchable operation, which gives PG&E the right to curtail the number of hours per year that the King City Power Plant operates. PG&E has an option to extend its curtailment rights for two additional one-year terms. If PG&E exercises the curtailment extension option, it will be required to pay an additional 0.7c per kilowatt hour for all energy delivered from the King City Power Plant. 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. ("BVP"), an affiliate of BAF, under a long-term contract coterminous with the power sales agreement. It is necessary to continue to operate the host facility in order to maintain the King City Power Plant's QF status. The BVP facility was built in 1957 and processes between 30% and 40% of the dehydrated onion and garlic production in the United States. Natural gas for the King City Power Plant is supplied by Calpine Fuels Corporation ("Calpine Fuels"), a wholly-owned subsidiary of the Company, which purchases gas under short-term gas supply agreements. 15 18 Natural gas is transported under a firm transportation agreement, expiring on March 1, 1999, via a 38-mile pipeline owned and operated by PG&E. Fee title to the premises is owned by Basic American, Inc., which has leased the premises to an affiliate of BAF for a term equivalent to the term of the power sales agreement for the King City Power Plant. The Company is subleasing the premises, together with certain easements, from such affiliate of BAF pursuant to a ground sublease for approximately 15 acres. During 1997, the King City Power Plant generated approximately 424,879,000 kilowatt hours of electrical energy and approximately $45.8 million of total revenue. Gilroy Power Plant On August 29, 1996, the Company acquired the Gilroy cogeneration facility (the "Gilroy Power Plant"), a 120 megawatt gas-fired facility located in Gilroy, California. The Company purchased the Gilroy Power Plant for $125.0 million plus certain contingent consideration, which the Company currently estimates will be approximately $24.1 million, of which $12.5 million has been paid as of December 31, 1997. The acquisition of the Gilroy Power Plant was originally financed utilizing non-recourse project financing in the aggregate amount of $116.0 million. Such loan consists of a 15-year tranche in the amount of $81.0 million and an 18-year tranche in the amount of $35.0 million and bears interest at fixed and floating rates. The Gilroy Power Plant consists of a General Electric Frame 7 Model EA combustion turbine generator, an AEG-KANIS steam turbine, a Henry Vogt heat recovery steam generator, two auxiliary boilers and an inlet chiller using a Henry Vogt ice machine. The Gilroy Power Plant commenced commercial operation in March 1988. Since its acquisition by the Company in August 1996, the Gilroy Power Plant has operated at an average availability of 98.6%. Electricity generated by the Gilroy Power Plant is sold to PG&E under an original 30-year power sales agreement terminating in 2018. The power sales agreement contains payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $172 per kilowatt year for 120 megawatts for the term of the agreement so long as the Gilroy Power Plant delivers 80% of the firm capacity during designated periods of the year. Additional capacity payments are received for as-delivered capacity in excess of 120 megawatts delivered at the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. In addition, through 1998 the power sales agreement provides for payments for electrical energy actually delivered at a price based on the SRAC (or the Power Exchange Price, when available) less $.00132 per kilowatt hour. Thereafter, PG&E is required to pay for electrical energy actually delivered at SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. Through December 31, 1998, the power sales agreement allows for dispatchable operation, which gives PG&E the right to curtail the number of hours per year that the Gilroy Power Plant operates. In addition to the sale of electricity to PG&E, the Gilroy Power Plant produces and sells thermal energy to a thermal host, Gilroy Foods, Inc. ("Gilroy Foods"), under a long-term contract that is coterminous with the power sales agreement. Gilroy Foods is a recognized leader in the production of dehydrated onions and garlic. Simultaneously with the acquisition by the Company of the Gilroy Power Plant, Gilroy Foods was acquired by ConAgra, Inc., an international food company. It is necessary to continue to operate the host facility in order to maintain the Gilroy Power Plant's QF status. Natural gas for the Gilroy Power Plant is supplied by Calpine Fuels, which purchases gas under short-term gas supply agreements. Natural gas is transported under a firm transportation agreement with PG&E, expiring on March 1, 1999. The Gilroy Power Plant is located on approximately five acres of land which are leased to the Company by Gilroy Foods. The lease term runs concurrent with the term of the power sales agreement. 16 19 During 1997, the Gilroy Power Plant generated approximately 485,625,000, kilowatt hours of electrical energy for sale to PG&E and approximately $40.1 million in revenue. Greenleaf 1 and 2 Power Plants On April 21, 1995, Calpine completed the acquisition of the Greenleaf 1 and 2 cogeneration facilities (the "Greenleaf 1 and 2 Power Plants") for an adjusted purchase price of $81.5 million. On June 30, 1995, Calpine refinanced the existing debt on the Greenleaf 1 and 2 Power Plants by borrowing $76.0 million from Sumitomo Bank. The non-recourse project financing with Sumitomo Bank is divided into two tranches, a $60.0 million fixed rate loan facility which bears interest on the unpaid principal at a fixed rate of 7.415% per annum, with amortization of principal based on a fixed schedule through June 30, 2005, and a $16.0 million floating rate loan facility which bears interest based on LIBOR plus an applicable margin, with the amortization of principal based on a fixed schedule through December 31, 2010. The Company is currently negotiating to enter into a sale leaseback of the Greenleaf 1 and 2 Power Plants. Pursuant to the sale leaseback, the Company anticipates that the Greenleaf 1 and 2 Power Plants would be sold to an equipment leasing finance company and the Company would enter into a 15-year operating lease for the plants. The Company anticipates completing the sale leaseback in the second quarter of 1998. There can be no assurance that the Company will successfully complete the sale leaseback. The Greenleaf 1 and 2 Power Plants have a combined natural gas requirement of approximately 22,000 mmbtu per day. Natural gas for the Greenleaf 1 and 2 Power Plants is supplied pursuant to a gas sales agreement with Calpine Gas Company, a wholly-owned subsidiary of the Company, expiring on the termination of the power sales agreements for the Greenleaf 1 and 2 Power Plants. Supplemental gas is supplied by Calpine Fuels, which purchases gas under short-term gas supply agreements. Natural gas is transported under a firm transportation agreement with PG&E, expiring on March 1, 1999. Greenleaf 1 Power Plant -- The Greenleaf 1 cogeneration facility (the "Greenleaf 1 Power Plant") is a 49.5 megawatt gas-fired cogeneration facility located near Yuba City, California. The Greenleaf 1 Power Plant includes an LM5000 gas turbine manufactured by General Electric, a Vogt heat recovery steam generator and a condensing General Electric steam turbine. The Greenleaf 1 Power Plant commenced commercial operation in March 1989. Since its acquisition by the Company in April 1995, the Greenleaf 1 Power Plant has operated at an average availability of approximately 91.6%. Electricity generated by the Greenleaf 1 Power Plant is sold to PG&E under a 30-year power sales agreement terminating in 2019 which contains payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term of the agreement, so long as the Greenleaf 1 Power Plant delivers 80% of its firm capacity during certain designated periods of the year, and an as-delivered capacity payment for an additional 0.3 megawatts of capacity at $188 per kilowatt year for 1998. Thereafter, the payment for as-delivered capacity will be the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. In addition, the power sales agreement provides for payments for up to 49.5 megawatts of electrical energy actually delivered at SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. In accordance with the power sales agreement, PG&E is entitled to curtail the Greenleaf 1 Power Plant during hydro-spill periods, or during periods of negative avoided costs. During 1997, the Greenleaf 1 Power Plant did not experience curtailment. In addition to the sale of electricity to PG&E, 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 the Company. It is necessary to continue to operate the host facility in order to maintain the Greenleaf 1 Power Plant's QF status. The Greenleaf 1 Power Plant is located on 77 acres owned by the Company near Yuba City, California. For 1997, the Greenleaf 1 Power Plant generated approximately 255,161,000 kilowatt hours of electrical energy for sale to PG&E and approximately $15.9 million in revenue. 17 20 Greenleaf 2 Power Plant -- The Greenleaf 2 cogeneration facility (the "Greenleaf 2 Power Plant") is a 49.5 megawatt gas-fired cogeneration facility located near Yuba City, California. The Greenleaf 2 Power Plant includes a STIG LM5000 gas turbine manufactured by General Electric and a Deltak heat recovery steam generator. The Greenleaf 2 Power Plant commenced commercial operation in December 1989. Since its acquisition by the Company in April 1995, the Greenleaf 2 Power Plant has operated at an average availability of approximately 95.9%. Electricity generated by the Greenleaf 2 Power Plant is sold to PG&E under a 30-year power sales agreement terminating in 2019 which includes payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term of the agreement, so long as the Greenleaf 2 Power Plant delivers 80% of its firm capacity during certain designated periods of the year, and an as-delivered capacity payment for an additional 0.3 megawatts of capacity at $188 per kilowatt year through 1998. Thereafter, the payment for as-delivered capacity will be the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. In addition, the power sales agreement provides for payments for up to 49.5 megawatts of electrical energy actually delivered at SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. In accordance with the power sales agreement, PG&E is entitled to curtail the Greenleaf 2 Power Plant during hydro-spill periods or during any period of negative avoided costs. During 1997, the Greenleaf 2 Power Plant did not experience curtailment. In addition to the sale of electricity to PG&E, the Greenleaf 2 Power Plant sells thermal energy to Sunsweet Growers, Inc. ("Sunsweet") pursuant to a 30-year contract. Sunsweet is the largest producer of dried fruit in the United States. It is necessary to continue to operate the host facility in order to maintain the status of the Greenleaf 2 Power Plant as a QF. The Greenleaf 2 Power Plant is located on 2.5 acres of land under a lease from Sunsweet, which runs concurrent with the power sales agreement. For 1997, the Greenleaf 2 Power Plant generated approximately 382,041,000 kilowatt hours of electrical energy for sale to PG&E and approximately $20.4 million in revenue. Agnews Power Plant The Agnews cogeneration facility (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. Calpine holds 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. The other stockholder of GATX Calpine-Agnews, Inc. is GATX Capital Corporation ("GATX"), which has an 80% ownership interest. In connection with the sale leaseback arrangement, Calpine has agreed to reimburse GATX for its proportionate share of certain payments that may be made by GATX with respect to the Agnews Power Plant. The Company and GATX managed the development and financing of the Agnews Power Plant, which commenced commercial operations in December 1990. The Company managed the engineering, construction and start-up of the Agnews Power Plant. The construction work was performed by Power Systems Engineering, Inc. under a turnkey contract. The power plant consists of an LM2500 aeroderivative gas turbine manufactured by General Electric, a Deltak unfired heat recovery steam generator and a Shin Nippon steam turbine-generator. Since start-up, the Agnews Power Plant has operated at an average availability of approximately 97.2%. The total cost of the Agnews Power Plant was approximately $39.0 million. The construction financing was provided by Credit Suisse in the amount of $28.0 million. After the commencement of commercial operation, the power plant was sold to Nynex Credit Corporation under a sale leaseback arrangement with O.L.S. Energy-Agnews. Under the sale leaseback, O.L.S. Energy-Agnews has entered into a 22-year lease, 18 21 commencing March 1991, providing for the payment of a fixed base rental, renewal options and a purchase option at fair market value at the termination of the lease. Electricity generated by the Agnews Power Plant is sold to PG&E under a 30-year power sales agreement terminating in 2021 which contains payment provisions for capacity and energy. The power sales agreement provides for a payment of $196 per kilowatt year for 24 megawatts of firm capacity for the term of the agreement, so long as the Agnews Power Plant delivers at least 80% of its firm capacity of 24 megawatts during certain designated periods of the year, and an as-delivered capacity payment for an additional 4 megawatts of capacity at $188 per kilowatt year for 1998. Thereafter, the payment for as-delivered capacity will be the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. In addition, the power sales agreement provides for payments for up to 32 megawatts of electrical energy actually delivered at a price equal to (i) through 1998, the product of PG&E's fixed incremental energy rate and PG&E's utility electric generation gas cost, and (ii) thereafter, SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1997, PG&E curtailed the energy purchased under the power sales agreement by 989 hours. In addition to the sale of electricity to PG&E, the Agnews Power Plant produces and sells electricity and approximately 7,000 pounds per hour of steam to the Agnews Developmental Center pursuant to a 30-year energy service agreement. The energy service agreement provides that the State of California will purchase from the Agnews Power Plant all of its requirements for steam (up to a specified maximum) and for electricity for the East Campus of the Agnews Developmental Center for the term of the agreement. Steam sales are priced at the cost of production for the Agnews Developmental Center. Electricity sales are priced at the rates that would otherwise be paid to PG&E by the Agnews Developmental Center. The State of California is required to utilize the minimum amount of steam required to maintain the Agnews Power Plant's QF status. The supply of natural gas for the Agnews Power Plant is currently provided under a month-to-month full requirements fuel supply agreement between O.L.S. Energy-Agnews and Amoco Energy Trading Corporation. Natural gas is transported under a firm gas transportation agreement with PG&E, expiring March 1, 1999. The Agnews Power Plant is operated by the Company under an operating and maintenance agreement pursuant to which the Company is reimbursed for certain costs and is entitled to a fixed annual fee and an incentive payment based on performance. This agreement expires on January 7, 2003. The Agnews Power Plant is located on 1.4 acres of land leased from the Agnews Development Center under the terms of a 30-year lease that expires in 2021. This lease provides for rental payments to the State of California on a fixed payment basis until January 1, 1999, and thereafter based on the gross revenues derived from sales of electricity by the Agnews Power Plant, as well as a purchase option at fair market value. During 1997, the Agnews Power Plant generated approximately 219,120,000 kilowatt hours of electrical energy and total revenue of $14.9 million. In 1997, the Company recognized a gain of approximately $17,000 as a result of the Company's 20% ownership interest and recorded revenue of $1.7 million for services performed under the operating and maintenance agreement. Watsonville Power Plant The Watsonville cogeneration facility (the "Watsonville Power Plant") is a 28.5 megawatt gas-fire cogeneration facility located in Watsonville, California. On June 29, 1995, the Company acquired the operating lease for this facility for $900,000 from Ford Motor Credit Company. Under the terms of the lease, rent is payable each month from July through December. The lease terminates on December 29, 2009. The Watsonville Power Plant commenced commercial operation in May 1990. The power plant consists of a General Electric LM2500 gas turbine, a Deltak heat recovery steam generator and a Shin Nippon steam turbine. Since its acquisition by the Company in June 1995, the Watsonville Power Plant has operated at an average availability of approximately 97.0%. 19 22 Electricity generated by the Watsonville Power Plant is sold to PG&E under a 20-year power sales agreement terminating in 2009 which contains payment provisions for capacity and energy. The power sales agreement provides for a payment of $178 per kilowatt year for 20.9 megawatts of firm capacity for the term of the agreement, so long as the Watsonville Power Plant delivers at least 80% of its firm capacity of 20.9 megawatts during certain designated periods of the year, and an as-delivered capacity payment for all megawatts of capacity delivered above the 20.9 megawatts of firm capacity. The power sales agreement provides for payments of all electrical energy actually delivered. Through April 2000, 1% of energy will be sold under a fixed energy price and 99% of the energy will be sold at SRAC (or the Power Exchange Price, when available). For 1998 through 2000, the fixed energy price is 13.90c per kilowatt hours and the as-delivered capacity price per kilowatt year is $188. Thereafter, PG&E will pay for energy delivered at SRAC (or the Power Exchange Price, when available) and will pay for as-delivered capacity at the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. During 1997, SRAC averaged approximately 2.94c per kilowatt hour. Under certain circumstances, PG&E may curtail energy deliveries for up to 400 hours between January 1 and April 15 and an additional 900 off-peak hours from November 1 though April 30. From January 1, 1997 through December 31, 1997, PG&E curtailed energy purchases of 1,300 hours under the power sales agreement. During 1997, 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. It is necessary to continue to operate the host facilities in order to maintain the Watsonville Power Plant's QF status. Natural gas for the Watsonville Power Plant is supplied by Calpine Fuels, which purchases gas under short-term gas supply agreements. Natural gas is transported under a firm transportation agreement with PG&E, expiring on March 1, 1999. The Watsonville Power Plant is located on 1.8 acres of land leased from Norcal Foods under the terms of a 30-year lease expiring in 2010. For 1997, the Watsonville Power Plant generated approximately 208,325,000 kilowatt hours of electrical energy for sale to PG&E and approximately $12.2 million in revenue. West Ford Flat Power Plant The West Ford Flat geothermal facility (the "West Ford Flat Power Plant") consists of a 27 megawatt geothermal power plant and associated steam fields located in the eastern portion of The Geysers area of northern California. The West Ford Flat Power Plant includes a power plant consisting of two turbines manufactured by Mitsubishi Heavy Industries, Inc. with rotors remanufactured by ABB Industries, Inc., two generators manufactured by Electric Machinery, Inc., nine production wells and various steam leases. The West Ford Flat Power Plant commenced commercial operation in December 1988. Since start-up, the West Ford Flat Power Plant has operated at an average availability of approximately 98.5%. Electricity generated by the West Ford Flat Power Plant 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 $167 per kilowatt year for 27 megawatts of firm capacity for the term of the agreement, so long as the West Ford Flat Power Plant delivers 80% 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 fixed average energy price for 1998 is 13.83c per kilowatt hour under the West Ford Flat power sales agreement. Thereafter, PG&E is required to pay for electrical energy actually delivered at SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. The power sales agreement provides that, under certain circumstances, PG&E may curtail energy deliveries. During 1997, PG&E curtailed the energy purchased under this agreement by 304 hours. Due to an 20 23 amendment to the power sales agreement in April 1997, the Company currently does not expect curtailment by PG&E during the remainder of the agreement. The Company believes that the geothermal reserves that supply energy for use by the West Ford Flat Power Plant will be sufficient to earn substantially all of the capacity payments for the remaining term of the power sales agreement due principally to low projected decline rates, limited development in adjacent areas and the substantial productive acreage dedicated to the West Ford Flat Power Plant. The West Ford Flat Power Plant is located on 267 acres of leased land located in The Geysers. During 1997, the West Ford Flat Power Plant generated approximately 213,206,000 kilowatt hours of electrical energy for sale to PG&E and approximately $35.4 million of revenue. Bear Canyon Power Plant The Bear Canyon facility (the "Bear Canyon Power Plant") consists of a 20 megawatt geothermal power plant and associated steam fields located in the eastern portion of The Geysers area of northern California, two miles south of the West Ford Flat Power Plant. The Bear Canyon Power Plant includes a power plant consisting of two turbine generators manufactured by Mitsubishi Heavy Industries, Inc. with rotors remanufactured by ABB Industries, Inc., as well as nine production wells, an injection well and steam reserves. The Bear Canyon Power Plant commenced commercial operation in October 1988. Since start-up, the Bear Canyon Power Plant has operated at an average availability of approximately 98.2%. Electricity generated by the Bear Canyon Power Plant is sold to PG&E under two 10 megawatt, 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 per kilowatt year on four megawatts for the term of the agreement, so long as the Bear Canyon Power Plant delivers 80% of its firm capacity during certain designated periods of the year, and an as-delivered capacity payment for the additional six megawatts of capacity. The other agreement provides for an as-delivered capacity payment for the entire 10 megawatts. 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 energy price is 13.83c per kilowatt hour until September 1998 and, thereafter, PG&E will pay for energy delivered at SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. The as-delivered capacity price is $188 per kilowatt year through 1998, and, thereafter, is the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. The power sales agreement provides that, under certain circumstances, PG&E may curtail energy deliveries. During 1997, PG&E curtailed the energy purchased under this agreement by 304 hours. Due to an amendment to the power sales agreement in April 1997, the Company currently does not expect curtailment by PG&E during the remainder of the agreement. The Company believes that the geothermal reserves for the Bear Canyon Power Plant will be sufficient to earn substantially all of the capacity payments for 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 Power Plant. The Bear Canyon Power Plant is located on 284 acres of land located in The Geysers covered by two leases: one with the State of California and the other with a private landowner. During 1997, the Bear Canyon Power Plant generated approximately 168,285,000 kilowatt hours of electrical energy and approximately $25.3 million of revenue. Aidlin Power Plant The Aidlin geothermal facility (the "Aidlin Power Plant") consists of a 20 megawatt geothermal power plant and associated steam fields located in the western portion of The Geysers area of northern California. The Company holds an indirect 5% ownership interest in the Aidlin Power Plant. The Company's ownership interest is held in the form of a 10% general partnership interest in a limited partnership (the "Aidlin 21 24 Partnership"), which in turn owns a 50% ownership interest, as both a limited and general partner, in Geothermal Energy Partners Ltd. ("GEP"), a limited partnership which is the owner of the Aidlin Power Plant. MetLife Capital Corporation owns the remaining 90% interest in the Aidlin Partnership as a limited partner. The remaining 50% of GEP is owned by subsidiaries of Mission Energy Company and Sumitomo Corporation. The Aidlin Power Plant commenced commercial operation in May 1989. The Aidlin Power Plant includes a power plant consisting of two turbine and generator sets manufactured by Fuji Electric and ABB Industries, Inc., as well as seven production wells and two injection wells. Since start-up, the Aidlin Power Plant has operated at an average availability of approximately 98.9%. The construction of the Aidlin Power Plant was financed with a $59.4 million term loan provided by Prudential, which bears interest at a fixed rate of 10.48% per annum and matures on June 30, 2008 according to a specified amortization schedule. Electricity generated by the Aidlin Power Plant is sold to PG&E under two 10 megawatt, 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 megawatts of $167 per kilowatt year for the term of the agreements, so long as the Aidlin Power Plant delivers 80% of its capacity during certain designated periods of the year. In addition, the Aidlin power sales agreements provide for energy payments for 20 megawatts based on a schedule of fixed energy prices in effect through 1999 of 13.83c per kilowatt hour. Thereafter, PG&E is required to pay for electrical energy actually delivered at SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1997, PG&E curtailed the energy purchased under this agreement by 984 hours. The Aidlin Power Plant is operated and maintained by the Company under an operating and maintenance agreement pursuant to which the Company is reimbursed for certain costs and is entitled to an incentive payment based on project performance. This agreement expires on December 31, 1999. The Aidlin Power Plant is located on 713.8 acres of land located in The Geysers, which is leased by GEP from a private landowner. The lease will remain in force so long as geothermal steam is produced in commercial quantities. During 1997, the Aidlin Power Plant generated approximately 172,959,000 kilowatt hours of electrical energy and revenue of $25.0 million. In 1997, the Company recognized revenue of approximately $455,000 as a result of the Company's 5% ownership interest and $3.0 million for services performed under the operating and maintenance agreement. STEAM FIELDS Thermal Power Company Steam Fields The Company acquired Thermal Power Company ("TPC") on September 9, 1994 for a purchase price of $66.5 million. TPC owns a 25% undivided interest in certain geothermal steam fields located at The Geysers in northern California (the "Thermal Power Company Steam Fields"). Union Oil Company of California ("Union Oil") and NEC own the remaining 75% 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 238 production wells, 18 injection wells and 55 miles of steam-transporting pipeline. The 12 plants have a mechanical capacity of 872 megawatts and currently have the capability to operate at over 560 megawatts. 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. PG&E is contractually 22 25 obligated to operate all of the power plants at a minimum of 40% of the field capacity during any given year, and at 25% of the field capacity in any given month. 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 1.65c per kilowatt hour. 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 1997 was 1.92c per kilowatt hour. The price for 1998 is estimated to be 1.95c per kilowatt hour. In addition, TPC receives a monthly fee for effluent disposal and maintenance. During 1997, such monthly fee was $152,000. In March 1996, TPC, NEC and Union Oil entered into an alternative pricing agreement with PG&E for any steam produced in excess of 40% of average field capacity as defined in the steam sales contract. The alternative pricing agreement is effective through December 31, 2000. Under the alternative pricing agreement, PG&E has the option to purchase a portion of the steam that PG&E would likely curtail under the existing steam sales agreement. The price for this portion of steam will be set by TPC, NEC and Union Oil with the intent that it be at competitive market prices. TPC, NEC and Union Oil will solely determine the price and duration of these alternative prices. The steam sales agreement with PG&E also provides for offset payments, which constitute a remedy for insufficient steam. 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 megawatts. In accordance with the steam sales agreement, TPC makes offset payments at a reduced rate until total offsets calculated since July 1, 1991 equal $15.0 million. Accordingly, TPC's share of offsets in 1997 was $582,000. In approximately 2001, when total offsets may exceed $15.0 million, in accordance with the agreement TPC's share of offset payments to PG&E would be approximately 3 1/2 times their current rate (as calculated at the current steam field capacity). 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, TPC 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, TPC may terminate the agreement with a two-year written notice to PG&E. If TPC 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, TPC 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. TPC 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% of their combined mechanical 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 is approximately 8%. The Company expects steam field productivity to continue to decline in the future. The City of Santa Rosa, California, has selected a proposal jointly submitted by the Company and Union Oil to construct a water injection project utilizing tertiary treated wastewater from the City of Santa Rosa. This project is expected to partially offset the anticipated rate of decline in steam field productivity. The implementation of this project, if completed, is subject to certain conditions, including the receipt of state and federal funding. PG&E has recently announced its intention to sell all of its power generating facilities in The Geysers that purchase steam from TPC and the PG&E Unit 13 and PG&E Unit 16 Steam Fields. The Company cannot predict the impact that any such sale would have on the Company's results of operations or financial condition. 23 26 In conjunction with Union Oil and NEC, TPC holds a right of first refusal to match any sales offer for PG&E's 12 power plants which are served by the Thermal Power Company Steam Fields. It cannot be determined at this time whether PG&E will complete the sale of the power plants or whether Union Oil, NEC and TPC will exercise their right of first refusal. On February 13, 1998, Union Oil, NEC and TPC filed a protest with the CPUC objecting to certain aspects of PG&E's application to sell the power plants. In addition, Union Oil, NEC and TPC have commenced arbitration proceedings with PG&E under the steam sales agreement in a dispute over the interpretation of contract provisions concerning minimum operation levels of the power plants. During 1997, the PG&E power plants produced 3,487,592,000 kilowatt hours of electrical energy of which the Company's 25% share is 871,898,000 kilowatt hours for approximately $15.8 million of revenue. PG&E Unit 13 and Unit 16 Steam Fields 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. The PG&E Unit 13 Steam Field includes 956 acres, 28 production wells, five 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 1997 was 0.95c per kilowatt hour. The Company receives an additional 0.05c per kilowatt hour from PG&E for the disposal of liquid effluents produced at Unit 13 and Unit 16. 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 37,371,590 kilowatt hours under the steam sales agreement during 1997. The steam sales agreement with PG&E continues in effect for as long as either Unit 13 or Unit 16 remains in commercial operation for PG&E, which depends in part 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. No assurance can be given that the operation of either Unit 13 or Unit 16 will not become economically impractical at any time. 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%, 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. In order to increase the efficiency of Unit 13 by approximately 20%, the Company agreed to purchase new rotors for $10.8 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. 24 27 The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient to operate Unit 13 and Unit 16 at approximately 77% 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 6.0% in 1997. The Company expects steam field productivity to continue to decline in the future, but at reduced 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. PG&E has recently announced its intention to sell all of its power generating facilities in The Geysers that purchase steam from Thermal Power Company and the PG&E Unit 13 and PG&E Unit 16 Steam Fields. The Company cannot predict the impact that any such sale would have on the Company's results of operations or financial condition. The Company has filed a protest with the CPUC challenging certain aspects of PG&E's application to sell Units 13 and 16. In addition, the Company has filed an action in state court seeking a declaratory judgment and injunctive relief to prohibit PG&E from assigning the steam contract to a third party through its sale of the power plants. During 1997, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient steam to permit Unit 13 and Unit 16 to produce approximately 1,295,000,000 kilowatt hours of electrical energy and approximately $13.0 million of revenue. SMUDGEO #1 Steam Fields The Company holds the leasehold rights to 394 acres of steam fields that supply steam to the power plant for the Sacramento Municipal Utility District ("SMUD") SMUDGEO #1 steam fields (the "SMUDGEO #1 Steam Fields"). The SMUD power plant has a nameplate capacity of 72 megawatts and currently operates at an output of 50 megawatts. The SMUDGEO #1 Steam Fields include 19 producing wells, one injection well and two and one half 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 $1.818 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% 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. The Company receives an additional 0.15c. per kilowatt hour from SMUD for the disposal of liquid effluents produced at the SMUDGEO #1 Steam Fields. The steam sales agreement with SMUD continues until the expiration or termination of the geothermal lease covering the SMUDGEO #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 SMUDGEO #1 Steam Fields currently supply steam sufficient to operate the SMUD power plant at approximately 69% of its nameplate capacity. This percentage reflects a decline in the productivity of the SMUDGEO #1 Steam Fields since commencement of operations. During 1997, the SMUDGEO #1 Steam Fields produced approximately 6,924,000 thousand pounds of steam and approximately $13.1 million of revenue. 25 28 Cerro Prieto Steam Fields In 1995, the Company entered into a series of agreements with Constructora y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain of Coperlasa's creditors pursuant to which the Company has agreed to invest up to $20 million in the Cerro Prieto steam fields (the "Cerro Prieto Steam Fields") located in Baja California, Mexico. The Cerro Prieto Steam Fields provide geothermal steam to three geothermal power plants owned and operated by Comision Federal de Electricidad ("CFE"), the Mexican national utility. The Company's investment consists of a loan of $18.5 million and a $1.5 million payment for an option to purchase a 29% equity interest in Coperlasa for $5.8 million. The $18.5 million loan was made in installments throughout 1995 and 1996, which provided capital to Coperlasa to fund the drilling of new wells and the repair of existing wells to meet its performance under the agreement with CFE. The loan matures in November 1999 and bears interest at an effective rate of 18.9% per annum. The Company is deferring the recognition of income on this loan until the Cerro Prieto project generates sufficient cash flows available for distribution to support the collectibility of interest earned. Pursuant to a technical services agreement, the Company receives fees for its technical services provided to Coperlasa. In addition, if the Company is successful in assisting Coperlasa in producing steam at a lower cost, the Company will receive 30% of the savings, if any. The Cerro Prieto Steam Fields are located near the city of Mexicali, Baja California, at the border of Baja California and the State of California. The Cerro Prieto geothermal resource, which has been commercially produced by CFE since 1973, provides approximately 70% of Baja California's electricity requirements since this region is not connected to the Mexican national power grid. The steam sales agreement between Coperlasa and CFE was entered into in May 1991. Under this agreement, CFE pays for steam delivered up to 1,600 tons per hour plus 10%. Payments for the steam delivered are made in Mexican pesos and are adjusted on a specific unit-of-production basis by a formula that accounts for the increases in inflation in Mexico and the United States, as well as for the devaluation of the peso against the U.S. dollar. This agreement has a termination date of October 2000. GAS FIELDS Montis Niger Gas Fields On January 31, 1997, the Company 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 16,094 gross acres and 15,037 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 80% of the fuel requirements for the Greenleaf 1 and 2 Power Plants. PROJECT DEVELOPMENT AND ACQUISITION The Company is actively engaged in the development and acquisition of power generation projects. The Company has historically focused principally on the development and acquisition of interests in gas-fired and geothermal power projects, although the Company also considers projects that utilize other power generation technologies. The Company has significant expertise in a variety of power generation technologies and has 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. 26 29 PROJECT DEVELOPMENT The development of power generation projects involves numerous elements, including evaluating and selecting development opportunities, designing and engineering the project, obtaining power and steam sales agreements, acquiring necessary land rights, permits and fuel resources, obtaining financing, and managing construction. The Company intends to focus primarily on development opportunities where the Company is able to capitalize on its expertise in implementing an innovative and fully integrated approach to project development in which the Company controls the entire development process. Utilizing this approach, the Company believes that it is able to enhance the value of its projects throughout each stage of development in an effort to maximize its return on investment. The Company is pursuing the development of highly efficient, low-cost merchant power plants that seek to take advantage of inefficiencies in the electricity market. The Company intends to sell all or a portion of the power generated by such merchant plants into the competitive market through a portfolio of short-, medium-and long-term power sales agreements. The Company expects that these projects will represent a prototype for future merchant plant developments by the Company. The Company currently plans to develop additional low-cost, gas-fired facilities in California, Texas, New England and other high priced power markets. The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, the Company must generally obtain power and/or steam 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 the Company 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 the Company 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, 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 the Company 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 the Company were unable to complete the development of a facility, it would generally not be able to recover its 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. There can be no assurance that the Company will be successful in the development of power generation facilities in the future. Pasadena Power Plant Calpine has entered into a development agreement with Phillips Petroleum Company ("Phillips") to construct and operate a 240 megawatt, gas-fired cogeneration project at the Phillips Houston Chemical Complex ("HCC") located in Pasadena, Texas (the "Pasadena Power Plant"). On December 19, 1996, the Company entered into an Energy Sales Agreement with Phillips pursuant to which Phillips will purchase all of the HCC's steam and electricity requirements of approximately 90 megawatts. It is anticipated that the remainder of available electricity output will be sold into the competitive market through Calpine's power sales activities. On December 20, 1996, the Company entered into a credit agreement with ING U.S. Capital Corporation to provide $151.8 million of construction loans and $98.6 million of term loan non-recourse project financing for the Pasadena Power Plant. In accordance with the terms of the agreement, Calpine contributed $53.1 million in equity to the project. The Company commenced construction in February 1997, with commercial operation scheduled to begin in July 1998. 27 30 Dighton and Tiverton Power Plants In October 1997, Calpine entered into agreements with Energy Management Inc. ("EMI"), a New England based power developer, to invest in the development of two merchant power plants in New England, including a 169 megawatt gas-fired combined-cycle merchant power plant to be located in Dighton, Massachusetts (the "Dighton Power Plant") and a 265 megawatt gas-fired power plant to be located in Tiverton, Rhode Island (the "Tiverton Power Plant"). The Company intends to invest $43.0 million of equity in the development of the Tiverton Power Plant. In October 1997, the Company invested $16.0 million in the development of the Dighton Power Plant. This investment, which is structured as subordinated debt, will provide the Company with a preferred payment stream at a rate of 12.07% per annum for a period of twenty years from the commercial operation date. The Dighton Power Plant is being developed by EMI. It is estimated that the development of the Dighton Power Plant will cost approximately $120.0 million, which is being financed, in part, with $104.0 million of non-recourse construction financing. Upon commercial operation, EMI is expected to contribute $2.0 million of equity and the construction financing will convert to a $102.0 million term loan non-recourse project financing. Construction commenced in the fourth quarter of 1997 and commercial operation is scheduled to begin in early 1999. Upon completion, the Dighton Power Plant will be operated by EMI and will sell its output into the New England Power Pool and to wholesale and retail customers in the northeastern United States. Pursuant to a letter agreement with EMI providing for an exclusivity period for negotiations through March 31, 1998, the Company intends to invest up to $43.0 million of equity in the development of the Tiverton Power Plant. The Tiverton Power Plant is being developed by EMI. It is estimated that the development of the Tiverton Power Plant will cost approximately $173.0 million. Construction is currently scheduled to commence in late 1998 and commercial operation is scheduled for early 2000. Upon completion, the Tiverton Power Plant will be operated by EMI and will sell its output in the New England Power Pool and to wholesale and retail customers in the northeastern United States. Magic Valley Power Plant On January 21, 1998, Calpine announced that it had been selected by Magic Valley Electric Cooperative, Inc., located in South Texas, to begin final negotiations to supply its electric needs from 2001 through 2021. The Company expects the electricity will be supplied by a 700 megawatt gas-fired merchant power plant currently under development by the Company in Edinburg, Texas. Sutter Power Plant In February 1997, the Company 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 merchant power plant. The Sutter Power Plant is expected to provide electricity to the deregulated California power market commencing in the year 2000. The Company is currently pursuing regulatory agency permits for this project. On January 21, 1998, the Company announced that the Sutter Power Plant has met the California Energy Commission's Data Adequacy requirements in its Application for Certification. ACQUISITIONS The Company will consider the acquisition of an interest in operating projects as well as projects under development where Calpine would assume responsibility for completing the development of the project. In the acquisition of power generation facilities, Calpine generally seeks to acquire an ownership interest in facilities that offer the Company attractive opportunities for revenue and earnings growth, that have existing, favorable long-term power sales agreements with major electric utilities or major users of power (i.e., industrial facilities), and that permit the Company to assume sole responsibility for the operation and maintenance of the facility. In evaluating and selecting a project for acquisition, the Company considers 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 28 31 agreements, the quantity and quality of any geothermal or other natural resource involved, and the actual condition of the physical plant. In addition, the Company assesses the past performance of an operating project and prepares financial projections to determine the profitability of the project. The Company generally seeks to obtain a significant equity interest in a project and to obtain the operation and maintenance contract for that project. The Company has grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields. The Company believes that although the domestic power industry is undergoing consolidation and that significant acquisition opportunities are available, the Company is likely to confront significant competition for acquisition opportunities. In addition, there can be no assurance that the Company will continue to identify attractive acquisition opportunities at favorable prices or, to the extent that any opportunities are identified, that the Company will be able to consummate such acquisitions. Pittsburg Power Plant On February 18, 1998, the Company announced that it has entered into exclusive negotiations for a four month period ending May 31, 1998, with The Dow Chemical Company ("Dow") to acquire its 70 megawatt gas-fired power plant and a natural gas pipeline system located adjacent to Dow's chemical plant in Pittsburg, California. The pipeline delivers low-cost fuel to the plant from Sacramento Basin gas fields. As part of the transaction, The Company will enter into long-term agreements with Dow to provide electricity and steam to its chemical facility and steam to the nearby USS-POSCO Industries steel mill. In addition, the Company will acquire rights to a site at the Dow chemical facility suitable for future expansion. The Company expects to complete the acquisition during the second quarter of 1998. GOVERNMENT REGULATION The Company is 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 29 32 laws concerning rate or financial regulation. These exemptions are important to the Company and its competitors. The Company believes that each of the electricity generating projects in which the Company owns an interest currently meets the requirements under PURPA necessary for QF status. Most of the projects which the Company is currently planning or developing are also expected to be QFs. 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. Due to increasing competition for utility contracts, the current practice is for most power sales agreements to be awarded at a rate below avoided cost. 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. 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. The Company endeavors to develop its projects, monitor compliance by the projects with applicable regulations and choose its 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 the Company's 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, the Company 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 projects in which the Company has 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 the Company 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 the Company's 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. If a project were to lose its QF status, the Company could attempt to avoid holding company status (and thereby protect the QF status of its other projects) on a prospective basis by restructuring the project, by changing its voting interest in the entity owning the non-qualifying project to nonvoting or limited partnership interests and selling the voting interest to an individual or company which could tolerate the lack of exemption from PUHCA, or by otherwise restructuring ownership of the project so as not to become a holding company. These actions, however, would require approval of the Securities and Exchange Commission ("SEC") or a no-action letter from the SEC, and would result in a loss of control over the non-qualifying project, could result in a reduced financial interest therein and might result in a modification of the Company's operation and 30 33 maintenance agreement relating to such project. A reduced financial interest could result in a gain or loss on the sale of the interest in such project, the removal of the affiliate through which the ownership interest is held from the consolidated income tax group or the consolidated financial statements of the Company, or a change in the results of operations of the Company. Loss of QF status on a retroactive basis could lead to, among other things, fines and penalties being levied against the Company and its subsidiaries and claims by utilities for refund of payments previously made. 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. Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at avoided costs. The Company does not know whether such legislation will be passed or what form it may take. The Company believes that if any such legislation is passed, it would apply to new projects. As a result, although such legislation may adversely affect the Company's ability to develop new projects, the Company believes it would not affect the Company's existing QFs. There can be no assurance, however, that any legislation passed would not adversely impact the Company's 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 the 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 expected effect of such amendments would be to enhance the development of non-QFs which do not have to meet the fuel, production and ownership requirements of PURPA. The Company believes that the amendments could benefit the Company by expanding its ability to own and operate facilities that do not qualify for QF status, but may also result in increased competition by allowing utilities to develop such facilities which are not subject to the constraints of PUHCA. Federal Natural Gas Transportation Regulation The Company has an ownership interest in and operates ten 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 for 31 34 such services are subject to continuing FERC oversight. Order No. 636, issued by FERC in April 1992, mandates the restructuring of interstate natural gas pipeline sales and transportation services and will result in changes in the terms and conditions under which interstate pipelines will provide transportation services, as well as the rates pipelines may charge for such services. The restructuring required by the rule includes (i) the separation (unbundling) of a pipeline's sales and transportation services, (ii) the implementation of a straight fixed-variable rate design methodology under which all of a pipeline's fixed costs are recovered through its reservation charge, (iii) the implementation of a capacity releasing mechanism under which holders of firm transportation capacity on pipelines can release that capacity for resale by the pipeline and (iv) the opportunity for pipelines to recover 100% of their prudently incurred costs (transition costs) associated with implementing the restructuring mandated by the rule. Pipelines were required to file tariff sheets implementing Order No. 636 by December 31, 1992. FERC affirmed the major components of Order No. 636 in Order Nos. 636A and B issued in August and November 1992. The restructuring required by the rule became effective in late 1993. 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. The California Public Utilities Commission ("CPUC") and the California Joint Legislative Committee on Lowering the Cost of Electric Services commenced proceedings and hearings related to the restructure of the California electric services industry in 1994. The proceedings and hearings were initiated as a result of the CPUC study and Order Instituting Rulemaking and Order Instituting Investigation on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation, issued by the CPUC on April 20, 1994. The FERC, as authorized under the Energy Policy Act of 1992, has also initiated proceedings and continues to hold workshops and hearings on policy issues related to a more competitive electric services industry. Though the state of California appears to be at the forefront, many other states are in various stages of review and interest in deregulation, moving toward a more competitive electric services industry. On December 20, 1995, the CPUC issued its decision on California electric industry restructure which envisioned commencement of deregulation and implementation of customer choice beginning January 1, 1998, with all customers participating by 2003. The decision provided for phased-in customer choice, development of a non-discriminatory market structure, full recovery of utility stranded costs, sanctity of existing contracts, and continuation of existing public purpose programs including promotion of fuel diversity through a renewable energy purchase requirement. On February 5, 1996, the CPUC issued a procedural plan to facilitate the transition of the electric generation market to competition. The electric restructuring roadmap focused on the multiple and interrelated tasks to be accomplished and set forth the process to achieve the necessary procedural milestones to be completed in order to meet the restructure implementation goal. 32 35 In 1996, the Joint Legislative Conference Committee held hearings related to electric industry restructure and drafted legislation, AB 1890 (the "Bill"), which was approved by the legislature in August 1996 and signed by the Governor on September 23, 1996. The legislation codifies much of the December CPUC decision as modified in January 1996 and directed the CPUC to proceed with resolve of outstanding issues resulting in implementation of restructure no later than January 1, 1998. The Bill accelerated the transition period in which utilities are allowed to recover their stranded costs from five years to four years, continued to provide for sanctity of existing contracts with provisions for voluntary restructure, established an electricity rate freeze for the transition period and mandated a 10% rate reduction effective January 1, 1998 for small commercial and residential customers through issuance of rate reduction bonds, and replaced the CPUC renewable technology purchase requirement with funds specified for use in public service programs. On December 20, 1996, the CPUC responded to the legislation and issued an updated procedural roadmap consistent with provisions included in the Bill. Proceedings are ongoing at the CPUC and FERC for establishment of 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 ("PX") responsible for an efficient competitive electric energy auction open on a non-discriminatory basis to all electric services providers. Other proceedings now ongoing 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 (Pacific Gas & Electric 50%; Southern California Edison, 100%), 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. On May 6, 1997, the CPUC issued decisions which eliminated phase-in and provided for implementation of direct access for all customers beginning January 1, 1998, and the unbundling of revenue cycle services, thereby allowing all electric service providers to participate in metering and billing services. The CPUC has subsequently extended the implementation date to April 1, 1998. 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 Calpine through implementation of customer choice (direct access), the CPUC decision and the AB 1890 restructuring legislation both recognize the sanctity of existing contracts, provide for mitigation of utility horizontal market power through divestiture of fossil generation and provide 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. 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. 33 36 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 the Company 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 the Company. In most cases, analogous state laws also exist that may impose similar, and in some cases more stringent, requirements on the Company 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. The Company believes that all of the Company's 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, the Company's operations have, in certain instances, necessitated variances under applicable California air pollution control laws. However, the Company believes that it is in 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. The Company is required to obtain a wastewater and storm water discharge permit for wastewater and runoff, respectively, from certain of the Company's facilities. The Company believes that, with respect to its geothermal operations, it is exempt from newly promulgated federal storm water requirements. The Company believes that it is in 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. The Company believes that it is 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, the Company is subject to certain solid waste requirements under applicable California laws. The Company believes that its operations are in 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 34 37 include past and present owners and operators of, as well as generators of wastes sent to, a site. As of the present time, the Company is not subject to liability for any Superfund matters. However, the Company generates certain wastes, including hazardous wastes, and sends certain of its wastes to third-party waste disposal sites. As a result, there can be no assurance that the Company will not incur liability under CERCLA in the future. RISK FACTORS SUBSTANTIAL LEVERAGE The Company is substantially leveraged as a result of outstanding indebtedness of the Company and non-recourse debt financing of certain of the Company's subsidiaries incurred to finance the acquisition and development of power generation facilities. As of December 31, 1997, the Company's total consolidated indebtedness was $855.9 million, its total consolidated assets were $1.4 billion and its stockholders' equity was $240.0 million. The ability of the Company to meet its debt service obligations and to repay outstanding indebtedness according to its terms will be dependent primarily upon the performance of the power generation facilities in which the Company has an interest. On September 25, 1996, the Company entered into a $50.0 million three-year revolving credit facility with The Bank of Nova Scotia as agent (the "Revolving Credit Facility"). The Revolving Credit Facility contains certain restrictions that significantly limit or prohibit, among other things, the ability of the Company or its subsidiaries to incur indebtedness, make prepayments of certain indebtedness, pay dividends, make investments, engage in transactions with affiliates, create liens, sell assets and engage in mergers and consolidations. The Company believes that, based on current levels of operations and anticipated growth, cash flow from operations, together with other available sources of funds, including borrowings under the Company's existing borrowing arrangements, will be adequate to make required payments of principal and interest on the Company's debt, including the 8 3/4% Senior Notes, the 10 1/2% Senior Notes and the 9 1/4% Senior Notes, and to enable the Company to comply with the terms of its Indentures and other debt agreements, although there can be no assurance that this will be the case. If the Company is unable to comply with the terms of its Indentures and other debt agreements and fails to generate sufficient cash flow from operations in the future, the Company may be required to refinance all or a portion of its existing debt or to obtain additional financing. There can be no assurance that any such refinancing would be possible or that any additional financing could be obtained, particularly in view of the Company's high levels of debt and the debt incurrence restrictions under existing Indentures and other debt agreements. If cash flow is insufficient and no such refinancing or additional financing is available, the Company may be forced to default on its debt obligations. In the event of a default under the terms of any of the indebtedness of the Company, subject to the terms of such indebtedness, the obligees thereunder would be permitted to accelerate the maturity of such obligations, which could cause defaults under other obligations of the Company. POSSIBLE UNAVAILABILITY OF FINANCING Each power generation facility acquired or developed by the Company will require substantial capital investment. The Company's ability to arrange financing and the cost of such financing are dependent upon numerous factors, including 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 the Company, the continued success of the Company's current power generation facilities, and provisions of tax and securities laws that are conducive to raising capital. There can be no assurance that financing for new facilities will be available to the Company on acceptable terms in the future. The Company's power generation facilities have been financed using a variety of leveraged financing structures, primarily consisting of non-recourse project financing and lease obligations. As of December 31, 1997, the Company had approximately $855.9 million of total consolidated indebtedness, of which approximately 35% represented non-recourse project financing. Each non-recourse project financing and lease 35 38 obligation is structured to be fully paid out of cash flow provided by the facility or facilities, the assets of which (together with pledges of stock or partnership interests in the entity owning the facility) collateralize such obligations, without any claim against the Company's general corporate funds. Such leveraged financing permits the development of larger facilities, but also increases the risk to the Company that its interest in a particular facility could be impaired or that fluctuations in revenues could adversely affect the Company's ability to meet its lease or debt obligations. The debt collateralized by the interests of the Company in each operating facility reduces the liquidity of such assets since any sale or transfer of a facility would be subject both to the lien securing the facility indebtedness and to transfer restrictions in the financing agreements. While the Company intends to utilize non-recourse or lease financing when appropriate, there can be no assurance that market conditions and other factors will permit the same limited equity investment by the Company or the same substantially non-recourse nature of financings for future facilities. In the event of a default under a financing agreement, and assuming the Company or the other equity investors in a facility are unable or choose not to cure such default within applicable cure periods, if any, the lenders or lessors would generally have rights to the facility, any related geothermal resource or natural gas reserves, related contracts and cash flows and all licenses and permits necessary to operate the facility. In the event of foreclosure after such a default, the Company might not retain any interest in such facility. The Company does not believe the existence of non-recourse or lease financing will materially affect its ability to continue to borrow funds in the future in order to finance new facilities. There can be no assurance, however, that the Company will continue to be able to obtain the financing required to develop its power generation facilities on terms satisfactory to the Company. The Company has from time to time guaranteed certain obligations of its subsidiaries and other affiliates. There can be no assurance that, in respect of any financings of facilities in the future, lenders or lessors will not require the Company to guarantee the indebtedness of such future facilities, rendering the Company's general corporate funds vulnerable in the event of a default by such facility or related subsidiary. IMPACT OF AVOIDED COST PRICING; ENERGY PRICE FLUCTUATIONS PG&E pays a fixed price for each unit of electrical energy according to schedules set forth in the long-term power sales agreements for the Bear Canyon (20 megawatts) and West Ford Flat (27 megawatts) Power Plants. The fixed price periods under these power sales agreements expire in September and December 1998, respectively. After the fixed price periods expire, while the basis for the capacity and capacity bonus payments under these power sales agreements remains the same, the energy payments adjust to interim short-run avoided cost ("SRAC"), which is calculated pursuant to the methodology approved by the CPUC on December 9, 1996, and will continue at SRAC until the independent power exchange has commenced operations and is functioning properly. The independent power exchange is currently scheduled to commence operations on April 1, 1998. Thereafter, SRAC will become the energy clearing price of the independent power exchange (referred to herein as the "Power Exchange Price"). During 1997, SRAC averaged approximately 2.94c per kilowatt hour. As a result, while SRAC does not affect capacity payments under the power sales agreements, the Company's energy revenue under these power sales agreements is expected to be materially reduced at the expiration of the fixed price period. Such reduction may have a material adverse effect on the Company's results of operations. The Company expects the forecasted decline in energy revenues will be mitigated by decreased royalty expenses and planned operating cost reductions at the facilities. In addition, the Company will continue its strategy of offsetting such reductions through its acquisition and development program. In addition, prices paid for the steam delivered by the Company's steam fields are based on a formula that partially reflects the price levels of nuclear and fossil fuels, and, therefore, a reduction in the price levels of such fuels may reduce revenue under the steam sales agreements for the steam fields. POWER PROJECT DEVELOPMENT AND ACQUISITION RISKS The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, the Company must generally obtain governmental permits and 36 39 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 the Company 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 the Company 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, 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 the Company to expend significant sums for preliminary engineering, permitting, legal and other expenses before it can be determined whether a project is feasible, economically attractive or financeable. If the Company were unable to complete the development of a facility, it would generally not be able to recover its 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. There can be no assurance that the Company will be successful in the development of power generation facilities in the future. The Company has grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields. The Company believes that although the domestic power industry is undergoing consolidation and that significant acquisition opportunities are available, the Company is likely to confront significant competition for acquisition opportunities. In addition, there can be no assurance that the Company will continue to identify attractive acquisition opportunities at favorable prices or, to the extent that any opportunities are identified, that the Company will be able to consummate such acquisitions. START-UP RISKS The commencement of operation of a newly constructed power plant or steam field 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 of these 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. Such insurance, warranties or performance guarantees may not be adequate to cover lost revenues or increased expenses and, 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 the Company losing its interest in such power generation facility or steam field. In addition, power sales agreements, which are typically entered into with a utility early in the development phase of a project, often enable the utility to terminate such agreement, or to retain security posted as liquidated damages, in the event that a project fails to achieve commercial operation or certain operating levels by specified dates or fails to make certain specified payments. In the event such a termination right is exercised, a project may not commence generating revenues, the default provisions in a financing agreement may be triggered (rendering such debt immediately due and payable) and the project may be rendered insolvent as a result. GENERAL OPERATING RISKS The Company currently operates 16 out of 23 of the power generation facilities and steam fields in which it has an interest. The continued operation of power generation facilities and steam fields 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. To date, the Company's power generation facilities have operated at an average availability of approximately 97%, and although from time to time the Company's power generation facilities and steam fields have experienced certain equipment breakdowns or failures, such breakdowns or failures have not had a material adverse effect on the operation of such facilities or on the Company's results of operations. Although the Company's 37 40 facilities contain certain redundancies and back-up mechanisms, there can be no assurance that any such breakdown or failure would not prevent the affected facility or steam field from performing under applicable power and/or steam sales agreements. In addition, although insurance is maintained to protect against certain of these operating risks, the proceeds of such insurance may not be adequate to cover lost revenues or increased expenses, and, as a result, the entity owning such power generation facility or steam field may be unable to service principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation could result in the Company losing its interest in such power generation facility or steam field. RISKS RELATED TO THE DEVELOPMENT AND OPERATION OF GEOTHERMAL ENERGY RESOURCES 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 and operational factors relating to the extraction of fluids, including operating expenses, energy price levels and capital expenditure requirements relating primarily to the drilling of new wells. In connection with the development of a project, the Company estimates the productivity of the geothermal resource and the expected decline in such productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient recoverable reserves being available for sustained generation of the electrical power capacity desired. An incorrect estimate by the Company or an unexpected decline in productivity could have a material adverse effect on the Company's results of operations. Geothermal reservoirs are highly complex, and, 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 those of the Company. 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 the Company has extensive experience in the operation and development of geothermal energy resources and in preparing such estimates, there can be no assurance that the Company will be able to successfully manage the development and operation of its geothermal reservoirs or that the Company will accurately estimate the quantity or productivity of its steam reserves. DEPENDENCE ON THIRD PARTIES The nature of the Company's power generation facilities is such that each facility generally relies on one power or steam sales agreement with a single electric utility customer for substantially all, if not all, of such facility's revenue over the life of the project. During 1997, approximately 80% and 5% of the Company's total revenue was attributable to revenue received pursuant to power and steam sales agreements with PG&E and SMUD, respectively. The power and steam sales agreements are generally long-term agreements, covering the sale of electricity or steam for initial terms of 20 or 30 years. However, the loss of any one power or steam sales agreement with any of these utility customers could have a material adverse effect on the Company's results of operations. In addition, any material failure by any utility customer to fulfill its obligations under a power or steam sales agreement could have a material adverse effect on the cash flow available to the Company and, as a result, on the Company's results of operations. PG&E has recently announced its intention to sell all of its power generating facilities in The Geysers that purchase steam from TPC and the PG&E Unit 13 and PG&E Unit 16 Steam Fields. Although there can be no assurance, the Company does not expect that such sale, if consummated, would have a material adverse impact on the Company's results of operations or financial condition. Furthermore, each power generation facility may depend on a single or limited number of entities to purchase thermal energy, or to supply or transport natural gas to such facility. The failure of any one utility customer, steam host, gas supplier or gas transporter to fulfill its contractual obligations could have a material adverse effect on a power project and on the Company's business and results of operations. 38 41 INTERNATIONAL INVESTMENTS The Company has made an investment in the Cerro Prieto geothermal steam fields located in Mexico and may pursue additional international investments, in selected countries. Such investments are subject to risks and uncertainties relating to the political, social and economic structures of those countries. 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. GOVERNMENT REGULATION The Company's 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 the Company believes that it has obtained the requisite approvals for its existing operations and that its business is operated in accordance with applicable laws, the Company remains subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. There can be no assurance that existing laws and regulations will not be revised or that new laws and regulations will not be adopted or become applicable to the Company that may have a material adverse effect on the Company's business or results of operations, nor can there be any assurance that the Company will be able to obtain all necessary licenses, permits, approvals and certificates for proposed projects or that completed facilities will 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, and intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain permits and may create a significant risk of expensive delays or significant loss of value in a project if the project is unable to function as planned due to changing requirements or local opposition. The Company's operations are subject to the provisions of various energy laws and regulations, including PURPA, PUHCA, and state and local regulations. PUHCA provides for the extensive regulation of public utility holding companies and their subsidiaries. PURPA provides to QFs and owners of QFs certain exemptions from certain federal and state regulations, including rate and financial regulations. Under present federal law, the Company is not and will not be subject to regulation as a holding company under PUHCA as long as the power plants in which it has an interest are QFs under PURPA or are subject to another exemption. In order to be a QF, a facility must be not more than 50% owned by an electric utility or electric utility holding company. A QF that is a cogeneration facility must produce not only electricity, but also useful thermal energy for use in an industrial or commercial process or heating or cooling applications in certain proportions to the facility's total energy output, and it must meet certain energy efficiency standards. Therefore, loss of a thermal energy customer could jeopardize a cogeneration facility's QF status. All geothermal power plants up to 80 megawatts that meet PURPA's ownership requirements and certain other standards are considered QFs. If one of the power plants in which the Company has an interest were to lose its QF status and not otherwise receive a PUHCA exemption, the project subsidiary or partnership in which the Company has an interest owning or leasing that plant could become a public utility company, which could subject the Company to significant federal, state and local laws, including rate regulation and regulation as a public utility holding company under PUHCA. This loss of QF status, which may be prospective or retroactive, in turn, could cause all of the Company's other power plants to lose QF status because, under FERC regulations, a QF cannot be owned by an electric utility or electric utility holding company. In addition, a loss of QF status could, depending on the power sales agreement, allow the power purchaser to cease taking and paying for electricity or to seek refunds of past amounts paid and thus could cause the loss of some or all contract revenues or otherwise impair the value of a project and could trigger defaults under provisions of the applicable project contracts and financing agreements (rendering such debt immediately due and payable). If a power purchaser ceased taking and paying for electricity or sought 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. 39 42 Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at avoided costs. The Company does not know whether such legislation will be passed or what form it may take. The Company believes that if any such legislation is passed, it would apply to new projects. As a result, although such legislation may adversely affect the Company's ability to develop new projects, the Company believes it would not affect the Company's existing QFs. There can be no assurance, however, that any legislation passed would not adversely impact the Company's existing projects. Many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry. In a December 20, 1995 policy decision, the CPUC outlined a new market structure that would provide for a competitive power generation industry and direct access to generation for all consumers within five years. The CPUC has issued decisions which provide for direct access for all customers beginning April 1, 1998, and the unbundling of all electric services. As part of its policy decision, the CPUC indicated that power sales agreements of existing QFs would be honored. The Company cannot predict the final form or timing of the proposed restructuring and the impact, if any, that such restructuring would have on the Company's existing business or results of operations. SEISMIC DISTURBANCES Areas in which the Company operates and is developing many of its geothermal and gas-fired projects are subject to frequent low-level seismic disturbances, and more significant seismic disturbances are possible. While the Company's existing power generation facilities are built to withstand relatively significant levels of seismic disturbances, and the Company believes it maintains adequate insurance protection, there can be no assurance that earthquake, property damage or business interruption insurance will be adequate to cover all potential losses sustained in the event of serious seismic disturbances or that such insurance will continue to be available to the Company on commercially reasonable terms. AVAILABILITY OF NATURAL GAS To date, the Company's fuel acquisition strategy has included various combinations of Company-owned gas reserves, gas prepayment contracts and short, medium and long-term supply contracts. In its gas supply arrangements, the Company attempts 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. The Company believes that there will be adequate supplies of natural gas available at reasonable prices for each of its facilities when current gas supply agreements expire. There can be no assurance, however, that gas supplies will be available for the full term of the facilities' power sales agreements, or that gas prices will not 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 material adverse impact on the Company's results of operations. COMPETITION The power generation industry is characterized by intense competition, and the Company encounters 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 has issued decisions which provide for direct access for all customers beginning April 1, 1998. Regulatory initiatives are also being considered in other states, including Texas, New York and states in New England. 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. 40 43 DEPENDENCE ON SENIOR MANAGEMENT The Company's success is largely dependent on the skills, experience and efforts of its senior management. The loss of the services of one or more members of the Company's senior management could have a material adverse effect on the Company's business and development. To date, the Company generally has been successful in retaining the services of its senior management. QUARTERLY FLUCTUATIONS; SEASONALITY 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, if any, 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. EMPLOYEES As of December 31, 1997, the Company employed 356 people. None of the Company's employees are covered by collective bargaining agreements, and the Company has never experienced a work stoppage, strike or labor dispute. The Company considers relations with its employees to be good. ITEM 2. PROPERTIES The Company's principal executive office is located in San Jose, California under a lease that expires in June 2001. The Company, through its ownership of CGC and TPC, has 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 TPC's 25% undivided interest in the TPC Steam Fields which are operated by Union Oil. In the Glass Mountain and Medicine Lake areas in northern California, the Company holds leasehold interests in 18 leases comprising approximately 25,028 acres of federal geothermal resource lands. In general, under the leases, the Company has 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. The Company believes that its leases are valid and that it has complied with all the requirements and conditions material to their continued effectiveness. A number of the Company's leases for undeveloped properties may expire in any given year. Before leases expire, the Company performs geological evaluations in an effort to determine the resource potential of the underlying properties. No assurance can be given that the Company will decide to renew any expiring leases. The Company, through its ownership of the Greenleaf 1 Power Plant, owns 77 acres in Sutter County, California. The Company owns the Calpine Gas Company, which includes 112 leases covering approximately 16,094 gross acres and 15,037 net acres. The Company believes that its properties are adequate for its current operations. 41 44 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 L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power 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. All of the defendants have filed motions to dismiss such claims, which are currently pending. The Company believes that the claims of Indeck are without merit and that the resolution of this matter will not have a material adverse effect on the Company's financial position or results of operations. On February 17, 1998, the Company filed an action in the Superior Court of California, Sonoma County, seeking injunctive and declaratory relief to prevent PG&E from unilaterally assigning the Company's steam sales contract to the prospective winning bidder in PG&E's recently announced auction of its power plants in The Geysers. On January 14, 1998, PG&E filed an application with the CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it seeks authorization to sell five electric generating plants and related assets. Included in this proposed sale are The Geysers Geothermal Power Plants (including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric generating plants. In PG&E's 851 Filing, PG&E announced its intention to assign its rights and to delegate its duties under the Company's steam contract to the successful third party purchaser of the Unit 13 and Unit 16 Power Plants. The Company has been informed by PG&E that it will attempt to make such assignment and delegation without first seeking and obtaining the approval and consent of the Company. The Company is challenging the continued validity of the price term of the steam sales contract following the proposed divestiture by PG&E of 98% of its fossil fueled steam-electric generating plants, as the price term of the steam sales contract is based on a complex formula that reflects PG&E's weighted average cost of fossil and nuclear fuel from the preceding year. In a related action, the Company has filed a protest with the CPUC which raises issues similar to those addressed in the above-referenced lawsuit and, in addition, challenges certain inaccuracies contained in portions of PG&E's 851 Filings related to Unit 13 and Unit 16. As no discovery has been conducted in either matter, nor has any answer been filed in the lawsuit, the Company is unable to predict the outcome of these cases. An action was filed against Lockport Energy Associates, L.P. ("LEA") on August 7, 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 the Federal Energy Regulatory Commission (the "FERC") and the New York Public Service Commission ("NYPSC"), to modify contract rates to be paid to the Lockport Power Plant. On October 14, 1997, NYPSC, a named defendant in the NYSEG action, filed a cross-claim alleging that the FERC violated PURPA and the Federal Power Act by failing to reform the NYSEG contract which was previously approved by the NYPSC. LEA continues to vigorously defend this action, although it is unable to predict the outcome of this case. 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. In the event the NYSEG's action is successful, the Company may choose to exercise its right to require BUG to purchase its interest in the Lockport Power Plant. 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. As of December 31, 1997, TNP has withheld approximately $5.4 million related to transmission charges and has continued to withhold approximately $450,000 per month thereafter. CLC filed a petition for declaratory order with the Texas Public Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas PUC declare that TNP's 42 45 withholding is in error. This matter is pending before the Texas PUC. In addition, as of December 31, 1997, TNP has withheld approximately $4.4 million of standby power charges and has continued to withhold approximately $270,000 per month thereafter. CLC has filed a lawsuit in Texas against TNP claiming that TNP is in breach of certain provisions of the power sales agreement, including the provisions involved in the disputes described above, and is seeking in excess of $15.0 million in damages. A trial is scheduled to begin on June 1, 1998. The Company is unable to predict the outcome of either of these proceedings. 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 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 29 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. SELECTED FINANCIAL DATA The information required hereunder is set forth under "Selected Consolidated Financial Data" included in Appendix F to this report. 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 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. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE None. ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES Incorporated by reference from Proxy Statement relating to the 1998 Annual Meeting of Shareholders. ITEM 11. EXECUTIVE COMPENSATION Incorporated by reference from Proxy Statement relating to the 1998 Annual Meeting of Shareholders. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Incorporated by reference from Proxy Statement relating to the 1998 Annual Meeting of Shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. 43 46 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, 1997 and 1996 Consolidated Statements of Operations for the Years Ended December 31, 1997, 1996 and 1995 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1997, 1996 and 1995 Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995 Notes to Consolidated Financial Statements for the Years Ended December 31, 1997, 1996 and 1995 (A)-2. FINANCIAL STATEMENTS AND SCHEDULES The following items appear in Appendix F of this report: CALPINE CORPORATION I Condensed Financial Information of Registrant Report of Independent Public Accountants Balance Sheets, December 31, 1997 and 1996 Statements of Operations for the Years Ended December 31, 1997, 1996 and 1995 Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995 Notes to Condensed Financial Statements for the Years Ended December 31, 1997, 1996 and 1995 II Valuation and Qualifying Accounts SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY Independent Auditor's Report Consolidated Balance Sheet, December 31, 1997 and 1996 Consolidated Statement of Income for the Years Ended December 31, 1997, 1996 and 1995 Consolidated Statements of Changes in Partners' Equity for the Years Ended December 31, 1997, 1996 and 1995 Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995 Notes to Consolidated Financial Statements for the Year Ended December 31, 1997 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. 44 47 (A)-3. EXHIBITS The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 -- Amended and Restated Certificate of Incorporation of Calpine Corporation, a Delaware corporation.(l) 3.2 -- Amended and Restated Bylaws of Calpine Corporation, a Delaware corporation.(l) 4.1 -- Indenture dated as of February 17, 1994 between the Company and Shawmut Bank of Connecticut, National Association, as Trustee, including form of Notes.(a) 4.2 -- Indenture dated as of May 16, 1996 between the Company and Fleet National Bank, as Trustee, including form of Notes.(m) 10.1 -- Financing Agreements 10.1.1 -- Term and Working Capital Loan Agreement, dated as of June 1, 1990, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.) and Deutsche Bank AG, New York Branch.(a) 10.1.2 -- First Amendment to Term and Working Capital Loan Agreement, dated as of June 29, 1990, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.) and Deutsche Bank AG, New York Branch.(a) 10.1.3 -- Second Amendment to Term and Working Capital Loan Agreement, dated as of December 1, 1990, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.) and Deutsche Bank AG, New York Branch.(a) 10.1.4 -- Third Amendment to Term and Working Capital Loan Agreement, dated as of June 26, 1992, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), Deutsche Bank AG, New York Branch, National Westminster Bank PLC, Union Bank of Switzerland, New York Branch, and The Prudential Insurance Company of America.(a) 10.1.5 -- Fourth Amendment to Term and Working Capital Loan Agreement, dated as of April 1, 1993, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), Deutsche Bank AG, New York Branch, National Westminster Bank PLC, Union Bank of Switzerland, New York Branch, and The Prudential Insurance Company of America.(a) 10.1.6 -- Construction and Term Loan Agreement, dated as of January 30, 1992, between Sumas Cogeneration Company, L.P., The Prudential Insurance Company of America and Credit Suisse, New York Branch.(a) 10.1.7 -- Amendment No. 1 to Construction and Term Loan Agreement, dated as of May 24, 1993, between Sumas Cogeneration Company, L.P., The Prudential Insurance Company of America and Credit Suisse, New York Branch.(a) 10.1.8 -- Credit Agreement Construction Loan and Term Loan Facility, dated as of January 10, 1990, between Credit Suisse and O.L.S. Energy-Agnews.(a) 10.1.9 -- Amendment No. 1 to Credit Agreement Construction Loan and Term Loan Facility, dated as of December 5, 1990, between Credit Suisse and O.L.S. Energy-Agnews.(a) 10.1.10 -- Participation Agreement, dated as of December 1, 1990, between O.L.S. Energy-Agnews, Nynex Credit Company, Credit Suisse, Meridian Trust Company of California and GATX Capital Corporation.(a) 10.1.11 -- Facility Lease Agreement, dated as of December 1, 1990, between Meridian Trust Company of California and O.L.S. Energy-Agnews.(a)
45 48
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.1.12 -- Project Revenues Agreement, dated as of December 1, 1990, between O.L.S. Energy-Agnews, Meridian Trust Company of California and Credit Suisse.(a) 10.1.13 -- Project Credit Agreement, dated as of June 30, 1995, between Calpine Greenleaf Corporation, Greenleaf Unit One Associates, Greenleaf Unit Two Associates, Inc. and The Sumitomo Bank, Limited.(g) 10.1.14 -- Lease dated as of April 24, 1996 between BAF Energy A California Limited Partnership, Lessor, and Calpine King City Cogen, LLC, Lessee.(j) 10.1.15 -- Credit Agreement, dated as of August 28, 1996, among Calpine Gilroy Cogen, L.P. and Banque Nationale de Paris.(l) 10.1.16 -- Credit Agreement, dated as of September 25, 1996, among Calpine Corporation and The Bank of Nova Scotia.(m) 10.1.17 -- Credit Agreement, dated December 20, 1996, among Pasadena Cogeneration L.P. and ING (U.S.) Capital Corporation and The Bank Parties Hereto.(n) 10.2 -- Purchase Agreements 10.2.1 -- Purchase Agreement, dated as of April 1, 1993, between Sonoma Geothermal Partners, L.P., Healdsburg Energy Company, L.P. and Freeport-McMoRan Resource Partners, Limited Partnership.(a) 10.2.2 -- Stock Purchase Agreement, dated as of June 27, 1994, between Maxus International Energy Company, Natomas Energy Company, Calpine Corporation and Calpine Thermal Power, Inc., and amendment thereto dated July 28, 1994.(b) 10.2.3 -- Share Purchase Agreement dated March 30, 1995 between Calpine Corporation, Calpine Greenleaf Corporation, Radnor Power Corp. and LFC Financial Corp.(e) 10.2.4 -- Asset Purchase Agreement, dated as of August 28, 1996, among Gilroy Energy Company, McCormick & Company, Incorporated and Calpine Gilroy Cogen, L.P.(m) 10.2.5 -- Noncompetition/Earnings Contingency Agreement, dated as of August 28, 1996, among Gilroy Energy Company, McCormick & Company, Incorporated and Calpine Gilroy Cogen, L.P.(m) 10.3 -- Power Sales Agreements 10.3.1 -- Long-Term Energy and Capacity Power Purchase Agreement relating to the Bear Canyon Facility, dated November 30, 1984, between Pacific Gas & Electric and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), Amendment dated October 17, 1985, Second Amendment dated October 19, 1988, and related documents.(a) 10.3.2 -- Long-Term Energy and Capacity Power Purchase Agreement relating to the Bear Canyon Facility, dated November 29, 1984, between Pacific Gas & Electric and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), and Modification dated November 29, 1984, Amendment dated October 17, 1985, Second Amendment dated October 19, 1988, and related documents.(a) 10.3.3 -- Long-Term Energy and Capacity Power Purchase Agreement relating to the West Ford Flat Facility, dated November 13, 1984, between Pacific Gas & Electric and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), and Amendments dated May 18, 1987, June 22, 1987, July 3, 1987 and January 21, 1988, and related documents.(a) 10.3.4 -- Agreement for Firm Power Purchase, dated as of February 24, 1989, between Puget Sound Power & Light Company and Sumas Energy, Inc. and Amendment thereto dated September 30, 1991.(a)
46 49
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.3.5 -- Long-Term Energy and Capacity Power Purchase Agreement, dated April 16, 1985, between O.L.S. Energy-Agnews and Pacific Gas & Electric Company and amendment thereto dated February 24, 1989.(a) 10.3.6 -- Long-Term Energy and Capacity Power Purchase Agreement, dated November 15, 1984, between Geothermal Energy Partners, Ltd. and Pacific Gas & Electric Company, and related documents.(a) 10.3.7 -- Long-Term Energy and Capacity Power Purchase Agreement, dated November 15, 1984, between Geothermal Energy Partners, Ltd. and Pacific Gas & Electric Company (see Exhibit 10.3.6 for related documents).(a) 10.3.8 -- Long-Term Energy and Capacity Power Purchase Agreement, dated December 12, 1984, between Greenleaf Unit One Associates, Inc. and Pacific Gas and Electric Company.(f) 10.3.9 -- Long-Term Energy and Capacity Power Purchase Agreement, dated December 12, 1984, between Greenleaf Unit Two Associates, Inc. and Pacific Gas and Electric Company.(f) 10.3.10 -- Long-Term Energy and Capacity Power Purchase Agreement, dated December 5, 1985, between Calpine Gilroy Cogen, L.P. and Pacific Gas and Electric Company, and Amendments thereto dated December 19, 1993, July 18, 1985, June 9, 1986, August 18, 1988 and June 9, 1991.(l) 10.3.11 -- Amended and Restated Energy Sales Agreement, dated December 16, 1996, between Phillips Petroleum Company and Pasadena Cogeneration, L.P.(n) 10.4 -- Steam Sales Agreements 10.4.1 -- Geothermal Steam Sales Agreement, dated July 19, 1979, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), and Sacramento Municipal Utility District, and related documents.(a) 10.4.2 -- Agreement for the Sale and Purchase of Geothermal Steam, dated March 23, 1973, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.) and Pacific Gas & Electric Company, and related letter dated May 18, 1987.(a) 10.4.3 -- Thermal Energy and Kiln Lease Agreement, dated as of January 16, 1992, between Sumas Cogeneration Company, L.P. and Socco, Inc., and Amendment thereto dated May 24, 1993.(a) 10.4.4 -- Amended and Restated Energy Service Agreement, dated as of December 1, 1990, between the State of California and O.L.S. Energy-Agnews.(a) 10.4.5 -- Agreement for the Sale of Geothermal Steam, dated as of July 28, 1992, between Thermal Power Company and Pacific Gas & Electric Company.(c) 10.4.6 -- Amendment to the Agreement for the Sale of Geothermal Steam, dated as of August 9, 1995, between Union Oil Company of California, NEC Acquisition Company, Thermal Power Company, and Pacific Gas and Electric Company.(h) 10.5 -- Service Agreements 10.5.1 -- Operation and Maintenance Agreement, dated as of April 5, 1990, between Calpine Operating Plant Services, Inc. (formerly Calpine-Geysers Plant Services, Inc.) and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.).(a) 10.5.2 -- Amended and Restated Operating and Maintenance Agreement, dated as of January 24, 1992, between Calpine Operating Plant Services, Inc. and Sumas Cogeneration Company, L.P.(a) 10.5.3 -- Amended and Restated Operation and Maintenance Agreement, dated as of December 31, 1990, between O.L.S. Energy-Agnews and Calpine Operating Plant Services, Inc. (formerly Calpine Cogen-Agnews, Inc.).(a)
47 50
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.5.4 -- Operating and Maintenance Agreement, dated as of January 1, 1995, between Calpine Corporation and Geothermal Energy Partners, Ltd.(h) 10.5.5 -- Amended and Restated Operating Agreement for the Geysers, dated as of December 31, 1993, by and between Magma-Thermal Power Project, a joint venture composed of NEC Acquisition Company and Thermal Power Company, and Union Oil Company of California.(c) 10.6 -- Gas Supply Agreements 10.6.1 -- Gas Sale and Purchase Agreement, dated as of December 23, 1991, between ENCO Gas, Ltd. and Sumas Cogeneration Company, L.P.(a) 10.6.2 -- Gas Management Agreement, dated as of December 23, 1991, between Canadian Hydrocarbons Marketing Inc., ENCO Gas, Ltd. and Sumas Cogeneration Company, L.P.(a) 10.6.4 -- Natural Gas Sales Agreement, dated as of November 1, 1993, between O.L.S. Energy-Agnews, Inc. and Amoco Energy Trading Corporation.(a) 10.6.5 -- Natural Gas Service Agreement, dated November 1, 1993, between Pacific Gas & Electric Company and O.L.S. Energy-Agnews, Inc.(a) 10.7 -- Agreements Regarding Real Property 10.7.1 -- Office Lease, dated March 15, 1991, between 50 West San Fernando Associates, L.P. and Calpine Corporation.(a) 10.7.2 -- First Amendment to Office Lease, dated April 30, 1992, between 50 West San Fernando Associates, L.P. and Calpine Corporation.(a) 10.7.3 -- Geothermal Resources Lease CA 1862, dated July 25, 1974, between the United States Bureau of Land Management and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.).(a) 10.7.4 -- Geothermal Resources Lease PRC 5206.2, dated December 14, 1976, between the State of California and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.).(a) 10.7.5 -- First Amendment to Geothermal Resources Lease PRC 5206.2, dated April 20,1994, between the State of California and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.).(a) 10.7.6 -- Industrial Park Lease Agreement, dated December 18, 1990, between Port of Bellingham and Sumas Energy, Inc.(a) 10.7.7 -- First Amendment to Industrial Park Lease Agreement, dated as of July 16, 1991, between Port of Bellingham, Sumas Energy, Inc., and Sumas Cogeneration Company, L.P.(a) 10.7.8 -- Second Amendment to Industrial Park Lease Agreement, dated as of December 17, 1991, between Port of Bellingham and Sumas Cogeneration Company, L.P.(a) 10.7.9 -- Amended and Restated Cogeneration Lease, dated as of December 1, 1990, between the State of California and O.L.S. Energy-Agnews.(a) 10.8 -- General 10.8.1 -- Limited Partnership Agreement of Sumas Cogeneration Company, L.P., dated as of August 28, 1991, between Sumas Energy, Inc. and Whatcom Cogeneration Partners, L.P.(a) 10.8.2 -- First Amendment to Limited Partnership Agreement of Sumas Cogeneration Company, L.P., dated as of January 30, 1992, between Whatcom Cogeneration Partners, L.P. and Sumas Energy, Inc.(a)
48 51
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.8.3 -- Second Amendment to Limited Partnership Agreement of Sumas Cogeneration Company, L.P., dated as of May 24, 1993, between Whatcom Cogeneration Partners, L.P. and Sumas Energy, Inc.(a) 10.8.4 -- Second Amended and Restated Shareholders' Agreement, dated as of October 22, 1993, among GATX Capital Corporation, Calpine Agnews, Inc., JGS-Agnews, Inc., and GATX/Calpine-Agnews, Inc.(a) 10.8.5 -- Amended and Restated Reimbursement Agreement, dated October 22, 1993, between GATX Capital Corporation, Calpine Agnews, Inc., JGS-Agnews, Inc., GATX/Calpine Agnews, Inc., and O.L.S. Energy-Agnews, Inc.(a) 10.8.6 -- Amended and Restated Limited Partnership Agreement of Geothermal Energy Partners Ltd., L.P., dated as of May 19, 1989, between Western Geothermal Company, L.P., Sonoma Geothermal Company, L.P., and Cloverdale Geothermal Partners, L.P.(a) 10.8.7 -- Assignment and Security Agreement, dated as of January 10, 1990, between O.L.S.Energy-Agnews and Credit Suisse.(a) 10.8.8 -- Pledge Agreement, dated as of January 10, 1990, between GATX/Calpine-Agnews, Inc., and Credit Suisse.(a) 10.8.9 -- Equity Support Agreement, dated as of January 10, 1990, between Calpine Corporation and Credit Suisse.(a) 10.8.10 -- Assignment and Security Agreement, dated as of December 1, 1990, between O.L.S. Energy-Agnews and Meridian Trust Company of California.(a) 10.8.11 -- First Amended and Restated Limited Partner Pledge and Security Agreement, dated as of April 1, 1993, between Sonoma Geothermal Partners, L.P., Healdsburg Energy Company, L.P., Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), Freeport-McMoRan Resource Partners, L.P., and Meridian Trust Company of California.(a) 10.8.12 -- Management Services Agreement, dated January 1, 1995, between Calpine Corporation and Electrowatt Ltd.(k) 10.8.13 -- Guarantee Fee Agreement, dated January 1, 1995, between Calpine Corporation and Electrowatt Ltd.(g) 10.9.1 -- Calpine Corporation Stock Option Program and forms of agreements thereunder.(a) 10.9.2 -- Calpine Corporation 1996 Stock Incentive Plan and forms of agreements thereunder.(l) 10.9.3 -- Calpine Corporation Employee Stock Purchase Plan and forms of agreements thereunder.(l) 10.10.1 -- Amended and Restated Employment Agreement between Calpine Corporation and Mr. Peter Cartwright.(l) 10.10.2 -- Senior Vice President Employment Agreement between Calpine Corporation and Ms. Ann B. Curtis.(l) 10.10.3 -- Senior Vice President Employment Agreement between Calpine Corporation and Mr. Lynn A. Kerby.(l) 10.10.4 -- Vice President Employment Agreement between Calpine Corporation and Mr. Ron A.Walter.(l) 10.10.5 -- Vice President Employment Agreement between Calpine Corporation and Mr. Robert D.Kelly.(l) 10.10.6 -- First Amended and Restated Consulting Contract between Calpine Corporation and Mr. George J. Stathakis.(l)
49 52
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.11 -- Form of Indemnification Agreement for directors and officers. (l) 21.1 -- Subsidiaries of the Company.(m) 27.0 -- Financial Data Schedule.*
- --------------- (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 Current Report on Form 8-K dated September 9, 1994 and filed on September 26, 1994. (c) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated September 30, 1994 and filed on November 14, 1994. (d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated December 31, 1994 and filed on March 29, 1995. (e) Incorporated by reference to Registrant's Current Report on Form 8-K dated April 21, 1995 and filed on May 5, 1995. (f) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated March 31, 1995 and filed on May 12, 1995. (g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated June 30, 1995 and filed on August 14, 1995. (h) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated September 30, 1995 and filed on November 14, 1995. (i) Incorporated by reference to Registrant's Annual Report on Form 10-K dated December 31, 1995 and filed on March 29, 1996. (j) Incorporated by reference to Registrant's Current Report on Form 8-K dated May 1, 1996 and filed on May 14, 1996. (k) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated March 31, 1996 and filed on May 15, 1996. (l) Incorporated by reference to Registrant's Registration Statement on Form S-1 (Registration Statement No. 333-07497). (m) Incorporated by reference to Registrant's Current Report on Form 8-K dated August 29, 1996 and filed on September 13, 1996. (n) Incorporated by reference to Registrant's Annual Report on Form 10-K dated December 31, 1996, filed on March 27, 1996. * Filed herewith. (B) REPORTS ON FORM 8-K No reports on Form 8-K were filed during the period from October 1, 1997 to December 31, 1997. 50 53 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: March 6, 1998 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.
SIGNATURE TITLE DATE --------- ----- ---- /s/ PETER CARTWRIGHT President, Chief Executive March 6, 1998 - -------------------------------------- Officer and Chairman of the Board Peter Cartwright (Principal Executive Officer) /s/ ANN B. CURTIS Senior Vice President and March 6, 1998 - -------------------------------------- Director (Principal Financial Officer) Ann B. Curtis /s/ JEFFREY E. GARTEN Director March 6, 1998 - -------------------------------------- Jeffrey E. Garten /s/ SUSAN C. SCHWAB Director March 6, 1998 - -------------------------------------- Susan C. Schwab /s/ GEORGE J. STATHAKIS Director March 6, 1998 - -------------------------------------- George J. Stathakis /s/ JOHN O. WILSON Director March 6, 1998 - -------------------------------------- John O. Wilson /s/ ORVILLE WRIGHT Director March 6, 1998 - -------------------------------------- V. Orville Wright /s/ GLORIA S. GEE Controller (Principal Accounting March 6, 1998 - -------------------------------------- Officer) Gloria S. Gee
51 54 CALPINE CORPORATION AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND OTHER INFORMATION DECEMBER 31, 1997
PAGE ---- CALPINE CORPORATION AND SUBSIDIARIES Selected Consolidated Financial Data........................ F-2 Management's Discussion and Analysis of Financial Condition and Results of Operations................................. F-4 Report of Independent Public Accountants.................... F-13 Consolidated Balance Sheets December 31, 1997 and 1996...... F-14 Consolidated Statements of Operations for the Years Ended December 31, 1997, 1996 and 1995.......................... F-15 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1997, 1996 and 1995.............. F-16 Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995.......................... F-17 Notes to Consolidated Financial Statements for the Years Ended December 31, 1997, 1996 and 1995.................... F-18 CALPINE CORPORATION Report of Independent Public Accountants.................... F-43 Schedule I: Condensed Financial Information of Registrant Balance Sheets, December 31, 1997 and 1996................ F-44 Condensed Statements of Operations for the Years Ended December 31, 1997, 1996 and 1995....................... F-45 Condensed Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995....................... F-46 Notes to Condensed Financial Statements for December 31, 1997...................................... F-47 Schedule II: Valuation and Qualifying Accounts.............. F-52 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY Independent Auditor's Report................................ F-53 Consolidated Balance Sheets, December 31, 1997 and 1996..... F-54 Consolidated Statement of Income for the Years Ended December 31, 1997, 1996 and 1995.......................... F-55 Consolidated Statement of Changes in Partners' Equity for the Years Ended December 31, 1997, 1996 and 1995.......................... F-56 Consolidated Statement of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995.......................... F-57 Notes to Consolidated Financial Statements for the Year Ended December 31, 1997................................... F-58
F-1 55 CALPINE CORPORATION AND SUBSIDIARIES SELECTED CONSOLIDATED FINANCIAL DATA (IN THOUSANDS, EXCEPT RATIO DATA)
YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1993 1994 1995 1996 1997 ---------- ---------- ---------- ---------- ---------- STATEMENT OF OPERATIONS DATA: Revenue: Electricity and steam sales................. $ 53,000 $ 90,295 $ 127,799 $ 199,464 $ 237,277 Service contract revenue from related parties.................................. 16,896 7,221 7,153 6,455 10,177 Income (loss) from unconsolidated investments in power projects............ 19 (2,754) (2,854) 6,537 15,819 Interest income on loans to power projects................................. -- -- -- 2,098 13,048 ---------- ---------- ---------- ---------- ---------- Total revenue....................... 69,915 94,762 132,098 214,554 276,321 Cost of revenue............................... 42,501 52,845 77,388 129,200 153,308 ---------- ---------- ---------- ---------- ---------- Gross profit.................................. 27,414 41,917 54,710 85,354 123,013 Project development expenses.................. 1,280 1,784 3,087 3,867 7,537 General and administrative expenses........... 5,080 7,323 8,937 14,696 18,289 Provision for write-off of project development costs....................................... -- 1,038 -- -- -- ---------- ---------- ---------- ---------- ---------- Income from operations...................... 21,054 31,772 42,686 66,791 97,187 Interest expense.............................. 13,825 23,886 32,154 45,294 61,466 Interest income............................... (693) (1,058) (1,555) (8,604) (14,285) Other (income) expense........................ (440) (930) (340) 2,345 (3,153) ---------- ---------- ---------- ---------- ---------- Income before provision for income taxes and cumulative effect of change in accounting principle................................ 8,362 9,874 12,427 27,756 53,159 Provision for income taxes.................... 4,195 3,853 5,049 9,064 18,460 ---------- ---------- ---------- ---------- ---------- Income before cumulative effect of change in accounting principle..................... 4,167 6,021 7,378 18,692 34,699 Cumulative effect of adoption of SFAS No. 109......................................... (413) -- -- -- -- ---------- ---------- ---------- ---------- ---------- Net income.................................. $ 3,754 $ 6,021 $ 7,378 $ 18,692 $ 34,699 ========== ========== ========== ========== ========== Basic earnings per common share(1) Weighted average shares of common stock outstanding.............................. 10,388 10,388 10,388 12,903 19,946 Basic earnings per common share............. $ 0.36 $ 0.58 $ 0.71 $ 1.45 $ 1.74 Diluted earnings per common share(1).......... Weighted average shares of common stock outstanding.............................. 10,879 10,921 10,957 14,879 21,016 Diluted earnings per common share........... $ 0.35 $ 0.55 $ 0.67 $ 1.26 $ 1.65 OTHER FINANCIAL DATA AND RATIOS: Depreciation and amortization................. $ 12,540 $ 21,580 $ 26,896 $ 40,551 $ 48,935 EBITDA(2)..................................... $ 42,370 $ 53,707 $ 69,515 $ 117,379 $ 172,616 EBITDA to Consolidated Interest Expense(3).... 2.98x 2.23x 2.11x 2.41x 2.60x Total debt to EBITDA.......................... 6.24x 6.23x 5.87x 5.12x 4.96x Ratio of earnings to fixed charges(4)......... 2.09x 1.52x 1.46x 1.45x 1.64x
AS OF DECEMBER 31, -------------------------------------------------------------- 1993 1994 1995 1996 1997 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) BALANCE SHEET Cash and cash equivalents..................... $ 6,166 $ 22,527 $ 21,810 $ 95,970 $ 48,513 Property, plant and equipment, net............ 251,070 335,453 447,751 648,208 719,721 Total assets.................................. 302,256 421,372 554,531 1,031,397 1,380,956 Total liabilities............................. 288,827 402,723 529,304 828,270 1,141,000 Total stockholders' equity.................... 13,429 18,649 25,227 203,127 239,956
(The information contained in the Selected Consolidated Financial Data is derived from the audited consolidated financial statements of Calpine Corporation and Subsidiaries.) (See footnotes on next page) F-2 56 - --------------- (1) In 1997, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings per Share," and subsequently, in February 1998, Staff Accounting Bulletin ("SAB") No. 98 on Computations of Earnings per Share. In accordance with SFAS No. 128, basic earnings per common share for all periods was computed by dividing net income by the weighted average shares of common stock outstanding during the year. Diluted earnings per common share for all periods was also computed in conformance with SFAS No. 128 by dividing net income by the weighted average shares of common stock outstanding during the year and the additional number of shares that would have been outstanding during the year if the Company's dilutive potential shares had been issued. The treasury stock method was used to calculate the potential number of dilutive shares associated with the Company's outstanding stock options (see Note 2 of Notes to Consolidated Financial Statements). (2) 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 the Company's 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). (3) 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 capital stock of the Company. (4) Earnings are defined as income before provision for taxes, extraordinary item 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. F-3 57 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 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) 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 the Company's 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 Company's stock price, (xvii) fluctuations in quarterly results and seasonality, and (xviii) other risks identified from time to time in the Company's reports and registration statements filed with the Securities and Exchange Commission. GENERAL Calpine Corporation ("Calpine") a Delaware corporation, and subsidiaries (collectively, the "Company") is engaged in the acquisition, development, ownership and operation of power generation facilities and the sale of electricity and steam principally in the United States. The Company currently has interests in 23 power plants and steam fields, having an aggregate capacity of 2,613 megawatts. The Company currently sells electricity and steam to 16 utility and other customers, principally under long term power and steam sales agreements, generated by power generation facilities located in six states and Mexico. In addition, the Company has a 240 megawatt gas-fired power plant currently under construction in Pasadena, Texas and an investment in a 169 megawatt gas-fired power plant currently under construction in Dighton, Massachusetts. Since its inception in 1984, the Company has developed substantial expertise in all aspects of electric power generation. The Company's vertical integration has resulted in significant growth in recent years as the Company has applied its extensive engineering, construction management, operations, fuel management and financing capabilities to successfully implement its acquisition and development program. The Company's strategy is to capitalize on opportunities in the power market through an ongoing program to acquire, develop, own and operate electric power generation facilities, as well as marketing power and energy services to utilities and other end users. The Company's net interest in power generation facilities has increased from 297 megawatts in 1992 to 1981 megawatts at December 31, 1997, including the power plants currently under construction. Total assets have increased from $55.4 million as of December 31, 1992 to $1.4 billion as of December 31, 1997. The Company's revenue has increased to $276.3 million for 1997, representing a 5-year compound annual growth rate of 48% since 1992. The Company's EBITDA (see Selected Consolidated Financial Data) for 1997 increased to $172.6 million from $9.9 million in 1992, representing a 5-year compound annual growth rate of 77%. In January 1995, the Company purchased the working interest in certain of the geothermal properties at the Pacific Gas & Electric Company ("PG&E") Unit 13 and Unit 16 Steam Fields from a third party for a purchase price of $6.75 million. On April 21, 1995, the Company acquired the stock of certain companies that own 100% of the Greenleaf 1 and 2 Power Plants, consisting of two 49.5 megawatt gas-fired cogeneration facilities, for an adjusted purchase price of $81.5 million. On June 29, 1995, the Company acquired the operating lease for the Watsonville Power Plant, a 28.5 megawatt gas-fired cogeneration facility, for a F-4 58 purchase price of $900,000. On November 17, 1995, the Company entered into a series of agreements to invest up to $20.0 million in the Cerro Prieto Steam Fields. In April 1996, the Company entered into a lease transaction for the King City Power Plant, a 120 megawatt gas-fired cogeneration facility, which required an investment of $108.3 million, primarily related to the collateral fund requirements. On August 29, 1996, the Company acquired the Gilroy Power Plant, a 120 megawatt gas-fired cogeneration facility, for a purchase price of $125.0 million plus certain contingent consideration, which the Company currently estimates will amount to approximately $24.1 million, of which $12.5 million has been paid as of December 31, 1997. On January 31, 1997, the Company paid approximately $7.1 million to acquire the stock of Montis Niger, Inc. (subsequently renamed Calpine Gas Company). Calpine Gas Company has 8.1 billion cubic feet of estimated proven gas reserves and an 80-mile pipeline system which provide gas to the Company's Greenleaf 1 and 2 Power Plants. In February 1997, the Company commenced construction of the Pasadena Power Plant, a 240 megawatt gas-fired cogeneration facility at the Phillips Houston Chemical Complex ("HCC") located in Pasadena, Texas. The Company has entered into an agreement to supply HCC with approximately 90 megawatts of electricity (see Note 3 of Notes to Consolidated Financial Statements), with the remainder of available electricity output to be sold into the competitive market. The Pasadena Power Plant is the first merchant power plant to be financed with non-recourse project financing and is scheduled to be operational in July 1998. On June 23, 1997, the Company completed the acquisition of a 50% equity interest in two gas-fired cogeneration facilities, the 450 megawatt Texas City Power Plant and the 377 megawatt Clear Lake Power Plant, for an aggregate purchase price of $35.4 million. As a part of that acquisition, the Company entered into a $125.0 million non-recourse project financing agreement with The Bank of Nova Scotia, the proceeds of which were utilized for the acquisition of the 50% equity interest and the purchase of $155.6 million of outstanding non-recourse project financing associated with the Texas City and Clear Lake Power Plants. On October 9, 1997, the Company completed the acquisition of 50% interests in the Gordonsville Power Plant, a 240 megawatt gas-fired cogeneration facility located in Gordonsville, Virginia, and the Auburndale Power Plant, a 150 megawatt gas-fired cogeneration facility located in Auburndale, Florida, for an aggregate purchase price of $42.4 million. On October 10, 1997, the Company entered into agreements with Energy Management Inc. to invest in the development of two merchant power plants, including the 169 megawatt gas-fired combined-cycle Dighton Power Plant to be located in Dighton, Massachusetts, and the 265 megawatt gas-fired combined-cycle Tiverton Power Plant to be located in Tiverton, Rhode Island. In October 1997, the Company invested $16.0 million in the Dighton Power Plant (see Note 3 of Notes to Consolidated Financial Statements). The Company intends to invest up to $42.0 million of equity in the development of the Tiverton Power Plant. There can be no assurances that the Dighton or Tiverton Power Plants will be successfully developed. On December 19, 1997, the Company completed the acquisition of 100% of the capital stock of Gas Energy, Inc. ("GEI") and Gas Energy Cogeneration Inc. ("GECI") from The Brooklyn Union Gas Company for an aggregate purchase price of $100.9 million, subject to final adjustments. GEI and GECI indirectly own (i) a 50% general partnership interest in the Kennedy International Airport Power Plant, a 107 megawatt gas-fired cogeneration facility located at the John F. Kennedy International Airport in Queens, New York, (ii) a 50% general partnership interest in the Stony Brook Power Plant, a 40 megawatt gas-fired cogeneration facility located on the campus of the State University of New York in Stony Brook, New York, (iii) a 45% general partnership interest in the Bethpage Power Plant, a 57 megawatt gas-fired cogeneration facility located in Bethpage, New York, (iv) an 11.36% limited partnership interest in the Lockport Power Plant, a 184 megawatt gas-fired cogeneration facility located in Lockport, New York, and (v) a 100% interest in three fuel management contracts. On February 5, 1998, the Company acquired the remaining 55% interest in, and assumed operations and maintenance of, the Bethpage Power Plant. The Company purchased the remaining interests for approximately $4.6 million. F-5 59 On February 18, 1998, the Company announced that it had entered into exclusive negotiations to acquire a 70 megawatt gas-fired power plant and natural gas pipeline system from The Dow Chemical Company located in Pittsburg, California. There can be no assurance that the Company will successfully complete this acquisition. Each of the Company's power plants produces electricity for sale to a utility or other third party purchasers. Thermal energy produced by the gas-fired cogeneration facilities is sold to governmental and industrial users, and steam produced by the geothermal steam fields is sold to utility-owned power plants. The electricity, thermal energy and steam generated by these facilities are typically sold pursuant to long-term, take-and-pay power or steam sales agreements, generally having original terms of 20 or 30 years. PG&E pays a fixed price for each unit of electrical energy according to schedules set forth in the long-term power sales agreements for Bear Canyon (20 megawatts) and West Ford Flat (27 megawatts) Power Plants. The fixed price periods under these power sales agreements expire in September and December 1998, respectively. After the fixed price periods expire, while the basis for the capacity and capacity bonus payments under these power sales agreements remains the same, the energy payments adjust to interim short-run avoided cost ("SRAC"), which is calculated pursuant to the methodology approved by the California Public Utilities Commission ("CPUC") on December 9, 1996, and will continue at SRAC until the independent power exchange has commenced operations and is functioning properly. The independent power exchange is currently scheduled to commence operations on April 1, 1998. Thereafter, SRAC will eventually become the energy-clearing price of the independent power exchange. During 1997, SRAC averaged approximately 2.94c per kilowatt-hour. As a result, while SRAC does not affect capacity payments under the power sales agreements, the Company's energy revenue under these power sales agreements is expected to be materially reduced at the expiration of the fixed price period. Such reduction may have a material adverse effect on the Company's results of operations. The Company expects the forecasted decline in energy revenues will be mitigated by decreased royalty expenses and planned operating cost reductions at the facilities. The Company expects to continue its strategy of replacing decreased revenues through its acquisition and development program. In addition, prices paid for the steam delivered by the Company's steam fields are based on a formula that partially reflects the price levels of nuclear and fossil fuels, and, therefore, a reduction in the price levels of such fuels may reduce revenue under the steam sales agreements for the steam fields. Certain of the Company's power and steam sales agreements contain curtailment provisions under which the purchasers of energy or steam are entitled to reduce the number of hours of energy or amount of steam purchased thereunder. For the year ended December 31, 1996, certain of the Company's power generation facilities experienced maximum curtailment primarily as a result of low gas prices and a high degree of precipitation during the period, which resulted in high levels of energy generation by hydroelectric power plants that supply electricity. For the year ended December 31, 1997, such plants experienced a reduced amount of curtailment compared to the same period in 1996. Due to an amendment to certain of the power sales agreements executed in May 1997, the Company currently does not expect curtailment during the remainder of the terms of the power sales agreements for these power plants. Many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry. In December 1995, the CPUC issued an electric industry restructuring decision, which envisioned commencement of deregulation and implementation of customer choice of electricity supplier by January 1, 1998. Legislation implementing this decision was adopted in September 1996. The CPUC subsequently extended the implementation date to April 1, 1998. As part of its policy decision, the CPUC indicated that power sales agreements of existing qualifying facilities would be honored. The Company cannot predict the final form or timing of the proposed restructuring and the impact, if any, that such restructuring would have on the Company's existing business or results of operations. The Company believes that any such restructuring would not have a material effect on its power sales agreements and, accordingly, believes that its existing business and results of operations would not be materially adversely affected, although there can be no assurance in this regard. F-6 60 SELECTED OPERATING INFORMATION Set forth below is certain selected operating information for the power plants and steam fields, for which results are consolidated in the Company's Consolidated Statements of Operations. The information set forth under power plants consists of the results for the West Ford Flat Power Plant, the Bear Canyon Power Plant, the Greenleaf 1 and 2 Power Plants since their acquisitions on April 21, 1995, the Watsonville Power Plant since the acquisition of the lease on June 29, 1995, the King City Power Plant since the effective date of the lease on May 2, 1996, and the Gilroy Power Plant since its acquisition on August 29, 1996. 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, for 1994 through 1997, the Thermal Power Company Steam Fields since the acquisition of Thermal Power Company ("TPC") on September 9, 1994. The information provided for the other interest included under steam revenue prior to 1995 represents revenue attributable to a working interest that was held by a third party in the PG&E Unit 13 and Unit 16 Steam Fields. In January 1995, the Company purchased this working interest. Prior to the Company's acquisition of the remaining interest in the Bear Canyon and West Ford Flat Power Plants, the PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields on April 19, 1993, the Company's revenue from these facilities was accounted for under the equity method and, therefore, does not represent the actual revenue of the Company from these facilities for the periods set forth below.
YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1993 1994 1995 1996 1997 ---------- ---------- ---------- ---------- ---------- (DOLLARS IN THOUSANDS) POWER PLANTS: Electricity revenue (1): Energy..................... $ 37,088 $ 45,912 $ 54,886 $ 93,851 $ 110,879 Capacity................... $ 7,834 $ 7,967 $ 30,485 $ 65,064 $ 84,296 Megawatt hours produced.... 378,035 447,177 1,033,566 1,985,404 2,158,008 Average energy price per kilowatt hour(2)........ 9.811c 10.267c 5.310c 4.727c 5.138c STEAM FIELDS: Steam revenue: Calpine.................... $ 31,066 $ 32,631 $ 39,669 $ 40,549 $ 42,102 Other interest............. $ 2,143 $ 2,051 $ -- $ -- $ -- Megawatt hours produced.... 2,014,758 2,156,492 2,415,059 2,528,874 2,641,422 Average price per kilowatt hour.................... 1.648c 1.608c 1.643c 1.603c 1.594c
- --------------- (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 reflects the increase in the Company's megawatt hour production as a result of acquisitions of gas-fired power plants by the Company. RESULTS OF OPERATIONS 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 F-7 61 additional $4.2 million in revenues in 1997 as compared to 1996. In addition, 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 the Company's 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 the Company's June 1997 investment in the Texas City and Clear Lake Power Plants (see Note 3 of Notes to Consolidated Financial Statements), and an increase in equity income of $2.2 million from the Company's investment in Sumas Cogeneration Company, L.P. ("Sumas") (see Note 5 of Notes to Consolidated Financial Statements). 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 the Company's 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 the 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., the Company's partner in Sumas (see Note 6 of Notes to Consolidated Financial Statements). 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 the Company's 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: (i) $10.8 million of interest expense related to the 8 3/4% Senior Notes Due 2007 issued in July and September 1997, (ii) a $7.3 million increase in interest expense related to the 10 1/2% Senior Notes Due 2006 issued May 1996, (iii) a $6.4 million increase in interest expense on debt related to the Gilroy Power Plant acquired in August 1996 and (iv) $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, L.P. ("CGC") 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, the Company recorded a $1.1 million gain on the sale of a note receivable (see Note 6 of Notes to Consolidated Financial Statements) and received a refund of $961,000 from PG&E. In 1996, the Company 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 reductions from the statutory tax rate were primarily due to depletion in excess of F-8 62 tax basis benefits at the Company's geothermal facilities, a decrease in the California taxes paid due to the Company's expansion into states other than California, and a revision of prior years' tax estimates. YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995 Revenue -- Total revenue increased 62% to $214.6 million in 1996 compared to $132.1 million in 1995. Electricity and steam sales revenue increased 56% to $199.5 million in 1996 compared to $127.8 million in 1995. The King City and Gilroy Power Plants contributed revenues of $41.5 million and $14.7 million, respectively, to electricity and steam revenues during 1996. Revenue for 1996 also reflected a full year of operation at the Greenleaf 1 and 2 Power Plants and the Watsonville Power Plant, which contributed to increases in electricity and steam revenues in 1996 compared to 1995 of $9.1 million and $4.7 million, respectively. During 1996 and 1995, the Company experienced the maximum curtailment allowed under the power sales agreements with PG&E for the Bear Canyon and West Ford Flat Power Plants. Without such curtailment, the Bear Canyon and West Ford Flat Power Plants would have generated an additional $5.2 million and $5.7 million of revenue in 1996 and 1995, respectively. Service contract revenue decreased to $6.5 million in 1996 compared to $7.2 million in 1995, reflecting a $2.8 million loss related to the Company's electricity trading operations, offset by increased revenue during 1996 related to overhauls at the Aidlin and Agnews Power Plants, and to technical services performed for the Cerro Prieto project. Income from unconsolidated investments in power projects increased to $6.5 million in 1996 compared to losses of $2.9 million during 1995. The increase is primarily attributable to $6.4 million of equity income generated by the Company's investment in Sumas during 1996 compared to a $3.0 million loss in 1995. The increase in Sumas' profitability during 1996 is primarily attributable to a contractual increase in the energy price in accordance with the power sales agreement with Puget Sound Power & Light Company. Interest income on loans to power projects was $2.1 million in 1996 as a result of the recognition of interest income on loans to the sole shareholder of the general partner in Sumas. Cost of revenue -- Cost of revenue increased 67% to $129.2 million in 1996 as compared to $77.4 million in 1995. The increase was primarily due to plant operating, depreciation, and operating lease expenses attributable to: (i) a full year of operation during 1996 at the Greenleaf 1 and 2 Power Plants, which were purchased on April 21, 1995, (ii) a full year of operation during 1996 at the Watsonville Power Plant, for which the Company acquired the operating lease on June 29, 1995, (iii) operations at the King City Power Plant subsequent to May 2, 1996, and (iv) operations at the Gilroy Power Plant subsequent to acquisition on August 29, 1996. Cost of revenue also increased due to service contract expenses related to the Cerro Prieto Steam Fields, partially offset by lower operating expenses at the Company's other existing power generation facilities and steam fields. Project development expenses -- Project development expenses increased to $3.9 million in 1996 compared to $3.1 million in 1995, due to project development activities. General and administrative expenses -- General and administrative expenses were $14.7 million in 1996 compared to $8.9 million in 1995. The increases were primarily due to additional personnel and related expenses necessary to support the Company's expanding operations, including the Company's power marketing operations. The Company also incurred an employee bonus expense of $1.4 million in September 1996 related to the initial public offering. Interest expense -- Interest expense increased 41% to $45.3 million in 1996 from $32.2 million in 1995. Approximately $11.8 million of the increase was attributable to interest on the Company's 10 1/2% Senior Notes Due 2006 issued in May 1996, $2.7 million of interest expense related to the Gilroy Power Plant acquired on August 29, 1996, and $1.6 million of higher interest expense related to the Greenleaf 1 and 2 Power Plants acquired on April 21, 1995, offset in part by a $3.0 million decrease in interest expense as a result of repayments of principal on certain non-recourse project financing. Interest income -- Interest income increased to $8.6 million for 1996 compared with $1.6 million for 1995. The increase was primarily due to $4.5 million of interest income on collateral securities purchased in connection with the acquisition of the King City operating lease, and higher interest income for the period due to increased cash balances as a result of sales of equity and debt securities. F-9 63 Other income, net -- Other income, net decreased to $2.3 million of expense for 1996 compared with $340,000 of income for 1995. The decrease was primarily due to a $3.7 million loss for a dispute related to uncollectible amounts from an acquisition project offset by $1.4 million in net proceeds from a development project settlement. Provision for income taxes -- The effective rate for the income tax provision was approximately 33% in 1996 and 41% in 1995. In 1996, the Company decreased its deferred income tax liability by $769,000 to reflect the change in California's state income tax rate from 9.3% to 8.8% effective January 1, 1997. In addition, depletion in excess of tax basis benefits at the Company's geothermal facilities and a revision of prior years' tax estimates reduced the Company's effective tax rate for 1996. LIQUIDITY AND CAPITAL RESOURCES To date, the Company has obtained cash from its operations, borrowings under its credit facilities and other working capital lines, sale of debt and equity, and proceeds from non-recourse project financing. The Company utilized this cash to fund its operations, service debt obligations, fund the acquisition, development and construction of power generation facilities, finance capital expenditures and meet its other cash and liquidity needs. The following table summarizes the Company's cash flow activities for the periods indicated:
YEAR ENDED DECEMBER 31, ----------------------------------- 1995 1996 1997 --------- --------- --------- (IN THOUSANDS) Cash flows from: Operating activities.......... $ 26,346 $ 59,944 $ 108,461 Investing activities.......... (38,190) (330,937) (402,158) Financing activities.......... 11,127 345,153 246,240 --------- --------- --------- Total................. $ (717) $ 74,160 $ (47,457) ========= ========= =========
Operating activities in 1997 provided $108.5 million, consisting of approximately $34.7 million of net income from operations, $46.8 million of depreciation and amortization, $15.1 million of deferred income taxes, $23.0 million of distributions (see Note 5 of Notes to Consolidated Financial Statements), and a $4.7 million net decrease in operating assets and liabilities, offset by $15.8 million of income from unconsolidated investments in power projects. Investing activities used $402.2 million during 1997, primarily due to $191.0 million for the acquisition of interests in the Texas City and Clear Lake Power Plants and the related notes receivable, $100.9 million for the acquisition of the capital stock of GEI and GECI, $42.4 million for the acquisition of interests in the Auburndale and Gordonsville Power Plants, $16.0 million for the investment in the Dighton Power Plant, $77.6 million of capital expenditures related to the construction of the Pasadena Power Plant, $29.5 million of other capital expenditures, $6.2 million of interest capitalized on construction projects, $6.0 million of capitalized project development costs, offset by $200,000 of deferred project costs, $7.2 million of additional investment in the Clear Lake Power Plant, $7.1 million for the acquisition of Calpine Gas Company, offset by the receipt of $23.1 million of loan payments, $10.0 million from the sale of loans (see Note 6 of Notes to Consolidated Financial Statements), $5.4 million of maturities of collateral securities in connection with the King City Power Plant and a $43.7 million decrease in restricted cash, primarily related to the Pasadena Power Plant and CGC. Financing activities provided $246.2 million of cash during 1997 consisting of $125.0 million of borrowings for the acquisition of the interests in the Texas City and Clear Lake Power Plants and the related notes receivable, $6.6 million of borrowings for contingent consideration in connection with the acquisition of the Gilroy Power Plant and $275.0 million of proceeds from the issuance of the 8 3/4% Senior Notes Due 2007, offset by $144.5 million in repayment of non-recourse project financing, $7.1 million in repayment of notes payable and $9.7 million of costs associated with financing activities. F-10 64 At December 31, 1997, cash and cash equivalents were $48.5 million and negative working capital was $12.0 million. For the twelve months ended December 31, 1997, cash and cash equivalents decreased by $47.5 million and working capital decreased by $102.7 million as compared to December 31, 1996. As a developer, owner and operator of power generation facilities, the Company may be required to make long-term commitments and investments of substantial capital for its projects. The Company historically has financed these capital requirements with borrowings under its credit facilities, other lines of credit, non-recourse project financing or long-term debt. At December 31, 1997, the Company had $105.0 million of outstanding 9 1/4% Senior Notes Due 2004, which mature on February 1, 2004 and bear interest payable semi-annually on February 1 and August 1 of each year. In addition, the Company had $180.0 million of outstanding 10 1/2% Senior Notes Due 2006, which mature on May 15, 2006 and bear interest payable semi-annually on May 15 and November 15 of each year. During 1997, the Company issued $275.0 million of 8 3/4% Senior Notes Due 2007, which mature on July 15, 2007 and bear interest payable semi-annually on January 15 and July 15 of each year. Under the provisions of the applicable indentures, the Company may, under certain circumstances, be limited in its ability to make restricted payments, as defined, which includes dividends and certain purchases and investments, incur additional indebtedness and engage in certain transactions. At December 31, 1997, the Company had $192.5 million of non-recourse project financing associated with the Greenleaf 1 and 2 Power Plants and the Gilroy Power Plant. The annual maturities for such non-recourse project financing are $9.6 million for 1998, $8.7 million for 1999, $10.4 million for 2000, $10.6 million for 2001, $11.1 million for 2002 and $142.1 million thereafter. At December 31, 1997, the Company had $103.4 million of non-recourse borrowings from The Bank of Nova Scotia in connection with the acquisition of the notes receivable from the Texas City and Clear Lake Power Plants. Such borrowings mature on June 22, 1998. The Company expects to refinance such borrowings before the maturity date. The Company currently has a $50.0 million revolving credit agreement with a consortium of commercial lending institutions led by The Bank of Nova Scotia, with borrowings bearing interest at either the London Inter Bank Offering Rate or at The Bank of Nova Scotia base rate, plus a mutually agreed margin. At December 31, 1997, the Company had no borrowings outstanding and $9.4 million of letters of credit outstanding under the revolving credit facility (see Note 7 of Notes to Consolidated Financial Statements). The Bank of Nova Scotia credit facility contains certain restrictions that limit or prohibit, among other things, the ability of the Company 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. The Company has a $1.2 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, 1997, the Company had no borrowings under this working capital line and $74,000 of letters of credit outstanding. Borrowings are at prime plus 1%. Where appropriate, the Company may use non-recourse project financing for new projects. The debt agreements of the Company's subsidiaries and other affiliates governing the non-recourse project financing generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to the Company. The dividend restrictions in such agreements generally require that, prior to the payment of dividends, distributions or other transfers, the subsidiary or other affiliate must provide for the payment of other obligations, including operating expenses, debt service and reserves. However, the Company does not believe that such restrictions will adversely affect its ability to meet its debt obligations. At December 31, 1997, the Company had commitments for capital expenditures in 1998 totaling $19.8 million related to the Pasadena Power Plant (see Note 3 of Notes to Consolidated Financial Statements). The Company intends to fund capital expenditures for the ongoing operation and development of the Company's power generation facilities primarily through the operating cash flow of such facilities, non-recourse project financing and corporate financing. Capital expenditures for the twelve months ended F-11 65 December 31, 1997 of $107.1 million included $77.6 million for the construction of the Pasadena Power Plant, $12.1 million related to the geothermal facilities, $2.5 million related to the development of other merchant power plants and the remaining $14.9 million at certain of the Company's gas-fired power plants. The Company continues to pursue the acquisition and development of new power plants. The Company expects to commit significant capital in future years for the acquisition and development of these power plants. The Company's actual capital expenditures may vary significantly during any year. The Company believes that it 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 through December 31, 1998. NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting Comprehensive Income," which establishes standards for reporting comprehensive income and its components (revenues, expenses, gains and losses) in financial statements. SFAS No. 130 requires classification of other comprehensive income in a financial statement, and the display of the accumulated balance of other comprehensive income separately from retained earnings and additional paid-in capital. SFAS No. 130 is effective for fiscal years beginning after December 15, 1997. The Company believes this pronouncement will not have a material effect on its financial statements. In June 1997, the FASB also issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," which established standards for reporting 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, although earlier application is encouraged. The Company believes this pronouncement will not have a material effect on its financial statements. YEAR 2000 COMPLIANCE To ensure that the Company's computer systems are Year 2000 compliant, the Company has begun preparing for the Year 2000 issue. The Company has been reviewing each of its financial and operating systems to identify those that contain two-digit year codes. The Company is assessing the amount of programming required to upgrade or replace each of the affected programs with the goal of completing all relevant internal software remediation and testing by 1998, with continuing Year 2000 compliance efforts through 1999. In addition, the Company is actively working with all of its partnerships to assess their compliance efforts and the Company's exposure resulting from Year 2000 issues. Based upon current information, the Company does not anticipate costs associated with the Year 2000 issue to have a material financial impact. However, there can be no assurances that there will not be interruptions or other limitations of financial and operating systems functionality or that the Company will not incur significant costs to avoid such interruptions or limitations. The costs incurred relating to the Year 2000 issue will be expensed by the Company during the period in which they are incurred. The Company's expectations about future costs associated with the Year 2000 issue are subject to uncertainties that could cause actual results to have a greater financial impact than currently anticipated. Factors that could influence the amount and timing of future costs include the success of the Company in identifying systems and programs that contain two-digit year codes, the nature and amount of programming required to upgrade or replace each of the affected programs, the rate and magnitude of related labor and consulting costs, and the success of the Company's partnerships in addressing the Year 2000 issue. F-12 66 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, 1997 and 1996, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. 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 is reflected in the accompanying financial statements using the equity method of accounting. The investment in Sumas represents approximately 1% of the Company's total assets at December 31, 1996. There is no investment balance as of December 31, 1997. The Company has recorded income of $8.6 million and $6.4 million and losses of $3.0 million representing its share of the net income or loss of Sumas for the years ended December 31, 1997, 1996 and 1995, 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, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP San Jose, California February 10, 1998 (except for Note 16 as to which the date is February 17, 1998) F-13 67 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1997 AND 1996 (IN THOUSANDS)
1997 1996 ---------- ---------- ASSETS Current assets: Cash and cash equivalents................................. $ 48,513 $ 95,970 Accounts receivable from related parties.................. 7,672 2,826 Accounts receivable....................................... 35,133 39,962 Collateral securities, current portion.................... 6,036 5,470 Loans receivable from related parties, current portion.... 30,507 -- Prepaid operating lease................................... 13,652 12,668 Inventories............................................... 6,015 5,375 Other current assets...................................... 19,050 8,171 ---------- ---------- Total current assets.............................. 166,578 170,442 Property, plant and equipment, net.......................... 719,721 648,208 Investments in power projects............................... 239,160 13,936 Project development costs................................... 4,614 86 Collateral securities, net of current portion............... 87,134 89,806 Loans receivable from related parties, net of current portion................................................... 101,304 -- Notes receivable from related parties....................... 16,053 36,143 Restricted cash............................................. 15,584 59,259 Other assets................................................ 30,808 13,517 ---------- ---------- Total assets...................................... $1,380,956 $1,031,397 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable and short term borrowings................... -- 6,865 Current portion of non-recourse project financing......... 112,966 30,627 Accounts payable.......................................... 30,441 18,363 Accrued payroll and related expenses...................... 4,950 3,912 Accrued interest payable.................................. 18,025 7,332 Other current liabilities................................. 12,204 12,621 ---------- ---------- Total current liabilities......................... 178,586 79,720 Non-recourse project financing, net of current portion...... 182,893 278,640 Senior Notes................................................ 560,041 285,000 Deferred income taxes, net.................................. 142,050 100,385 Deferred lease incentive.................................... 71,383 74,952 Other liabilities........................................... 6,047 9,573 ---------- ---------- Total liabilities................................. 1,141,000 828,270 ---------- ---------- Stockholders' equity: Common stock, $0.001 par value per share; authorized 100,000,000 shares in 1997 and 1996; issued and outstanding 20,060,705 shares in 1997 and 19,843,400 shares in 1996......................................... 20 20 Additional paid-in capital................................ 167,542 165,412 Retained earnings......................................... 72,394 37,695 ---------- ---------- Total stockholders' equity........................ 239,956 203,127 ---------- ---------- Total liabilities and stockholders' equity........ $1,380,956 $1,031,397 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. F-14 68 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1997 1996 1995 -------- -------- -------- Revenue: Electricity and steam sales.............................. $237,277 $199,464 $127,799 Service contract revenue from related parties............ 10,177 6,455 7,153 Income (loss) from unconsolidated investments in power projects.............................................. 15,819 6,537 (2,854) Interest income on loans to power projects............... 13,048 2,098 -- -------- -------- -------- Total revenue.................................... 276,321 214,554 132,098 -------- -------- -------- Cost of revenue: Plant operating expenses................................. 72,366 61,894 33,162 Depreciation............................................. 47,501 39,818 26,264 Production royalties..................................... 10,803 10,793 10,574 Operating lease expenses................................. 14,031 9,295 1,542 Service contract expenses................................ 8,607 7,400 5,846 -------- -------- -------- Total cost of revenue............................ 153,308 129,200 77,388 -------- -------- -------- Gross profit............................................... 123,013 85,354 54,710 Project development expenses............................... 7,537 3,867 3,087 General and administrative expenses........................ 18,289 14,696 8,937 -------- -------- -------- Income from operations........................... 97,187 66,791 42,686 Interest expense: Related parties.......................................... -- 894 1,663 Other.................................................... 61,466 44,400 30,491 Interest income............................................ (14,285) (8,604) (1,555) Other (income) expense..................................... (3,153) 2,345 (340) -------- -------- -------- Income before provision for income taxes......... 53,159 27,756 12,427 Provision for income taxes................................. 18,460 9,064 5,049 -------- -------- -------- Net income....................................... $ 34,699 $ 18,692 $ 7,378 ======== ======== ======== Basic earnings per common share: Weighted average shares of common stock outstanding...... 19,946 12,903 10,388 Basic earnings per common share.......................... $ 1.74 $ 1.45 $ 0.71 Diluted earnings per common share: Weighted average shares of common stock outstanding...... 21,016 14,879 10,957 Diluted earnings per common share........................ $ 1.65 $ 1.26 $ 0.67
The accompanying notes are an integral part of these consolidated financial statements. F-15 69 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS)
ADDITIONAL PREFERRED COMMON PAID IN RETAINED STOCK STOCK CAPITAL EARNINGS TOTAL --------- -------- ---------- -------- -------- Balance of 10,387,692 shares of common stock at December 31, 1994...................... $ -- $ 10 $ 6,214 $ 12,425 $ 18,649 Dividend ($0.40 per share)................ -- -- -- (800) (800) Net income................................ -- -- -- 7,378 7,378 -------- -------- -------- -------- -------- Balance, December 31, 1995.................. -- 10 6,214 19,003 25,227 Issuance of 5,000,000 shares of preferred stock.................................. 50 -- 49,950 -- 50,000 Conversion of 5,000,000 shares of preferred stock to 2,179,487 shares of common stock........................... (50) 3 47 -- -- Issuance of 7,276,221 shares of common stock, net............................. -- 7 109,172 -- 109,179 Tax benefit from stock options exercised.............................. -- -- 29 -- 29 Net income................................ -- -- -- 18,692 18,692 -------- -------- -------- -------- -------- Balance, December 31, 1996.................. -- 20 165,412 37,695 203,127 Issuance of 217,305 shares of common stock, net............................. -- -- 1,022 -- 1,022 Tax benefit from stock options exercised and other.............................. -- -- 1,108 -- 1,108 Net income................................ -- -- -- 34,699 34,699 -------- -------- -------- -------- -------- Balance, December 31, 1997.................. $ -- $ 20 $167,542 $ 72,394 $239,956 ======== ======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. F-16 70 CALPLNE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS)
1997 1996 1995 --------- --------- --------- Cash flows from operating activities: Net income.......................................... $ 34,699 $ 18,692 $ 7,378 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization, net............... 46,819 36,600 25,931 Deferred income taxes, net....................... 15,082 2,028 (1,027) (Income) loss from unconsolidated investments in power projects................................. (15,819) (6,537) 2,854 Distributions from unconsolidated power projects....................................... 22,950 1,274 -- Change in operating assets and liabilities: Accounts receivable............................ 7,249 (12,652) (3,354) Inventories.................................... (632) 256 -- Other current assets........................... (9,304) 55 (9,542) Other assets................................... (13,203) 63 (307) Accounts payable and accrued expenses.......... 17,464 16,818 6,847 Other liabilities.............................. 3,156 3,347 (2,434) --------- --------- --------- Net cash provided by operating activities... 108,461 59,944 26,346 --------- --------- --------- Cash flows from investing activities: Acquisition of property, plant and equipment........ (107,094) (24,057) (17,434) Acquisitions........................................ (108,671) (149,640) (14,336) Investments in unconsolidated power projects........ (100,968) -- -- Assumption of loan receivable....................... (155,622) -- -- (Increase) decrease in notes receivable............. 33,110 (10,176) (6,348) Investment in collateral securities................. -- (98,446) -- Maturities of collateral securities................. 5,350 2,900 -- Project development costs........................... (11,938) (5,887) (1,258) Decrease (increase) in restricted cash.............. 43,675 (45,631) 1,186 --------- --------- --------- Net cash used in investing activities....... (402,158) (330,937) (38,190) --------- --------- --------- Cash flows from financing activities: Payment of dividends................................ -- -- (800) Borrowings from line of credit...................... 14,300 46,861 34,851 Repayment of borrowings from line of credit......... (14,300) (66,712) (15,000) Borrowings from non-recourse project financing...... 131,600 119,760 76,026 Repayments of non-recourse project financing........ (144,529) (84,708) (79,388) Proceeds from notes payable and short-term borrowings....................................... -- 45,000 2,683 Repayments of notes payable and short-term borrowings....................................... (7,131) (46,177) (6,006) Proceeds from issuance of Senior Notes.............. 275,000 180,000 -- Proceeds from issuance of preferred stock........... -- 50,000 -- Proceeds from issuance of common stock.............. 1,022 109,208 -- Financing costs..................................... (9,722) (8,079) (1,239) --------- --------- --------- Net cash provided by financing activities... 246,240 345,153 11,127 --------- --------- --------- Net increase (decrease) in cash and cash equivalents......................................... (47,457) 74,160 (717) Cash and cash equivalents, beginning of period........ 95,970 21,810 22,527 --------- --------- --------- Cash and cash equivalents, end of period.............. $ 48,513 $ 95,970 $ 21,810 ========= ========= ========= Cash paid during the year for: Interest............................................ $ 42,746 $ 43,805 $ 32,162 Income taxes........................................ $ 9,795 $ 6,947 $ 4,294
The accompanying notes are an integral part of these consolidated financial statements. F-17 71 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 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. For the year ended December 31, 1997, primarily all electricity and steam sales revenue from consolidated subsidiaries was derived from sales to two customers in northern California (see Note 15), of which 43% related to geothermal activities. 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 5). 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 11). Additionally, the Company believes that certain industry restructuring (see Note 16, Regulation and CPUC Restructuring) will not have a material effect on existing power sales agreements and, accordingly, will not have a material effect on existing business or results of operations. Revenue Recognition -- Revenue from electricity and steam sales is recognized upon transmission to the customer. Revenues from contracts entered into or acquired since May 21, 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 Calpine Geyser's Company, L.P. ("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, 1997, 1996 and 1995, would have been approximately $20.1 million, $16.1 million, and $12.6 million less, respectively. The Company performs operations and maintenance services for all consolidated projects in which it has an interest, except for TPC. Revenue from investees is recognized on these contracts when the services are performed. 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. F-18 72 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 Restricted Cash -- The Company is required to maintain cash balances that are restricted by provisions of its debt 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. 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. 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 payment (see Note 3, "King City Transaction"). 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, 1997 and 1996 are as follows (in thousands):
UNREALIZED AMORTIZED AGGREGATE HOLDING COST FAIR VALUE GAINS 1997 --------- ---------- ---------- Debt securities issued by the United States government............................... $ 58,312 $ 63,174 $ 4,862 Corporate debt securities.................. 34,858 37,485 2,627 -------- -------- -------- Total............................ $ 93,170 $100,659 $ 7,489 ======== ======== ========
1996 Debt securities issued by the United States government............................... $ 54,826 $ 56,737 $ 1,911 Corporate debt securities.................. 40,450 40,499 49 -------- -------- -------- Total............................ $ 95,276 $ 97,236 $ 1,960 ======== ======== ========
Concentration 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 receivable. The Company's cash accounts are held by seven FDIC insured banks. The Company's accounts, notes and loans receivable are concentrated within entities engaged in the energy industry (see Note 15), 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 6, "Calpine Vapor Inc."). The Company generally does not require collateral for accounts receivable. 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 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, 1997 and 1996, 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 F-19 73 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 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. 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 30 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, 1997 and 1996, the components of property, plant and equipment, net are as follows (in thousands):
1997 1996 --------- --------- Geothermal properties........................ $ 307,152 $ 297,002 Buildings, machinery and equipment........... 299,018 275,459 Power sales agreements....................... 145,957 145,957 Other assets................................. 11,629 11,555 --------- --------- 763,756 729,973 Less accumulated depreciation and amortization............................... (148,390) (100,674) --------- --------- 615,366 629,299 Land......................................... 754 754 Construction in progress..................... 103,601 18,155 --------- --------- Property, plant and equipment, net.............................. $ 719,721 $ 648,208 ========= =========
Construction in progress includes costs primarily attributable to the development and construction of the Pasadena Power Plant. 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. Generally this occurs upon the execution of a memorandum of understanding or a letter of intent for a power or steam sales agreement. 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 project costs are charged to expense when the Company determines that the project will not be consummated or is impaired. F-20 74 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 Capitalized Interest -- The Company capitalizes interest on projects during the construction period. For the year ended December 31, 1997, the Company capitalized $6.2 million of interest in connection with the construction of its power plants. No interest was capitalized prior to 1997. Other Assets -- Other assets consist of the following at December 31, (in thousands):
1997 1996 ------- ------- Deferred financing costs......................... $20,493 $13,396 Prepaid operating lease, long term portion....... 9,808 -- Other............................................ 507 121 ------- ------- Other assets........................... $30,808 $13,517 ======= =======
Deferred financing costs are amortized over the term of the related financings, which range from 12 to 180 months. 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 connection with 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 deferred and recognized in income over the remaining life of the underlying exposure. At December 31, 1997, the Company had $239.1 million of interest rate swaps on non- recourse project financing. 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 option agreements to manage its exposure to market fluctuations. At December 31, 1997, CPSC held option contracts with two entities for the purchase and sale of up to 50 megawatts each for the period from June 1, 1998 to September 30, 1998. Net open positions may exist due to the origination of new transactions and the Company's evaluation of changing market conditions. An open position exposes the Company to the risk that fluctuating market prices may adversely impact its financial position or results of operations. However, any net open positions are actively managed. The impact of such transactions on the Company's financial position is not necessarily indicative of the impact of price fluctuations throughout the year. CPSC values its portfolio using the aggregate lower of cost or market method. An allowance is recorded for net aggregate losses of the entire portfolio resulting from the effect of market changes on net open positions. Net gains are recognized when realized. The Company's credit risk associated with power contracts results from the risk of loss as a result of 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. The Company sets credit limits prior to entering into transactions and has not obtained collateral or security. Basic and Diluted Earnings Per Share -- In 1997, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings per Share." In February 1998, the Securities and Exchange Commission ("SEC") staff released Staff Accounting Bulletin ("SAB") No. 98, "Computations of Earnings per Share." SAB No. 98 revises prior SEC guidance concerning presentation of earnings per share information for companies going public, and requires all companies to present earnings per share for all periods F-21 75 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 for which income statement information is presented in accordance with SFAS No. 128. Basic earnings per share were computed using the weighted average number of common shares outstanding. Diluted earnings per share were computed using the weighted average number of common shares and the common equivalent shares that would have been outstanding if the Company's dilutive potential shares had been issued. The treasury stock method was used to calculate the potential number of dilutive shares associated with the Company's outstanding stock options. New Accounting Pronouncements -- In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 130, "Reporting Comprehensive Income," which establishes standards for reporting comprehensive income and its components (revenues, expenses, gains and losses) in financial statements. SFAS No. 130 requires classification of other comprehensive income in a financial statement, and the display of the accumulated balance of other comprehensive income separately from retained earnings and additional paid-in capital. SFAS No. 130 is effective for fiscal years beginning after December 15, 1997. The Company believes this pronouncement will not have a material effect on its financial statements. In June 1997, the FASB also issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This pronouncement established standards for reporting 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, although earlier application is encouraged. The Company believes this pronouncement will not have a material effect on its financial statements. Reclassifications -- Certain prior years' amounts in the consolidated financial statements have been reclassified where necessary to conform to the 1997 presentation. 3. ACQUISITIONS AND INVESTMENTS The following acquisitions and investments were consummated during the three years ended December 31, 1997: GREENLEAF TRANSACTION In April 1995, the Company acquired the outstanding capital stock of Portsmouth Leasing Corporation, LFC No. 38 Corp. and LFC No. 60 Corp. (collectively, the "Acquired Companies") for $80.5 million. The purchase price included a cash payment of $20.3 million and the assumption of project debt totaling $60.2 million. In April 1996, the Company finalized the purchase price at $81.5 million. The Acquired Companies own 100% of the assets of two 49.5 megawatt gas-fired cogeneration facilities Greenleaf 1 and Greenleaf 2 (collectively, the "Greenleaf Power Plants"), located in Yuba City in northern California. Electrical energy generated by the Greenleaf Power Plants is sold to Pacific Gas and Electric Company ("PG&E") pursuant to two long-term power sales agreement (expiring in 2019) at prices equal to PG&E's full short-run avoided operating costs, adjusted annually. The power sales agreement also includes payment provisions for firm capacity payments through 2019 for up to 49.2 megawatts on each unit and as-delivered capacity on excess deliveries. PG&E, at its discretion, may curtail purchases of electricity from the Greenleaf Power Plants due to hydro-spill or uneconomic cost conditions. Thermal energy generated is utilized by thermal hosts adjacent to the Greenleaf Power Plants. Gas for the Greenleaf Power Plants is supplied by Calpine Gas Company (see "Montis Niger Transaction"). F-22 76 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 KING CITY TRANSACTION In April 1996, the Company entered into a long-term operating lease with BAF Energy, a California Limited Partnership ("BAF"), for a 120 megawatt gas-fired cogeneration power plant located in King City, California. The power plant generates electricity for sale to PG&E pursuant to a long-term power sales agreement through 2019. The Company recorded the value of the above-market pricing in the power sales agreement of $82.1 million as an asset, which is included in property, plant and equipment, net and is being amortized over the remaining life of the above market pricing period. The Company makes semi-annual lease payments to BAF on February 15 and August 15, a portion of which is supported by a $93.2 million collateral fund owned by the Company (see Note 2, Collateral Securities). As of December 31, 1997, future rent payments are $23.8 million for 1998, $19.4 million for 1999, $20.1 million for 2000, $20.8 million for 2001, $21.6 million for 2002, and $161.6 million thereafter. Included in the accompanying December 31, 1997 balance sheet is approximately $23.5 million of unamortized prepaid lease costs. The Company also recorded a deferred lease incentive of $75.0 million at December 31, 1997 equal to the value of the above-market payments to be received. Lease expense, net of amortization of the deferred lease incentive, was $13.7 million and $9.1 million in 1997 and 1996, respectively. GILROY TRANSACTION In August 1996, the Company acquired a 120 megawatt gas-fired cogeneration power plant located in Gilroy, California. The cost of the Gilroy Power Plant was $125.0 million plus certain contingent consideration, which is expected to be $24.1 million, of which $12.5 million had been paid as of December 31, 1997. In addition, the Company recorded the value of the above-market pricing in the power sales agreement of $63.9 million as an asset, which is included in property, plant and equipment, net, and is being amortized over the remaining life of 22 years. Electricity generated by the Gilroy Power Plant is sold to PG&E pursuant to a long-term power sales agreement terminating in 2018. The power sales agreement contains payment provisions for capacity and energy. The Gilroy power plant also produces and sells thermal energy to ConAgra, Inc. Pro Forma Consolidated Results The following unaudited pro forma consolidated results for the Company give effect to: (i) the King City Transaction and (ii) the Gilroy Transaction as if such transactions had occurred on January 1, 1996. Unaudited pro forma consolidated results are also provided for the effects of the above transactions and (iii) the Watsonville operating lease acquired on June 28, 1995, and (iv) the Greenleaf transaction, as if such had occurred on January 1, 1995 (in thousands, except per share amount).
1996 1995 -------- -------- Revenue...................................... $237,924 $221,447 Net income................................... $ 18,954 $ 11,288 Diluted earnings per share................... $ 1.27 $ 1.03
PASADENA COGENERATION PROJECT In December 1996, the Company entered into a development agreement with Phillips Petroleum Company ("Phillips") to construct and operate a 240 megawatt gas-fired cogeneration project at the Phillips Houston Chemical Complex ("HCC") located in Pasadena, Texas. Additionally, the Company entered into an energy sales agreement with Phillips pursuant to which Phillips will purchase all of HCC's steam and electricity requirements of approximately 90 megawatts. It is anticipated that the remainder of available electricity output will be sold into the competitive market (see Note 2, Power Marketing). The Company also F-23 77 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 entered into a credit agreement with ING U.S. Capital Corporation ("ING") to provide $151.8 million of construction financing to the project. At December 31, 1997, the Company had no borrowings against this credit agreement. In January 1998, the Company borrowed $35.9 million from ING in accordance with the terms of the credit agreement. MONTIS NIGER TRANSACTION In January 1997, the Company paid approximately $7.1 million for 100% of the stock of Montis Niger, Inc. (subsequently renamed Calpine Gas Company). Calpine Gas Company owns gas fields with 8.1 billion cubic feet of estimated proven gas reserves and an 80-mile pipeline system, which provides gas to the Company's Greenleaf Power Plants. TEXAS CITY AND CLEAR LAKE TRANSACTION In June 1997, the Company acquired a 50% equity interest in the Texas City Power Plant and the Clear Lake Power Plant for a total purchase price of $35.4 million, subject to final adjustments. The Company acquired its 50% interest in these plants through the acquisition of 50% of the capital stock of Enron Dominion Cogen Corp. ("EDCC") from Enron Power Corp. EDCC was subsequently renamed Texas Cogeneration Company ("TCC"). The remaining 50% shareholder interest in TCC is owned by Dominion Cogen, Inc. In addition to the purchase of the stock of TCC, the Company purchased from existing lenders the $155.6 million of outstanding non-recourse project financing of the Texas City Power Plant (approximately $53.0 million) and the Clear Lake Power Plant (approximately $102.6 million) (see Note 6, "Texas City and Clear Lake Power Plants"). The Company accounts for its investment in TCC under the equity method. The Texas City and Clear Lake Power Plants are operated by the Company under a one-year contract with automatic renewal provisions. Texas City Power Plant -- The Texas City Power Plant is a 450 megawatt gas-fired cogeneration facility located in Texas City, Texas. The plant commenced commercial operation in June 1987. Electricity generated by the Texas City Power Plant is sold under two separate long-term agreements to: (i) Texas Utilities Electric Company ("TUEC") under an original 12-year power sales agreement terminating in June 1999, which has been extended to September, 2002, and (ii) Union Carbide Company ("UCC") under an original 12-year power sales agreement terminating in June 1999. Each power sales agreement contains provisions for capacity and energy payments. The TUEC power sales agreement provides for a firm capacity payment for 410 megawatts. The UCC power sales agreement provides for a firm capacity payment for 20 megawatts. Clear Lake Power Plant -- The Clear Lake Power Plant is a 377 megawatt gas/hydrogen-fired cogeneration facility located in Pasadena, Texas. The plant commenced commercial operation in December 1984. Electricity generated by the Clear Lake Power Plant is sold under three separate long-term agreements to: (i) Texas New Mexico Power Company ("TNP") under an original 20-year power sales agreement terminating in 2004, (ii) Houston Light & Power Company under an original 10-year power sales agreement terminating in 2005, and (iii) Hoescht Celanese Chemical Group under an original 10-year power sales agreement terminating in 2004. Each power sales agreement contains provisions for capacity and energy payments. DIGHTON TRANSACTION In October 1997, the Company executed agreements with Energy Management, Inc. ("EMI") to invest in the development of two merchant power plants slated for start-up in 1999 and early 2000. The Company F-24 78 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 invested $16.0 million in a 169 megawatt gas-fired combined-cycle plant to be built in Dighton, Massachusetts. The Company will receive a preferred payment stream at a rate of approximately 12% on its investment. The Company accounts for its investment in Dighton under the equity method of accounting. During construction of the facility, the Company capitalizes interest on the investment at a rate equal to the average corporate cost of debt. Under the terms of the above agreements, the Company has also been granted an exclusive option to purchase an ownership interest in, and to partner with, EMI on the 265 megawatt gas-fired plant under development in Tiverton, Rhode Island. EMI and the Company would be co-general partners for the project. The Company intends to invest up to $43.0 million of equity in the development of the Tiverton Power Plant. AUBURNDALE AND GORDONSVILLE TRANSACTION In October 1997, the Company acquired a 50% interest in both the Auburndale Power Plant and the Gordonsville Power Plant for a total purchase price of $42.4 million, subject to final adjustments. The Company acquired its interest in these plants from Norweb Power Services Limited and Northern Hydro Limited, both wholly-owned subsidiaries of Norweb PLC. The Company accounts for its investment in the Auburndale Power Plant and Gordonsville Power Plant under the equity method. Auburndale Power Plant -- The Auburndale Power Plant is a 150 megawatt gas-fired cogeneration facility located outside of Orlando, Florida. The Auburndale Power Plant commenced commercial operation in July 1994 and sells capacity and energy to Florida Power Corporation under three 20-year power sales agreements terminating in December 2013. Gordonsville Power Plant -- The Gordonsville Power Plant is a 240 megawatt gas-fired cogeneration facility located near Gordonsville, Virginia. The Gordonsville Power Plant commenced commercial operations in June 1994 and sells capacity and energy to Virginia Electric and Power Company under two 30-year power sales agreements terminating in 2024. The Gordonsville and Auburndale Power Plants are operated by Edison Mission Operations & Maintenance, Inc. ("EMOM"), an affiliate of Edison Mission Energy. The operating agreements between EMOM and the two facilities expire in December 2013. EMOM is paid on a cost-plus basis for all direct labor plus reimbursement of certain costs, an operating fee and an incentive based upon performance. GAS ENERGY INC. AND GAS ENERGY COGENERATION INC. TRANSACTION In December 1997, the Company acquired 100% of the capital stock of Gas Energy Inc. ("GEI") and Gas Energy Cogeneration Inc. ("GECI") from The Brooklyn Union Gas Company ("BUG"), for a total purchase price of $100.9 million, subject to final adjustments. GEI and GECI were both wholly-owned subsidiaries of BUG and have (i) a 50% interest in the Kennedy International Airport Cogeneration Power Plant, (ii) a 50% interest in the Stony Brook Power Plant, (iii) a 45% interest in the Bethpage Power Plant, (iv) an 11.36% interest in the Lockport Power Plant and (v) a 100% interest in three fuel management contracts. The Company accounts for its investments in the above power plants under the equity method. The Kennedy International Airport Cogeneration Power Plant is a 107 megawatt gas-fired cogeneration facility located in Queens, New York. Steam and electricity generated by the Kennedy International Airport Cogeneration Power Plant are sold to the Port Authority of New York and New Jersey to service the John F. Kennedy International Airport under a 20-year power sales agreement terminating in 2015. The Stony Brook Power Plant is a 40 megawatt gas-fired cogeneration facility located at the State University of New York in Stony Brook, New York. Steam and electricity generated by the Stony Brook F-25 79 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 Power Plant are sold to the State University of New York at Stony Brook under a 20-year power sales agreement terminating in 2015, and excess electricity is sold to Long Island Lighting Company ("LILCo"). The Bethpage Power Plant is a 57 megawatt gas-fired cogeneration facility located in Bethpage, New York. Steam and electricity generated by the Bethpage Power Plant are sold to the Northrop Grumman Corporation under a 15-year power sales agreement expiring in 2004, and excess electricity is sold to LILCo. On February 5, 1998, the Company purchased the remaining 55% interest in the Bethpage Power Plant for approximately $4.6 million. The Lockport Power Plant is a 184 megawatt gas-fired cogeneration facility located in Lockport, New York. Steam and electricity generated by the Lockport Power Plant are sold to a General Motors plant under a 15-year power sales agreement terminating in 2007, and excess electricity is sold to New York State Electric and Gas ("NYSEG"). 4. ACCOUNTS RECEIVABLE At December 31, 1997, accounts receivable totaled $42.8 million, which included $7.7 million receivable from related parties. Accounts receivable from related parties at December 31, 1997 and 1996 include the following (in thousands):
DECEMBER 31, ---------------- 1997 1996 ------ ------ Nisseqougue Cogen Partners................................. $4,140 $ -- TBG Cogen Partners......................................... 1,490 -- Texas Cogeneration Company................................. 903 -- Sumas Cogeneration Company, L.P............................ 527 590 Geothermal Energy Partners, Ltd............................ 275 350 O.L.S. Energy-Agnews, Inc.................................. 269 687 KIAC Partners.............................................. 68 -- Electrowatt Ltd. and subsidiaries.......................... -- 1,199 ------ ------ Accounts receivable from related parties............ $7,672 $2,826 ====== ======
At December 31, 1996, the $1.2 million receivable from Electrowatt Ltd. (the previous indirect sole owner of the Company) was for reimbursement of costs for the sale of Electrowatt Ltd.'s ownership of the Company's common stock during the Company's initial public offering in September 1996. 5. RESULTS OF UNCONSOLIDATED INVESTMENTS The Company has unconsolidated investments in power projects which are accounted for under the equity method. Investments in less-than-majority-owned affiliates and the nature and extent of these F-26 80 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 investments change over time. The combined results of operations and financial position of the Company's equity-basis affiliates are summarized below (in thousands):
DECEMBER 31, -------------------------------------- 1997 1996 1995 ---------- ---------- ---------- Condensed Statement of Operations: Operating revenue.................... $ 271,494 $ 77,417 $ 63,981 Net income (loss).................... 30,264 14,021 (1,043) Condensed Balance Sheet: Assets............................... 1,693,454 235,682 239,149 Liabilities.......................... 1,276,922 200,667 213,850 Investments (see Note 2)............. 237,241 13,061 7,306 Project development costs............ 1,919 875 912 ---------- ---------- ---------- Total investments............ 239,160 13,936 8,218 ========== ========== ========== Company's share of net income (loss)... $ 15,819 $ 6,537 $ (2,854)
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):
INCOME FROM UNCONSOLIDATED INVESTMENTS IN POWER PROJECTS SERVICE CONTRACT REVENUE ----------------------------- ------------------------ FOR THE YEARS ENDED DECEMBER 31, COMPANY'S -------------------------------------------------------- OWNERSHIP 1997 1996 1995 1997 1996 1995 PERCENTAGE -------- ------- -------- ------ ------ ------ Sumas Cogeneration Company, L.P.... (1) $ 8,565 $6,396 $(3,049) $2,073 $2,034 $2,021 O.L.S. Energy-Agnews, Inc.......... 20% 17 (190) (82) 1,712 1,954 1,515 Geothermal Energy Partners, Ltd.... 5% 454 331 277 3,024 3,990 3,547 Texas Cogeneration Company......... 50% 6,331 -- -- 2,782 -- -- Auburndale Power Partners, L.P..... 50% (245) -- -- -- -- -- Gordonsville Energy, L.P........... 50% 404 -- -- -- -- -- KIAC Partners...................... 50% (190) -- -- -- -- -- Nissequogue Cogen Partners......... 50% 60 -- -- -- -- -- TBG Cogen Partners................. 45% 223 -- -- -- -- -- Lockport Energy Associates, L.P.... 11% 200 -- -- -- -- -- ------- ------ ------- ------ ------ ------ $15,819 $6,537 $(2,854) $9,591 $7,978 $7,083 ======= ====== ======= ====== ====== ======
The Company received $20.3 million and $1.3 million in distributions from Sumas for the years ended December 31, 1997 and 1996, respectively. The Company received $767,000 in distributions from Lockport Energy Associates, L.P. for the year ended December 31, 1997. - --------------- (1) On September 30, 1997, the partnership agreement governing Sumas Cogeneration Company, L.P. ("Sumas") 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. F-27 81 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 6. NOTES AND LOANS RECEIVABLE SUMAS POWER PLANT In May 1993, in accordance with the Sumas partnership agreement, the Company was entitled to receive a distribution of $1.5 million and Sumas Energy, Inc. ("SEI"), the Company's partner in Sumas, was required to make a capital contribution of $1.5 million. In order to meet SEI's $1.5 million capital contribution requirement, the Company loaned $1.5 million to the sole shareholder of SEI, who in turn loaned the funds to SEI, who in turn contributed the capital to Sumas. The interest rate on the loan was 20% and was secured by a security interest in the loan between SEI and its sole shareholder. The Company received all principal plus accrued interest totaling $2.8 million in 1997. In March 1994, the Company loaned $10.0 million to the sole shareholder of SEI. The interest rate on the loan was 16.25%. The loan was secured by a pledge to Calpine of SEI's interest in Sumas. The Company deferred the recognition of interest income from these notes until Sumas generated net income. During 1997, the $10.0 million loan was sold to a third party. The Company received all unpaid principal and interest related to both loans and recognized a total of $6.9 million of the interest income during 1997 (of which $3.5 million was previously deferred). In addition, the Company recorded a $1.1 million gain upon the sale of the $10.0 million loan, which was recorded in Other (income) expense. In 1996, the Company recognized $2.1 million of interest income related to the above two loans, which represents the portion of Sumas' earnings not recognized by the Company related to its equity investment in Sumas. In September 1997, the Company entered into a loan agreement with SEI's sole shareholder wherein the Company agreed to make available a line of credit up to $15.0 million, the proceeds of which are required to be used to develop a new project. SEI has guaranteed the payment and performance of obligations under this agreement and borrowings under the agreement will be collateralized by the new project and the sole shareholder's 100% interest in SEI. The loan agreement will expire on December 31, 2003. TEXAS CITY AND CLEAR LAKE POWER PLANTS In connection with the acquisition of TCC, the Company purchased from the existing lenders the $155.6 million of outstanding project debt of the Texas City Power Plant (approximately $53.0 million) and the Clear Lake Power Plant (approximately $102.6 million). At December 31, 1997, there were loans receivable of $37.1 million from Texas City and $94.7 million from Clear Lake (of these amounts $30.5 million is current and $101.3 million is long term). The effective interest rate on the loan to Texas City including the effect of the swap arrangement, was approximately 7.9% at December 31, 1997; the loan matures June 30, 1999. The effective interest rate on the loan to Clear Lake, including the effect of the existing swap arrangement, was approximately 8.3%; the loan matures December 31, 2003. Both notes are secured by the assets of the respective partnerships. CALPINE VAPOR INC. 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, Concentration of Credit Risks). 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, 1997 and 1996, notes receivable were $16.1 million and $18.0 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 F-28 82 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 until the Cerro Prieto Project generates sufficient cash flows available for distribution to support the collectibility of accrued interest. 7. REVOLVING CREDIT FACILITY AND LINES OF CREDIT At December 31, 1997 and 1996, the Company had a $50.0 million credit facility available with a consortium of commercial lending institutions which include The Bank of Nova Scotia, ING, Sumitomo Bank of California and Canadian Imperial Bank of Commerce. As of December 31, 1997, the Company had no borrowings and $9.4 million of letters of credit outstanding. This amount reflects $6.0 million to secure performance with the Clear Lake Power Plant, $1.5 million to secure performance under a purchase power agreement, and $1.9 million related to operating expenses at the Watsonville Power Plant. At December 31, 1996, the Company had no borrowings and $5.9 million of letters of credit outstanding, which reflected $3.0 million to secure performance with the Pasadena Power Plant and $2.9 million related to operating expenses at the Watsonville Power Plant. Borrowings bear interest at The Bank of Nova Scotia's base rate or at the London InterBank Offering Rate ("LIBOR"), plus an applicable margin. Interest is paid on the last day of each interest period for such loans, but not less often than quarterly, based on the principal amount outstanding during the period for base rate loans, and on the last day of each applicable interest period, but not less often than 90 days, for LIBOR loans. The credit agreement expires in September 1999. The credit agreement specified that the Company maintain certain covenants with which the Company was in compliance. Commitment fees related to this line of credit are charged based on 0.50% of committed unused credit. At December 31, 1997 and 1996, the Company had a loan facility with available borrowings totaling $1.2 million. As of December 31, 1997, the Company had no borrowings and $74,000 of letters of credit outstanding. There were no borrowings and $900,000 of letters of credit outstanding as of December 31, 1996. 8. NON-RECOURSE PROJECT FINANCING The components of non-recourse project financing as of December 31, 1997 and 1996 are (in thousands):
1997 1996 -------- -------- Senior-term loans: Fixed rate portion........................... $ -- $ 73,000 Variable rate portion........................ -- 20,000 Premium on debt.............................. -- 1,824 -------- -------- Total senior-term loans.............. -- 94,824 Junior-term loan............................... -- 19,965 Notes payable to banks......................... 295,859 194,478 -------- -------- Total long-term debt................. 295,859 309,267 Less current portion................. 112,966 30,627 -------- -------- Long-term debt, less current portion............................ $182,893 $278,640 ======== ========
Senior-Term and Junior-Term Loans -- The Company entered into Senior-Term and Junior-Term Loans in connection with the Company's acquisition of CGC in 1993. On July 8, 1997, the Company repaid all Senior-Term and Junior-Term Loans before their maturity date from the proceeds of the 8 3/4% Senior Notes Due 2007. In connection with this transaction, the Company terminated one swap transaction and retained one swap transaction, which was redesignated to other floating rate financings. The Company had entered into swap transactions to minimize the impact of changes in interest rates on a portion of the Senior- Term loans. At December 31, 1997, the remaining swap had an effective interest rate of 9.9%. The Company F-29 83 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 is potentially exposed to credit risk in an event of non-performance by the other parties to the swap agreements. Notes Payable to Banks -- In June 1995, the Company entered into an agreement with Sumitomo Bank to finance the acquisition of the Greenleaf Power Plants. Of the $71.9 million debt outstanding at December 31, 1997, $56.8 million bears interest fixed at 7.4%, with the remaining floating rate portion accruing interest at LIBOR, plus an applicable margin (6.5% at December 31, 1997). At December 31, 1996, $74.7 million of debt was outstanding, of which $59.0 million was at the fixed interest rate of 7.4%, with the remaining floating rate portion accruing interest at approximately 6.2%. This debt is secured by all of the assets of the Greenleaf Power Plants. Interest on the floating rate portion may be at Sumitomo's base rate plus an applicable margin or at LIBOR plus an applicable margin. Interest on base rate loans is paid at the end of each calendar quarter, and interest on LIBOR based loans is paid on each maturity date, but not less often than quarterly, based on the principal amount outstanding during the period. At the Company's discretion, the LIBOR based loans may be held for various maturity periods of at least 1 month up to 12 months. The $71.9 million debt is being repaid quarterly, with a final maturity date of December 31, 2010. The credit agreement specifies that the Company maintain certain covenants in which the Company was in compliance at December 31, 1997. On August 29, 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, 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. As of December 31, 1996, BNP had provided a $119.8 million loan consisting of a 15-year tranche in the amount of $84.8 million and an 18-year tranche in the amount of $35.0 million. The debt is secured by all of the assets of the Gilroy Power Plant. A portion of the BNP notes bears interest fixed at a weighted average of 6.6% as of December 31, 1997 and 1996 (see discussion below), with the remainder accruing interest at floating rate. Interest on the floating rate portion may be at BNP's base rate plus an applicable margin or at LIBOR plus an applicable margin (7.1% and 6.6% at December 31, 1997 and 1996, respectively). Interest on the loans is payable not less often than quarterly. Interest on LIBOR based loans is paid on each maturity date, but not less often than quarterly. 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 $120.5 million debt is repaid semi-annually with a final maturity date of August 28, 2011. Commitment fees are charged based on 1% to 1.125% of committed unused credit. The Company entered into four interest rate swap agreements to minimize the impact of changes in interest rates. These agreements fix the interest on $85.1 million of principal at a weighted average interest rate of 6.6%. The interest rate swap agreements mature through August 2011. The Company is exposed to credit risk in the event of non-performance by the other parties to the swap agreements. On June 23, 1997, the Company entered into a $125.0 million non-recourse project financing with The Bank of Nova Scotia. Proceeds were utilized for the acquisition of the 50% interest in TCC and the purchase from the lenders of $155.6 million of outstanding non-recourse project financing. The $125.0 million non-recourse project financing matures on June 22, 1998. The Company expects to refinance this non-recourse project financing prior to maturity. On December 31, 1997, $103.4 million of borrowings were outstanding which bear interest at The Bank of Nova Scotia's base rate or LIBOR, plus an applicable margin (approximately 7.2% at December 31, 1997). The Company utilized swap arrangements to minimize the impact of potential changes in interest rates on the project debt. The effective interest rate, including the effect of the swap arrangement, was approximately 7.1% at December 31, 1997. The interest rate swap agreements mature in June 1998. The Company has potential exposure to credit risk in the event of non-performance by other parties to the swap agreements. The credit agreement specifies that the Company maintain certain covenants in which the Company was in compliance at December 31, 1997. F-30 84 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 At December 31, 1997, the Company held a credit agreement with ING to provide $151.8 million of non-recourse project financing for the Pasadena Power Plant (see Note 3, "Pasadena Cogeneration Project"). Interest is payable at ING's base rate or the Federal Funds Rate plus an applicable margin on the last day of each calendar quarter, or at LIBOR plus an applicable margin upon maturity of the loan, but not less often than quarterly. All interest is due and payable upon conversion of the construction loan to a term loan. Subject to the terms of the credit agreement, all or part of the construction loan will be converted to a term loan upon completion of construction. Commitment fees are charged based on 0.375% of committed unused credit. No borrowings were outstanding at December 31, 1997 and 1996. In January 1998, the Company borrowed $35.9 million in accordance with the terms of the credit agreement. Beginning in June 1997, the Company was obligated to enter into several hedge transactions pursuant to the credit agreement, the notional values of which range from $25.0 million to $75.0 million, all of which were hedged at 7.2%. The annual principal maturities of the non-recourse project financing outstanding at December 31, 1997 are as follows (in thousands): 1998.............................. $112,966 1999.............................. 8,683 2000.............................. 10,352 2001.............................. 10,631 2002.............................. 11,132 Thereafter........................ 142,095 -------- Total................... $295,859 ========
The non-recourse project financing is held by subsidiaries of Calpine. The debt agreements governing the non-recourse project financing generally restrict their ability to pay dividends, make distributions or otherwise transfer funds. The dividend restrictions in such agreements generally require that, prior to the payment of dividends, distributions or other transfers, the subsidiary or other affiliate must provide for the payment of other obligations, including operating expenses, debt service and reserves. 9. NOTES PAYABLE At December 31, 1996, the Company had a non-interest bearing promissory note for $6.5 million payable to Natomas Energy Company, a wholly-owned subsidiary of Maxus Energy Company. This note had been discounted to yield 8.0% per annum, due September 9, 1997, and had a carrying value of $6.2 million at December 31, 1996. On July 8, 1997, the Company repaid the promissory note before its maturity date from the proceeds of the 8 3/4% Senior Notes Due 2007 (see Note 10). 10. SENIOR NOTES On July 8, 1997, the Company issued $200.0 million aggregate principal amount of 8 3/4% Senior Notes Due 2007. Transaction costs of $9.7 million incurred in connection with the debt offering were capitalized and are included in Other assets and amortized over the ten-year life of the 8 3/4% Senior Notes Due 2007. On September 10, 1997, the Company issued an additional $75.0 million aggregate principal amount of 8 3/4% Senior Notes Due 2007. In May and June 1997, the Company executed five interest rate hedging transactions related to debt. The notional value of the debt was $182.0 million and was 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 F-31 85 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 interest rate on the $275.0 million aggregate principal amount after the hedging transactions and the amortization of transaction costs was 9.1%. The 8 3/4% Senior Notes Due 2007 will mature on July 15, 2007. The Company has no sinking fund or mandatory redemption obligations with respect to the 8 3/4% Senior Notes Due 2007. Interest is payable semi-annually on January 15 and July 15 of each year while the 8 3/4% Senior Notes Due 2007 are outstanding, commencing on January 15, 1998. Based on the traded yield to maturity, the approximate fair market value of the 8 3/4% Senior Notes Due 2007 was $280.5 million as of December 31, 1997. On May 16, 1996, the Company issued $180.0 million aggregate principal amount of 10 1/2% Senior Notes Due 2006. Transaction costs of $5.1 million incurred in connection with the public debt offering were recorded in Other assets and amortized over the ten-year life of the 10 1/2% Senior Notes Due 2006. The effective interest rate of the $180.0 million aggregate principal amount after the amortization of transaction costs was 10.7%. The 10 1/2% Senior Notes Due 2006 will mature on May 15, 2006. The Company has no sinking fund or mandatory redemption obligations with respect to the 10 1/2% Senior Notes Due 2006. Interest is payable semi-annually on May 15 and November 15. Based on the traded yield to maturity, the approximate fair market value of the 10 1/2% Senior Notes Due 2006 was $196.2 million as of December 31, 1997. The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. The Company has no sinking fund or mandatory redemption obligations with respect to the 9 1/4% Senior Notes Due 2004. Interest is payable semi-annually on February 1 and August 1. Based on the traded yield to maturity, the approximate fair market value of the 9 1/4% Senior Notes Due 2004 was $108.7 million as of December 31, 1997. The effective interest rate on the $105.0 million aggregate principal amount after amortization of transaction costs was 9.6%. The Senior Note indentures specify that the Company maintains certain covenants with which the Company was in compliance. The Company may, under certain circumstances, be limited in its ability to make restricted payments, as defined, which include dividends and certain purchases and investments, incur additional indebtedness and engage in certain transactions. 11. PROVISION FOR INCOME TAXES The Company follows the liability method of accounting for income taxes whereby deferred income taxes are recognized for the tax consequences of "temporary differences" to the extent they are not reduced by net operating loss and tax credit carryforwards by applying enacted statutory rates. The components of the deferred tax liability as of December 31, 1997 and 1996 are (in thousands):
1997 1996 --------- --------- Expenses deductible in a future period............... $ 4,122 $ 3,329 Net operating loss and credit carryforwards.......... 20,260 19,856 Other differences.................................... 2,524 494 --------- --------- Deferred tax asset................................. 26,906 23,679 --------- --------- Property differences................................. (156,526) (119,842) Difference in taxable income and income from investments recorded on the equity method.......... (5,798) (2,753) Other differences.................................... (6,632) (1,469) --------- --------- Deferred tax liabilities........................... (168,956) (124,064) --------- --------- Net deferred tax liability...................... $(142,050) $(100,385) ========= =========
F-32 86 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 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, 1997, the federal net operating loss carryforwards were approximately $11.3 million. At December 31, 1997, state net operating losses have been fully utilized. At December 31, 1997, federal and state alternative minimum tax credit carryforwards were approximately $10.6 million and $3.6 million, respectively. In 1997 and 1996, the Company decreased its deferred income tax liability by $2.1 million and $769,000 to reflect the change in the California state income tax rate from 9.3% to 8.8% effective January 1, 1997 and 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. In September 1996, the Company underwent an ownership change as a result of the initial public offering of the Company's common stock. This ownership change limits the amount of net operating loss and credit carryforwards available to offset current tax liabilities. Although realization is not assured, management believes it is more likely than not that all of the deferred tax asset will be realized based on estimates of future taxable income. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. The provision for income taxes for the years ended December 31, 1997, 1996 and 1995 consists of the following (in thousands):
1997 1996 1995 ------- ------- ------- Current: Federal..................................... $ 1,892 $ 5,671 $ 3,085 State....................................... 917 1,805 1,163 Deferred: Federal..................................... 14,989 3,890 816 State....................................... 2,897 (801) (15) Adjustment in state tax rate (net of federal benefit)....................... (2,113) (769) -- Revision in prior years' tax estimates... (122) (732) -- ------- ------- ------- Total provision..................... $18,460 $ 9,064 $ 5,049 ======= ======= =======
The Company's effective rate for income taxes for the years ended December 31, 1997, 1996 and 1995 differs from the United States statutory rate, as reflected in the following reconciliation.
1997 1996 1995 ---- ---- ---- United States statutory tax rate....................... 35.0% 35.0% 35.0% State income tax, net of federal benefit............... 5.0 6.0 6.0 Depletion allowance.................................... (2.1) (2.3) (0.3) Effect of change in state tax rates, net of federal benefit.............................................. -- (3.0) -- Decrease in California deferred tax due to Company's expansion into other states, net of federal benefit.............................................. (4.1) -- -- Revision in prior years' tax estimates................. -- (2.6) -- Other, net............................................. 0.9 (0.4) (0.1) ---- ---- ---- Effective income tax rate.................... 34.7% 32.7% 40.6% ==== ==== ====
F-33 87 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 12. 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-sharing contribution. Employer profit-sharing contributions in 1997, 1996, and 1995 totaled $588,000, $485,000 and $350,000, respectively. 13. STOCKHOLDERS' EQUITY Common Stock In September 1996, the Company completed an initial public offering of 18,045,000 shares of its common stock with $0.001 par value per share (the "Common Stock Offering"). In the Common Stock Offering, the Company issued and sold 5,477,820 shares of common stock and Electrowatt Ltd. ("Electrowatt") sold 12,567,180 shares of common stock, representing its entire ownership interest in the Company. As a result of the Common Stock Offering, Electrowatt no longer owns any interest in the Company. The Company received approximately $82.1 million of net proceeds from the Common Stock Offering. In October 1996, the Company issued an additional 1,793,400 shares of common stock to cover over-allotments of shares in connection with the Common Stock Offering and received approximately $27.1 million of net proceeds. In connection with the Common Stock Offering, the Company completed a 5.194-for-1 stock split of the Company's common stock and converted the Company's outstanding Series A Preferred Stock into shares of common stock. The accompanying financial statements reflect the stock split retroactively for all periods presented. Preferred Stock and Preferred Share Purchase Rights The Company had 5,000,000 authorized shares of Series A Preferred Stock, all of which were issued on March 21, 1996 to Electrowatt. The shares of Series A Preferred Stock were not publicly traded. No dividends were payable on the Series A Preferred Stock. The Series A Preferred Stock contained provisions regarding liquidation and conversion rights. Upon the consummation of the Common Stock Offering, all of the Series A Preferred Stock were converted into approximately 2.2 million shares of common stock and sold to the public in the Common Stock Offering by Electrowatt. 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. On December 31, 1997, there were 19,905,233 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. F-34 88 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 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. 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. 14. STOCK-BASED COMPENSATION PROGRAMS 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, 54,149 shares were issued at a weighted average fair value of $13.65 per share in 1997. On January 30, 1998, employees participating in the ESPP purchased an additional 30,385 shares at a weighted average fair value of $13.39 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):
1997 1996 1995 ------- ------- ------- Net income As reported $34,699 $18,692 $ 7,378 Pro Forma $33,528 $18,145 $ 7,232 Basic earnings per share As reported $ 1.74 $ 1.45 $ 0.71 Pro Forma $ 1.68 $ 1.41 $ 0.70 Diluted earnings per share As reported $ 1.65 $ 1.26 $ 0.67 Pro Forma $ 1.60 $ 1.22 $ 0.66
The fair value of options granted in 1995, 1996 and 1997 was $1.23, $3.29 and $10.28 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 44%, 27% and 0% for 1997, 1996 and 1995, risk-free interest rates of 5.8%, 6.2% and 5.4% for 1997, 1996 and 1995, respectively, and expected lives of 3 years for 1995 and 1996, and 7 years for 1997. 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 F-35 89 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 future years. The Company may grant options for up to 4,041,858 shares under the SIP. As of December 31, 1997, the Company had granted options to purchase 2,519,803 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 four years and expire after 10 years. Changes in options outstanding, granted, exercisable and cancelled by the Company during the years 1997, 1996, and 1995, whether under the option or purchase plan were as follows:
AVAILABLE FOR WEIGHTED OPTION OR NUMBER OF AVERAGE AWARD SHARES EXERCISE PRICE ------------- --------- -------------- (IN THOUSANDS) Beginning Balance January 1, 1995................ 1,160,782 1,436,141 $ 1.53 Granted..................................... (444,333) 444,333 4.91 Cancelled................................... 25,963 (25,963) 2.13 --------- --------- --------- Outstanding December 31, 1995.................... 742,412 1,854,511 2.34 Additional shares reserved..................... 1,444,935 -- -- Granted..................................... (547,579) 547,579 8.71 Exercised................................... -- (5,000) 1.85 Cancelled................................... 56,796 (56,796) 7.90 --------- --------- --------- Outstanding December 31, 1996.................... 1,696,564 2,340,294 3.69 Granted..................................... (394,217) 394,217 18.31 Exercised................................... -- (163,156) 1.33 Cancelled................................... 51,552 (51,552) 8.55 --------- --------- --------- Outstanding December 31, 1997.................... 1,353,899 2,519,803 $ 6.03 ========= ========= ========= Options exercisable: December 31, 1995................................ 1,217,340 $ 1.15 December 31, 1996................................ 1,445,746 1.71 December 31, 1997................................ 1,635,469 3.23
The following tables summarizes information concerning outstanding and exercisable options at December 31, 1997:
OUTSTANDING OPTIONS ---------------------------------------------------- OPTIONS EXERCISABLE WEIGHTED AVERAGE -------------------------------- REMAINING WEIGHTED WEIGHTED RANGE OF NUMBER OF CONTRACTUAL LIFE AVERAGE NUMBER OF AVERAGE EXERCISE PRICES SHARES IN YEARS EXERCISE PRICE SHARES EXERCISE PRICE --------------- -------------- ---------------- -------------- -------------- -------------- (IN THOUSANDS) (IN THOUSANDS) $ 0.50 - $ 0.50........... 841,220 5.00 $ 0.50 841,220 $ 0.50 $ 1.85 - $ 1.85........... 117,887 5.25 1.85 117,887 1.86 $ 4.57 - $ 4.91........... 692,228 7.48 4.77 489,737 4.71 $ 6.83 - $ 6.83........... 1,317 9.00 6.83 1,317 6.83 $ 8.57 - $ 8.57........... 474,251 9.00 8.57 117,808 8.57 $16.00 - $20.50........... 382,900 9.22 18.19 57,500 19.27 $20.75 - $20.75........... 10,000 9.04 20.75 10,000 20.75 --------- --------- --------- --------- --------- Total........... 2,519,803 7.10 $ 6.03 1,635,469 $ 3.23 ========= ========= ========= ========= =========
15. SIGNIFICANT CUSTOMERS The Company's electricity and steam sales revenue is primarily from two sources -- PG&E and the Sacramento Municipal Utility District ("SMUD"). F-36 90 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 Revenues earned from these sources for the years ended, December 31, 1997, 1996 and 1995 were as follows (in thousands):
1997 1996 1995 REVENUES: -------- -------- -------- PG&E....................................... $221,457 $183,531 $112,522 SMUD....................................... 13,223 14,609 12,345
Accounts receivable at December 31, 1997 and 1996 were as follows (in thousands):
1997 1996 ACCOUNTS RECEIVABLE: -------- -------- PG&E....................................... $ 29,631 $ 27,534 SMUD....................................... 1,019 1,137
Industry restructuring and deregulation (see Note 16, "Regulation and CPUC Restructuring") will also affect PG&E, the Company's primary customer. 16. COMMITMENTS AND CONTINGENCIES Capital Projects -- The Company has 1998 commitments of $19.8 million related to the construction of the Pasadena Power Plant (see Note 3, "Pasadena Cogeneration Project"). 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, 1997, 1996 and 1995 are (in thousands):
1997 1996 1995 ------- ------- ------- Production Royalties.................. $10,803 $10,793 $10,574 Lease payments........................ 222 246 225
Natural Gas Purchases -- The Company enters into short-term gas purchase contracts with third parties to supply gas to its gas-fired cogeneration projects. Watsonville Operating Lease -- In June 1995, the Company acquired a 14.5 year operating lease (through December 2009) for the 28.5 megawatt natural gas-fired cogeneration power plant located in Watsonville, California. Under the terms of the lease, basic and contingent rents are payable each month during the period from July through December. As of December 31, 1997, future basic rent payments have remained the same from prior years at $2.9 million for 1996 and 1997, respectively. Future payment from 1998 to 2001 will continue at the current rate of $2.9 million, and $24.4 million thereafter through December 2009. Contingent rent expense for 1997 and 1996 was $864,000 and $671,000, respectively. This expense is based on the net of revenues less all operating expenses, fees, reserve requirements, basic rent and supplemental rent payments. Of the remaining balance, 60% is payable to the lessor and 40% is payable to the Company. F-37 91 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 Office and Equipment Leases -- The Company leases its corporate office, Santa Rosa office facilities and certain office equipment under noncancellable operating leases expiring through 2002. Future minimum lease payments under these leases are (in thousands): 1998................................ $1,409 1999................................ 1,211 2000................................ 1,128 2001................................ 564 2002................................ 114 Thereafter.......................... -- ------ $4,426 ======
Lease payments are subject to adjustments for the Company's pro rata portion of annual increases or decreases in building operating costs. In 1997, 1996, and 1995 rent expenses for noncancellable operating leases amounted to $1.2 million, $1.0 million and $733,000, respectively. Regulation and CPUC Restructuring -- Electricity and steam sales agreements with PG&E are regulated by the California Public Utilities Commission ("CPUC"). In December 1995, the CPUC issued a decision which proposed the transition of the regulated electric generation market to a competitive generation market beginning January 1, 1998. Since the proposed restructure represented a widespread impact on the market structure, requiring participation and oversight of the Federal Energy Regulatory Commission (the "FERC"), the CPUC sought and built a California consensus coalition which resulted in filings at the FERC which permitted the CPUC and the FERC to collectively proceed with implementation of the new competitive market structure. In late 1996, comprehensive legislation, AB 1890 ("the Bill"), was signed into California law which adopted the basic tenets of the CPUC electric industry restructure decision and directed the CPUC to proceed with implementation of restructure with customer choice of electricity supplier available no later than January 1, 1998. The Bill provided for market power mitigation by utility divestiture of fossil generation plants, provided a four year transition period for utility recovery of stranded costs, provided for sanctity of existing qualifying facility ("QF") contracts with provision for voluntary restructure, established an electricity rate freeze for the four year transition period for certain customers, mandated a 10% rate reduction beginning January 1, 1998 and continuing through the transition period for small commercial and residential customers financed by issuance of rate reduction bonds, and provided specified funds for continued public service programs including public interest research and development and enhancement of in-state renewable energy resources, which includes geothermal operations. In late 1997, the CPUC and the FERC issued decisions which provided for January 1, 1998 implementation of the California Independent Systems Operator ("ISO") responsible for centralized control and reliable operation of the state-wide electric transmission grid and the Power Exchange ("PX") responsible for the competitive electric energy auction. In late 1997, CPUC-approved sales of certain utility-owned fossil generation plants were completed and applications were pending at the CPUC for sales of the remaining utility-owned California fossil and geothermal power plants. Investor-owned utilities, though transferring control to the ISO, will continue to own and collect revenue from their transmission facilities and will continue to be regulated utility distribution companies ("UDC") for all electric service providers with default electric supplier responsibility. In December 1997, mechanics for operation of the ISO and PX were not yet fully perfected and implementation of deregulation was delayed to April 1, 1998. The California Energy Commission ("CEC") was directed by the Bill to develop a competitive mechanism for allocation and distribution of funds made available for public interest research and development and enhancement of in-state renewable resources. The CEC, in late 1997, issued its draft guidelines for selective allocation and distribution of the funds which are to be available over the four year transition period to a fully competitive electric services industry. Though the F-38 92 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 Company believes that implementation of electric industry restructure can provide significant opportunity for independent power producers, the ultimate impact of both increased competition and the changing regulatory environment on the Company's future results from operations is uncertain. A domestic electricity generating project must be a QF under the FERC regulations in order to take advantage of certain rate and regulatory incentives provided by the Public Utility Regulatory Policies Act of 1978, as amended ("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 state laws concerning rate or financial regulation. PURPA also requires that electric utilities purchase electricity generated by QFs at a price based on the utility's "avoided cost", and that the utility sell back-up power to the QF on a non-discriminatory basis. If one of the projects in which the Company has 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 laws and could result in the Company inadvertently becoming a public utility holding company. The Company believes that each of the electricity generating projects in which the Company owns an interest currently meets the requirements under PURPA necessary for QF status. Litigation 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. All the defendants filed motions to dismiss such claims, which are currently pending. The Company believes that the claims of Indeck are without merit and that the resolution of this matter will not have a material adverse effect on the Company's financial position or results of operations. On February 17, 1998, the Company filed an action in the Superior Court of California, Sonoma County, seeking injunctive and declaratory relief to prevent PG&E from unilaterally assigning the Company's steam sales contract to the prospective winning bidder in PG&E's recently announced auction of its power plants in The Geysers. On January 14, 1998, PG&E filed an application with the CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it seeks authorization to sell five electric generating plants and related assets. Included in this proposed sale are The Geysers Geothermal Power Plants (including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric generating plants. In PG&E's 851 Filing, PG&E announced its intention to assign its rights and to delegate its duties under the Company's steam contract to the successful third party purchaser of the Unit 13 and Unit 16 Power Plants. The Company has been informed by PG&E that it will attempt to make such assignment and delegation without first seeking and obtaining the approval and consent of the Company. The Company is challenging the continued validity of the price term of the steam sales contract following the proposed divestiture by PG&E of 98% of its fossil fueled steam-electric generating plants, as the price term of the steam sales contract is based on a complex formula that reflects PG&E's weighted average cost of fossil and nuclear fuel from the preceding year. In a related action, the Company has filed a protest with the CPUC which raises issues similar to those addressed in the above-referenced lawsuit and, in addition, challenges certain inaccuracies contained in F-39 93 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 portions of PG&E's 851 Filings related to Unit 13 and Unit 16. As no discovery has been conducted in either matter, nor has any answer been filed in the lawsuit, the Company is unable to predict the outcome of these cases. An action was filed against Lockport Energy Associates, L.P. ("LEA") on August 7, 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 the FERC and the New York Public Service Commission ("NYPSC"), to modify contract rates to be paid to the Lockport Power Plant. On October 14, 1997, NYPSC, a named defendant in the NYSEG action, filed a cross-claim alleging that the FERC violated PURPA and the Federal Power Act by failing to reform the NYSEG contract which was previously approved by the NYPSC. LEA continues to vigorously defend this action, although it is unable to predict the outcome of this case. The Company retains the right to require 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. In the event the NYSEG's action is successful, the Company may choose to exercise its right to require BUG to purchase its interest in the Lockport Power Plant. 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. As of December 31, 1997, TNP has withheld approximately $5.4 million related to transmission charges and has continued to withhold approximately $450,000 per month thereafter. CLC filed a petition for declaratory order with the Texas Public Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas PUC declare that TNP's withholding is in error. This matter is pending before the Texas PUC. In addition, as of December 31, 1997, TNP has withheld approximately $4.4 million of standby power charges and has continued to withhold approximately $270,000 per month thereafter. CLC has filed a lawsuit in Texas against TNP claiming that TNP is in breach of certain provisions of the power sales agreement, including the provisions involved in the disputes described above, and is seeking in excess of $15.0 million in damages. A trial is scheduled to begin on June 1, 1998. The Company is unable to predict the outcome of either of these proceedings. 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. F-40 94 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 17. EARNINGS PER SHARE The Company adopted SFAS No. 128 as of December 31, 1997. The reconciliation of the numerators and denominators of the basic and diluted earnings per share computation are as follows:
INCOME SHARES PER SHARE (NUMERATOR) (DENOMINATOR) AMOUNT FOR THE YEAR 1995 ----------- ------------- --------- BASIC EARNINGS PER SHARE Income available to common stockholders............ $ 7,378 10,388 $ 0.71 ======= Common shares issuable upon exercise of stock options using treasury stock method.............. -- 569 ------- ------- DILUTED EARNINGS PER SHARE Income available to common stockholders plus assumed conversions.............................. $ 7,378 10,957 $ 0.67 ======= ======= ======= FOR THE YEAR 1996 BASIC EARNINGS PER SHARE Income available to common stockholders............ $18,692 12,903 $ 1.45 ======= Common shares issuable upon exercise of stock options using treasury stock method.............. -- 886 Common shares outstanding assumed conversion of preferred stock (1).............................. -- 1,090 ------- ------- DILUTED EARNINGS PER SHARE Income available to common stockholders plus assumed conversion............................... $18,692 14,879 $ 1.26 ======= ======= ======= FOR THE YEAR 1997 BASIC EARNINGS PER SHARE Income available to common stockholders............ $34,699 19,946 $ 1.74 ======= Common shares issuable upon exercise of stock options using treasury stock method.............. -- 1,070 ------- ------- DILUTED EARNINGS PER SHARE Income available to common stockholders plus assumed conversions.............................. $34,699 21,016 $ 1.65 ======= ======= =======
Basic earnings per share for the year ended December 31, 1996 was computed using the weighted average number of common shares outstanding. Diluted earnings per share was computed using the weighted average number of common and common equivalent shares for outstanding stock options. Options to purchase approximately 385,000 shares of common stock at a weighted average price of $18.00 per share were outstanding during the fourth quarter of 1997. These options were not included in the computation of diluted earnings per share because the options' exercise price was greater than the average market price of common shares. The change in the way the Company previously reported earnings per share for financial reporting purposes is in part due to the adoption of SFAS No. 128 and subsequently, SAB No. 98 on "Computations of Earnings per Share" which became effective in February 1998. 18. 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, 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. F-41 95 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 The Company's common stock has been traded on the New York stock exchange since September 19, 1996. There were 45 common stockholders of record at December 31, 1997. No dividends were paid for the years ended December 31, 1997 and 1996.
QUARTER ENDED ------------------------------------------------------- DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 30 ------------- -------------- --------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1997 Total revenue..................................... $76,441 $92,905 $67,744 $39,231 Income from operations............................ $27,154 $43,384 $24,379 $ 2,270 Net income (loss)................................. $10,192 $19,147 $ 9,400 $(4,040) Basic earnings per share.......................... $ 0.51 $ 0.96 $ 0.47 $ (0.20) Diluted earnings per share........................ $ 0.48 $ 0.91 $ 0.45 $ (0.20) Common stock price per share High............................................ $ 21.25 $ 22.94 $ 20.88 $ 22.75 Low............................................. $ 12.38 $ 16.50 $ 15.75 $ 17.13 1996 Total revenue..................................... $61,663 $70,897 $50,321 $31,673 Income from operations............................ $14,303 $29,097 $16,203 $ 7,188 Net income (loss)................................. $ 3,537 $10,732 $ 4,717 $ (294) Basic earnings per share.......................... $ 0.18 $ 0.95 $ 0.45 $ (0.03) Diluted earnings per share........................ $ 0.17 $ 0.76 $ 0.35 $ (0.03) Common stock price per share High............................................ $ 20.00 $ 16.38 $ -- $ -- Low............................................. $ 16.00 $ 16.00 $ -- $ --
F-42 96 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS We have audited in accordance with generally accepted auditing standards, the consolidated financial statements of Calpine Corporation and subsidiaries included in this Form 10-K and have issued our report thereon dated February 10, 1998. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index of financial statement schedules are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state 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 10, 1998 (except for Note 5 as to which the date is February 17, 1998) F-43 97 CALPINE CORPORATION SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS DECEMBER 31, 1997 AND 1996 (IN THOUSANDS)
1997 1996 ASSETS -------- -------- Current assets: Cash and cash equivalents................................. $(55,070) $ 33,150 Accounts receivable from related parties.................. 6,164 4,534 Accounts receivable....................................... 2,168 5,024 Other current assets...................................... 714 1,603 -------- -------- Total current assets.............................. (46,024) 44,311 Property, plant and equipment, net.......................... 6,617 5,711 Investments in power projects............................... 246,090 141,816 Intercompany receivables.................................... 632,188 302,230 Notes receivable from related parties....................... -- 18,182 Deferred charges............................................ 16,282 8,326 Other assets................................................ 133 122 -------- -------- Total assets...................................... $855,286 $520,698 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.......................................... $ 11,699 $ 504 Accrued payroll and related expenses...................... 4,208 3,477 Accrued interest payable.................................. 17,960 6,462 Other current liabilities................................. 3,409 5,385 -------- -------- Total current liabilities......................... 37,276 15,828 Senior Notes................................................ 560,041 285,000 Deferred income taxes, net.................................. 18,013 11,230 Deferred revenue............................................ -- 5,513 -------- -------- Total liabilities................................. 615,330 317,571 Stockholders' equity: Common stock, $0.001 par value............................ 20 20 Additional paid-in capital................................ 167,542 165,412 Retained earnings......................................... 72,394 37,695 -------- -------- Total stockholders' equity........................ 239,956 203,127 -------- -------- Total liabilities and stockholders' equity........ $855,286 $520,698 ======== ========
The accompanying notes are an integral part of these condensed financial statements. F-44 98 CALPINE CORPORATION SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS)
1997 1996 1995 -------- -------- -------- Revenue: Service contract revenue from related parties............ $ 43,936 $ 36,582 $ 28,733 Income from unconsolidated investments in power projects.............................................. 103,898 66,625 32,397 -------- -------- -------- Total revenue.................................... 147,834 103,207 61,130 Cost of revenue: Service contract expenses................................ 42,014 34,953 27,433 -------- -------- -------- Gross profit............................................... 105,820 68,254 33,697 Project development expenses............................... 7,537 3,867 3,087 General and administrative expenses........................ 16,968 13,651 8,081 -------- -------- -------- Income from operations........................... 81,315 50,736 22,529 Interest expense........................................... 40,790 23,036 10,479 Interest income............................................ (11,470) (4,313) (71) Other (income) expense..................................... (1,164) 4,257 (306) -------- -------- -------- Income before provision for income taxes......... 53,159 27,756 12,427 Provision for income taxes................................. 18,460 9,064 5,049 -------- -------- -------- Net income....................................... $ 34,699 $ 18,692 $ 7,378 ======== ======== ======== Basic earnings per common share: Weighted average shares of common stock outstanding...... 19,946 12,903 10,388 Basic earnings per common share.......................... $ 1.74 $ 1.45 $ 0.71 Diluted earnings per common share: Weighted average shares of common stock outstanding...... 21,016 14,879 10,957 Diluted earnings per common share........................ $ 1.65 $ 1.26 $ 0.67
The accompanying notes are an integral part of these condensed financial statements. F-45 99 CALPINE CORPORATION SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS)
1997 1996 1995 --------- --------- --------- Net cash used in operating activities................... $(360,783) $(281,828) $ (8,997) --------- --------- --------- Cash flows from investing activities: Acquisition of property, plant and equipment.......... (1,316) (5,321) (368) Investments in power projects......................... (4,172) -- (1,262) Decrease (increase) in notes receivable, net.......... 11,500 2,750 (10,337) --------- --------- --------- Net cash provided by (used in) investing activities..... 6,012 (2,571) (11,967) --------- --------- --------- Cash flows from financing activities: Payment of dividend................................... -- -- (800) Borrowings from line of credit........................ 14,300 46,861 14,000 Repayment of borrowings under line of credit.......... (14,300) (60,861) -- Proceeds from Senior Notes............................ 275,041 180,000 -- Proceeds from issuance of preferred stock............. -- 50,000 -- Proceeds from issuance of common stock................ 1,022 109,208 -- Financing costs....................................... (9,512) (5,688) 279 --------- --------- --------- Net cash provided by financing activities..... 266,551 319,520 13,479 --------- --------- --------- Net increase (decrease) in cash and cash equivalents.... (88,220) 35,121 (7,485) Cash and cash equivalents, beginning of period.......... 33,150 (1,971) 5,514 --------- --------- --------- Cash and cash equivalents, end of period................ $ (55,070) $ 33,150 $ (1,971) ========= ========= ========= Cash paid during the period for: Interest.............................................. $ 19,218 $ 19,763 $ 9,945 Income taxes.......................................... $ 9,795 $ 6,947 $ 4,294
The accompanying notes are an integral part of these condensed financial statements. F-46 100 CALPINE CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS DECEMBER 31, 1997, 1996 AND 1995 1. ORGANIZATION AND OPERATION OF CALPINE Calpine Corporation ("Calpine"), a Delaware Corporation, is engaged in the development, acquisition, ownership and operation of power generation facilities in the United States. Calpine has ownership interests in and operates geothermal steam fields, geothermal power generation facilities, and natural gas-fired cogeneration facilities through subsidiaries and investees. In July 1996, Calpine's Board of Directors authorized the reincorporation of Calpine in Delaware in connection with Calpine's initial public offering. In addition, the Board of Directors approved a stock split of approximately 5.194-for-1. In September 1996, the reincorporation of Calpine and the stock split became effective. The accompanying financial statements reflect the reincorporation and the stock split as if such transactions had been effective for all periods. For the purposes of these registrant-only financial statements, Calpine's wholly-owned subsidiaries are accounted for under the equity method and are included in investments in power projects in the accompanying balance sheets. These financial statements should be read in conjunction with Calpine Corporation and Subsidiaries Consolidated Financial Statements. 2. SENIOR NOTES On July 8, 1997, the Company issued $200.0 million aggregate principal amount of 8 3/4% Senior Notes Due 2007. Transaction costs of $9.7 million incurred in connection with the debt offering were capitalized and are included in Other assets and are amortized over the ten-year life of the 8 3/4% Senior Notes Due 2007. On September 10, 1997, the Company issued an additional $75.0 million aggregate principal amount of 8 3/4% Senior Notes Due 2007. The net proceeds were for general corporate purposes. In May and June 1997, the Company executed five interest rate hedging transactions related to debt. The notional value of the debt was $182.0 million and was 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 aggregate principal amount after the hedging transactions and the amortization of transaction costs was 9.1%. The 8 3/4% Senior Notes Due 2007 will mature on July 15, 2007. The Company has no sinking fund or mandatory redemption obligations with respect to the 8 3/4% Senior Notes Due 2007. Interest is payable semi-annually on January 15 and July 15 of each year while the 8 3/4% Senior Notes Due 2007 are outstanding, commencing on January 15, 1998. Based on the traded yield to maturity, the approximate fair market value of the 8 3/4% Senior Notes Due 2007 was $280.5 million as of December 31, 1997. On May 16, 1996, the Company issued $180.0 million aggregate principal amount of 10 1/2% Senior Notes Due 2006. Transaction costs of $5.1 million incurred in connection with the public debt offering were recorded as other assets and are amortized over the ten-year life of the 10 1/2% Senior Notes Due 2006. The effective interest rate of the $180.0 million aggregate principal amount after the amortization of transaction costs was 10.7%. The 10 1/2% Senior Notes Due 2006 will mature on May 15, 2006. The Company has no sinking fund or mandatory redemption obligations with respect to the 10 1/2% Senior Notes Due 2006. Interest is payable semi-annually on May 15 and November 15. Based on the traded yield to maturity, the approximate fair market value of the 10 1/2% Senior Notes Due 2006 was $196.2 million as of December 31, 1997. F-47 101 CALPINE CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997, 1996 AND 1995 The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. The Company has no sinking fund or mandatory redemption obligations with respect to the 9 1/4% Senior Notes Due 2004. Interest is payable semi-annually on February 1 and August 1. Based on the traded yield to maturity, the approximate fair market value of the 9 1/4% Senior Notes Due 2004 was $108.7 million as of December 31, 1997. The effective interest rate on the $105.0 million aggregate principal amount after amortization of transaction costs was 9.6%. The Senior Note indentures specify that the Company maintains certain covenants with which the Company was in compliance. The Company may, under certain circumstances, be limited in its ability to make restricted payments, as defined, which include dividends and certain purchases and investments, incur additional indebtedness and engage in certain transactions. 3. NOTES RECEIVABLE In May 1993, in accordance with the Sumas Cogeneration, L.P. ("Sumas") partnership agreement, the Company was entitled to receive a distribution of $1.5 million and Sumas Energy, Inc. ("SEI"), the Company's partner in Sumas, was required to make a capital contribution of $1.5 million. In order to meet SEI's $1.5 million capital contribution requirement, the Company loaned $1.5 million to the sole shareholder of SEI, who in turn loaned the funds to SEI, who in turn contributed the capital to Sumas. The interest rate on the loan was 20% and was secured by a security interest in the loan between SEI and its sole shareholder. The Company received all principal plus accrued interest totaling $2.8 million in 1997. In March 1994, the Company loaned $10.0 million to the sole shareholder of SEI. The interest rate on the loan was 16.25%. The loan was secured by a pledge to Calpine of SEI's interest in Sumas. The Company deferred the recognition of interest income from these notes until Sumas generated net income. In September 1997, the Company entered into a loan agreement with SEI's sole shareholder wherein the Company agreed to make available a line of credit up to $15.0 million, the proceeds of which are required to be used to develop a new project. SEI has guaranteed the payment and performance of obligations under this agreement and borrowings under the agreement will be collateralized by the new project and the sole shareholder's 100% interest in SEI. The loan agreement will expire on December 31, 2003. During 1997, the $10.0 million loan was sold to a third party. The Company received all unpaid principal and interest related to both loans and recognized a total of $6.9 million of the interest income during 1997 (of which $3.5 million was previously deferred). In addition, the Company recorded a $1.1 million gain upon the sale of the $10.0 million loan, which was recorded in Other (income) expense. In 1996, the Company recognized $2.1 million of interest income related to the above two loans, which represents the portion of Sumas' earnings not recognized by the Company related to its equity investment in Sumas. 4. REVOLVING CREDIT FACILITY AND LINE OF CREDIT At December 31, 1997 and 1996, Calpine had a $50.0 million credit facility available with a consortium of commercial lending institutions which include The Bank of Nova Scotia, ING U.S. Capital Corporation, Sumitomo Bank of California and Canadian Imperial Bank of Commerce. As of December 31, 1997, the Company had no borrowings and $9.4 million of letters of credit outstanding. This amount reflects $6.0 million to secure performance with the Clear Lake Power Plant, $1.5 million to secure performance under a purchase power agreement, and $1.9 million related to operating expenses at Calpine Monterey Cogeneration Inc., ("CMCI"). At December 31, 1996, Calpine had no borrowings and $5.9 million of letters of credit outstanding, which reflected $3.0 million to secure performance with the Pasadena Power Plant and $2.9 million related to operating expenses at CMCI. Borrowings bear interest at The Bank of Nova Scotia's base rate plus an applicable margin or at the London Interbank Offered Rate ("LIBOR") plus an applicable margin. Interest is paid on the last day of each interest period for such loans, but not less often than quarterly, F-48 102 CALPINE CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997, 1996 AND 1995 based on the principal amount outstanding during the period for base rate loans, and on the last day of each applicable interest period, but not less often than 90 days, for LIBOR loans. The credit agreement expires in September 1999. The credit agreement specified that Calpine maintain certain covenants with which Calpine was in compliance. Commitment fees related to this line of credit are charged based on 0.50% of committed unused credit. At December 31, 1997 and 1996, Calpine had a loan facility with available borrowings totaling $1.2 million. As of December 31, 1997, Calpine had no borrowings and $74,000 of letters of credit outstanding. There were no borrowings and $900,000 of letters of credit outstanding as of December 31, 1996. 5. COMMITMENTS AND CONTINGENCIES Office and Equipment Leases -- The Company leases its corporate office, Santa Rosa office facilities and certain office equipment under noncancellable operating leases expiring through 2002. Future minimum lease payments under these leases are (in thousands). 1998...................................... $1,409 1999...................................... 1,211 2000...................................... 1,128 2001...................................... 564 2002...................................... 114 Thereafter.................................. -- ------ $4,426 ======
Lease payments are subject to adjustments for the Company's pro rata portion of annual increases or decreases in building operating costs. In 1997, 1996, and 1995, rent expenses for noncancellable operating leases amounted to $1.2 million, $1.0 million and $733,000, respectively. Regulation and CPUC Restructuring -- Electricity and steam sales agreements with Pacific Gas and Electric Company ("PG&E") are regulated by the California Public Utilities Commission ("CPUC"). In December 1995, the CPUC issued a decision which proposed the transition of the regulated electric generation market to a competitive generation market beginning January 1, 1998. Since the proposed restructure represented a widespread impact on the market structure requiring participation and oversight of the Federal Energy Regulatory Commission ("the FERC"), the CPUC sought and built a California consensus coalition which resulted in filings at the FERC which permitted the CPUC and the FERC to collectively proceed with implementation of the new competitive market structure. In late 1996, comprehensive legislation, (AB 1890 (the "Bill")), was signed into California law which adopted the basic tenets of the CPUC electric industry restructure decision and directed the CPUC to proceed with implementation of restructure with customer choice of electricity supplier available no later than January 1, 1998. The Bill provided for market power mitigation by utility divestiture of fossil generation plants, provided a four year transition period for utility recovery of stranded costs, provided for sanctity of existing contracts with provision for voluntary restructure, established an electricity rate freeze for the four year transition period, mandated a 10% rate reduction beginning January 1, 1998 and continuing through the transition period for small commercial and residential customers financed by issuance of rate reduction bonds, and provided specified funds for continued public service programs including public interest research and development and enhancement of in-state renewable energy resources, which includes geothermal operations. In late 1997 the CPUC and FERC issued decisions which provided for the January 1, 1998 implementation of the California Independent Systems Operator ("ISO"), responsible for centralized control and reliable operation of the state-wide electric transmission grid, and the Power Exchange ("PX"), responsible for the competitive electric energy auction. In late 1997, CPUC-approved sales of certain utility-owned fossil generation plants were completed and applications were pending at the CPUC for sales of the remaining utility-owned F-49 103 CALPINE CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997, 1996 AND 1995 California fossil and geothermal power plants. Investor-owned utilities, though transferring control to the ISO, will continue to own and collect revenue from their transmission facilities and will continue to be regulated utility distribution companies ("UDC") for all electric service providers with default electric supplier responsibility. In December 1997, mechanics for operation of the ISO and PX were not yet fully perfected and implementation of deregulation was delayed to April 1, 1998. The California Energy Commission ("CEC") was directed by the Bill to develop a competitive mechanism for allocation and distribution of funds made available for public interest research and development and enhancement of in-state renewable resources. The CEC in late 1997 issued its draft guidelines for selective allocation and distribution of the funds which are to be available over the four year transition period to a fully competitive electric services industry. Though Calpine believes that implementation of electric industry restructure can provide significant opportunity for independent power producers, the ultimate impact of both increased competition and the changing regulatory environment on Calpine's future results from operations is uncertain. A domestic electricity generating project must be a qualifying facility ("QF") under FERC regulations in order to take advantage of certain rate and regulatory incentives provided by the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). PURPA exempts owners of QFs from the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions of the Federal Power Act ("FPA") and state laws concerning rate or financial regulation. PURPA also requires that electric utilities purchase electricity generated by QFs at a price based on the utility's "avoided cost", and that the utility sell back-up power to the QF on a non-discriminatory basis. If one of the projects in which Calpine has 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 laws and could result in Calpine inadvertently becoming a public utility holding company. Calpine believes that each of the electricity generating projects in which Calpine owns an interest currently meets the requirements under PURPA necessary for QF status. LITIGATION -- 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. All the defendants has filed motions to dismiss such claims, which are currently pending. Calpine believes that the claims of Indeck are without merit and that the resolution of this matter will not have a material adverse effect on its financial position or results of operations. On February 17, 1998, Calpine filed an action in the Superior Court of California, Sonoma County, seeking injunctive and declaratory relief to prevent PG&E from unilaterally assigning Calpine's steam sales contract to the prospective winning bidder in PG&E's recently announced auction of its power plants in The Geysers. On January 14, 1998, PG&E filed an application with the CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it seeks authorization to sell five electric generating plants and related assets. Included in this proposed sale are The Geysers Geothermal Power Plants (including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric generating plants. In PG&E's 851 Filing, PG&E F-50 104 CALPINE CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997, 1996 AND 1995 announced its intention to assign its rights and to delegate its duties under Calpine's steam contract to the successful third party purchaser of the Unit 13 and Unit 16 Power Plants. Calpine has been informed by PG&E that it will attempt to make such assignment and delegation without first seeking and obtaining the approval and consent of Calpine. Calpine is challenging the continued validity of the price term of the steam sales contract following the proposed divestiture by PG&E of 98% of its fossil fueled steam-electric generating plants, as the price term of the steam sales contract is based on a complex formula that reflects PG&E's weighted average cost of fossil and nuclear fuel from the preceding year. In a related action, Calpine and CGC have filed a protest with the CPUC which raises issues similar to those addressed in the above-referenced lawsuit and, in addition, challenges certain inaccuracies contained in portions of PG&E's 851 Filings related to Unit 13 and Unit 16. As no discovery has been conducted in either matter, nor has any answer been filed in the lawsuit, Calpine is unable to predict the outcome of these cases. An action was filed against Lockport Energy Associates, L.P. ("LEA") on August 7, 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 the Federal Energy Regulatory Commission (the "FERC") and the New York Public Service Commission ("NYPSC"), to modify contract rates to be paid to the Lockport Power Plant. On October 14, 1997, NYPSC, a named defendant in the NYSEG action, filed a cross-claim alleging that the FERC violated PURPA and the Federal Power Act by failing to reform the NYSEG contract which was previously approved by the NYPSC. LEA continues to vigorously defend this action, although it is unable to predict the outcome of this case. Calpine retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase Calpine's interest in the Lockport Power Plant for $18.9 million, less equity distributions received by Calpine, at any time before December 19, 2001. In the event the NYSEG's action is successful, Calpine may choose to exercise its right to require BUG to purchase its interest in the Lockport Power Plant. 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. As of December 31, 1997, TNP has withheld approximately $5.4 million related to transmission charges and has continued to withhold approximately $450,000 per month thereafter. CLC filed a petition for declaratory order with the Texas Public Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas PUC declare that TNP's withholding is in error. This matter is pending before the Texas PUC. In addition, as of December 31, 1997, TNP has withheld approximately $4.4 million of standby power charges and has continued to withhold approximately $270,000 per month thereafter. CLC has filed a lawsuit in Texas against TNP claiming that TNP is in breach of certain provisions of the power sales agreement, including the provisions involved in the disputes described above, and is seeking in excess of $15.0 million in damages. A trial is scheduled to begin on June 1, 1998. Calpine is unable to predict the outcome of either of these proceedings. Calpine and its affiliates are involved in various other claims and legal actions arising out of the normal course of business. Calpine does not expect that the outcome of these proceedings will have a material adverse effect on their financial position or results of operations, although no assurance can be given in this regard. F-51 105 CALPINE CORPORATION SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS (IN THOUSANDS) FOR THE YEAR ENDED DECEMBER 31, 1997
ADDITIONS -------------------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING OF COSTS AND OTHER END OF DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD ----------- ------------ ---------- ---------- ---------- ---------- Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $(1,600) $ 238 Allowance for uncollectible accounts....... 238 -- -- -- 238
FOR THE YEAR ENDED DECEMBER 31, 1996
ADDITIONS -------------------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING OF COSTS AND OTHER END OF DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD ----------- ------------ ---------- ---------- ---------- ---------- Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $ -- $ 1,838(1) Allowance for uncollectible accounts....... 238 -- -- -- 238
FOR THE YEAR ENDED DECEMBER 31, 1995
ADDITIONS -------------------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING OF COSTS AND OTHER END OF DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD ----------- ------------ ---------- ---------- ---------- ---------- Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $ -- $ 1,838(1) Allowance for uncollectible accounts....... 238 -- -- -- 238
- --------------- (1) Provision for write-off of project development expenses. F-52 106 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, 1997 and 1996, and the related consolidated statements of income, changes in partners' deficit, and cash flows for each of the three years ended December 31, 1997. 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, 1997 and 1996, and the results of their operations and cash flows for each of the three years ended December 31, 1997, in conformity with generally accepted accounting principles. MOSS ADAMS LLP Everett, Washington January 22, 1998 F-53 107 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY CONSOLIDATED BALANCE SHEET ASSETS
DECEMBER 31, ---------------------------- 1997 1996 ------------ ------------ Current assets Cash and cash equivalents................................. $ 208,776 $ 317,196 Current portion of restricted cash and cash equivalents... 6,094,892 5,787,121 Accounts receivable....................................... 4,502,790 4,605,135 Prepaid expenses.......................................... 181,048 220,130 ------------ ------------ Total current assets.............................. 10,987,506 10,929,582 Restricted cash and cash equivalents,....................... 6,214,000 15,666,647 Property, plant and equipment, at cost, net................. 90,459,854 91,737,933 Other assets................................................ 10,819,238 10,938,732 ------------ ------------ Total assets...................................... $118,480,598 $129,272,894 ============ ============ LIABILITIES AND PARTNERS' EQUITY Current liabilities Accounts payable and accrued liabilities.................. 2,780,693 2,988,207 Related party distributions and payables.................. 490,676 476,390 National Energy Systems Company payable................ 1,415 1,490 Partner distributions.................................. 1,736,612 3,517,491 Current portion of long-term debt......................... 4,200,000 3,600,000 ------------ ------------ Total current liabilities......................... 9,209,396 10,583,578 Long-term debt, net of current portion...................... 129,200,004 113,400,003 Future removal and site restoration costs................... 731,184 679,600 Deferred income taxes....................................... 396,926 988,400 Commitments................................................. -- -- Partners' equity (deficit).................................. (21,056,912) 3,621,313 ------------ ------------ Total liabilities and partners' equity............ $118,480,598 $129,272,894 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-54 108 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, -------------------------------------------- 1997 1996 1995 ------------ ------------ ------------ Revenues Power sales.................................... $ 38,309,558 $ 43,488,465 $ 30,603,018 Natural gas sales, net......................... 2,483,862 434,611 893,690 Other.......................................... -- 169,146 29,146 ------------ ------------ ------------ Total revenues......................... 40,793,420 44,092,222 31,525,854 ------------ ------------ ------------ Costs and expenses Operating and production costs................. 11,211,812 16,852,253 18,493,245 Depletion, depreciation and amortization....... 6,898,111 5,702,310 6,965,496 General and administrative..................... 1,949,365 2,481,470 1,400,129 ------------ ------------ ------------ Total costs and expenses............... 20,059,288 25,036,033 26,858,870 ------------ ------------ ------------ Income from operations........................... 20,734,132 19,056,189 4,666,984 ------------ ------------ ------------ Other income (expense) Interest income................................ 1,190,133 406,537 490,071 Interest expense............................... (10,782,823) (10,678,618) (11,006,056) Other expense.................................. (68,258) (133,958) (60,664) ------------ ------------ ------------ Total other expense.................... (9,660,948) (10,406,039) (10,576,649) ------------ ------------ ------------ Income (loss) before provision for income taxes.......................................... 11,073,184 8,650,150 (5,909,665) Provision for income taxes....................... 525,642 (155,951) (188,387) ------------ ------------ ------------ Net income (loss)...................... $ 11,598,826 $ 8,494,199 $ (6,098,052) ============ ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-55 109 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 Partners' Equity, December 31, 1994......................... $ 5,523,136 Net loss.................................................... (6,098,052) ------------ Partners' Deficit, December 31, 1995........................ (574,916) Net income.................................................. 8,494,199 Distributions to partners................................... (4,297,970) ------------ Partners' Equity, December 31, 1996......................... 3,621,313 Net income.................................................. 11,598,826 Distributions to partners................................... (36,277,051) ------------ Partners' Deficit, December 31, 1997........................ $(21,056,912) ============
The accompanying notes are an integral part of these consolidated financial statements. F-56 110 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, -------------------------------------------- 1997 1996 1995 ------------ ------------ ------------ Cash flows from operating activities Net income (loss).............................. $ 11,598,826 $ 8,494,199 $ (6,098,052) Adjustments to reconcile net income (loss) to net cash from operating activities Depletion, depreciation and amortization.... 6,898,111 6,571,522 6,965,496 Deferred income taxes....................... (591,474) 80,600 134,000 Change in operating assets and liabilities accounts receivable....................... 102,345 (1,514,922) 1,017,993 Prepaid expenses............................ 39,082 2,698 9,497 Accounts payable and accrued liabilities.... (155,930) 1,114,029 (1,407,621) Related party distributions and payables.... 14,211 (437,524) 425,479 ------------ ------------ ------------ Net cash from operating activities..... 17,905,171 14,310,602 1,046,792 ------------ ------------ ------------ Cash flows from investing activities Decrease (increase) in restricted cash and cash equivalents................................. 9,144,876 (10,498,126) 2,908,466 Acquisition of property, plant and equipment... (3,772,579) (913,970) (3,710,025) Other assets................................... (1,727,958) -- -- ------------ ------------ ------------ Net cash from investing activities..... 3,644,339 (11,412,096) (801,559) ------------ ------------ ------------ Cash flows from financing activities Repayment of long-term debt.................... (3,600,000) (2,000,000) (400,000) Proceeds from long-term debt................... 20,000,000 -- -- Distributions to partners...................... (38,057,930) (780,479) -- ------------ ------------ ------------ Net cash from financing activities..... (21,657,930) (2,780,479) (400,000) ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents.................................... (108,420) 118,027 (154,767) Cash and cash equivalents, beginning of year..... 317,196 199,169 353,936 ------------ ------------ ------------ Cash and cash equivalents, end of year........... 208,776 317,196 199,169 ------------ ------------ ------------ Supplementary disclosure of cash flow information Cash paid for interest during the year......... $ 10,782,823 $ 10,678,618 $ 11,006,056 ============ ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-57 111 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1997 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 June 30, 2001, representing 20% of forecasted cash flows. 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). 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 with off-sales to third parties. The Generation Facility also receives 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 stated price includes a fixed and a variable component. The fixed and variable components are stated amounts per kilowatt hour in each contract year. The variable component is adjusted annually based on an index of inflation. 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 1997, the Generation Facility was displaced approximately six months. 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:
YEAR ENDED DECEMBER 31, KILOWATT HOURS ------------ -------------- 1997..................... 439,370,000 1996..................... 1,031,900,000 1995..................... 1,026,000,000
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 (see 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 1997, all preferential distributions were fully paid and the Partnership Agreement was amended. 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 of a stated amount equal to 20% of forecasted cash flows F-58 112 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997 for the period through June 30, 2001. After Whatcom has received cumulative distributions representing a fixed rate-of-return of 24.5% on its equity investment, exclusive of certain of the preferential distributions referred to above, 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, 1997, distributions totaling $36,277,051 were paid or accrued. On January 30, 1998, the December 31, 1997 accrued distributions in the amount of $1,736,612 will be paid. For the year ended December 31, 1996, distributions totaling $4,297,970 were paid or accrued. On January 31, 1997, the December 31, 1996 accrued distributions in the amount of $3,517,491 were paid. No distributions were paid or accrued for the year ended December 31, 1995. 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 include estimated future costs of dismantlement and abandonments of ENCO of $3,560,000 in 1997, $3,718,000 in 1996 and $3,748,000 in 1995. 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 $168,000 in 1997, $177,000 in 1996 and $193,000 in 1995 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. F-59 113 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997 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 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. 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: Organization, start-up and development costs... 5 - 30 years Financing costs................................ 10 - 15 years Gas contract costs............................. 20 years
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 1996 amounts have been reclassified to conform with the 1997 presentation. 2. PROPERTY, PLANT AND EQUIPMENT
1997 1996 ------------ ------------ Land and land improvements.............. $ 381,071 $ 381,071 Plant and equipment..................... 84,888,500 84,152,257 Acquisition of gas properties, including development thereon................... 28,691,894 25,838,035 Furniture and fixtures.................. 221,394 211,116 ------------ ------------ 114,182,859 110,582,479 Less accumulated depreciation and depletion............................. 23,723,005 18,844,546 ------------ ------------ Total.............................. $ 90,459,854 $ 91,737,933 ============ ============
Depreciation expense was $3,188,859 in 1997, $3,159,774 in 1996 and $3,316,748 in 1995. Depletion expense was $1,861,800 in 1997, $1,606,000 in 1996 and $1,843,000 in 1995. F-60 114 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997 3. OTHER ASSETS
1997 1996 ------------ ------------ Organization, start-up and development costs.... $ 4,568,404 $ 4,844,015 Financing costs............................... 4,394,946 3,909,886 Gas contract costs............................ 1,855,888 2,184,831 ------------ ------------ Total................................. $ 10,819,238 $ 10,938,732 ============ ============
4. LONG-TERM DEBT The Partnership and ENCO have loan agreements with The Prudential Insurance Company of America ("Prudential") and Credit Suisse First Boston ("Credit Suisse"), (collectively, "the Lenders"). Through September 1996, Credit Suisse was an affiliate of Whatcom. On September 30, 1997, the Partnership entered into a new additional loan agreement with the Lenders, the Secured Subordinated Loan (the Subordinated Loan) and made certain minor amendments to its existing Term Loans. The Subordinated Loan provided an additional $20 million in loans and a $1 million line of credit facility. At December 31, 1997 and 1996, amounts outstanding under the loan agreements, by entity, were as follows:
1997 1996 ------------ ------------ Sumas Cogeneration Company, L.P. Term Loan............................. $ 89,926,204 $ 92,781,003 Sumas Cogeneration Company, L.P. Subordinated Loan..................... 20,000,000 -- ENCO Gas, Ltd........................... 23,473,800 24,219,000 ------------ ------------ 133,400,004 117,000,003 Less current portion.................... 4,200,000 3,600,000 ------------ ------------ Total......................... $129,200,004 $113,400,003 ============ ============
Scheduled annual principal payments under the loan agreements as of December 31, 1997 are as follows:
YEAR ENDING DECEMBER 31, AMOUNT ------------ ------------ 1998......................... $ 4,200,000 1999......................... 5,400,000 2000......................... 6,900,000 2001......................... 12,600,000 2002......................... 15,000,000 Thereafter................... 89,300,004 ------------ Total.............. $133,400,004 ============
The Partnership's loans are comprised of the Term Loans and the Subordinated Loans. The Subordinated Loans were entered into on September 30, 1997. The Partnership's Term Loans are comprised of a fixed rate loan in the original amount of $55,510,000 and a variable rate loan in the original amount of $39,650,000. Interest is payable quarterly on the fixed rate loan at a rate of 10.35%. Interest on the variable rate loan 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 0.5% to 1.25% as stated in the loan agreement. During the year ended December 31, 1997, interest rates on the variable rate loan ranged from 6.66% to 7.31%. The Term Loans mature in May 2008. The Partnership's Subordinated Loans are comprised of a fixed rate loan in the original amount of $12,000,000, a variable rate loan in the original amount of $8,000,000 and a Revolving Line of Credit in the F-61 115 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997 amount of $1,000,000. Interest is payable quarterly on the fixed rate loan at a rate of 7.85%. Interest is payable monthly on the variable rate loan at either the LIBOR, certificate of deposit rate or Credit Suisse's base rate, plus an applicable margin which ranges from 1.00% to 1.75%. During the period from September 30, 1997 to December 31, 1997, interest rates on the variable rate Subordinated Loan ranged from 7.16% to 7.19%. The Subordinated Loans mature in May 2008. The Revolving Line of Credit is renewable annually at the discretion of the Lenders and is to be used for working capital purposes. Interest is payable monthly at either the LIBOR, certificate of deposit rate or Credit Suisse's base rate, plus an applicable margin which ranges from 1.00% to 1.75%. Through December 31, 1997 no borrowings were made under the Revolving Line of Credit. ENCO's loans are comprised of a fixed rate loan in the original amount of $14,490,000 and a variable rate loan in the original amount of $10,350,000. Interest is payable quarterly on the fixed rate loan at a rate of 9.99%. Interest on the variable rate loan is payable monthly at either the LIBOR, certificate of deposit rate or Credit Suisse's base rate, plus an applicable margin which ranges from .5% to 1.25% as stated in the loan agreement. During the year ended December 31, 1997, interest rates on the variable rate loan ranged from 6.66% to 7.31%. The loans mature in May 2008. 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:
1997 1996 1995 --------- -------- -------- Current Federal large corporation tax............. $ 30,708 $ 41,340 $ 34,625 British Columbia capital taxes............ 35,124 34,011 19,762 65,832 75,351 54,387 Deferred.................................. (591,474) 79,744 135,400 (525,642) 155,095 189,787 Utilization of loss carryforwards for Canadian income tax purposes............ -- -- 47,700 Reduction of (increase) in Canadian loss carryforwards due to foreign exchange and other adjustments................... -- 856 (49,100) --------- -------- -------- $(525,642) $155,951 $188,387 ========= ======== ========
F-62 116 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997 The principal sources of temporary differences resulting in deferred tax assets and liabilities are as follows:
1997 1996 ----------- ----------- Deferred tax asset Canadian net operating loss carryforwards........... $(1,906,396) $ (919,400) Deferred tax liabilities Acquisition and development costs of gas Deducted for tax purposes in excess of amounts...................................... -- -- Deducted for financial reporting purposes...... 2,303,322 1,907,800 ----------- ----------- Net deferred tax liability................ $ 396,926 $ 988,400 =========== ===========
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:
1997 1996 1995 ----------- ----------- ----------- Canadian statutory rate............. 44.62% 44.62% 44.62% Income taxes based on statutory rate.............................. $ (887,037) $ (45,824) $ (33,852) Capital taxes, net of deductible portion........................... 49,710 60,175 47,028 Non-deductible provincial royalties, net of resource allowance......... 216,931 123,464 95,671 Depletion on gas properties with no tax basis......................... 33,436 36,488 44,641 Foreign exchange adjustments........ 63,931 16,362 14,860 Other............................... (2,613) (35,570) 21,439 ----------- ----------- ----------- $ (525,642) $ 155,095 $ 189,787 =========== =========== ===========
As of December 31, 1997, ENCO has non-capital loss carryforwards of approximately $4,273,000, which may be applied against taxable income of future periods which expire as follows: 1999........................... $1,518,000 2000........................... 233,000 2003........................... 244,000 2004........................... 2,278,000
6. RELATED PARTY TRANSACTIONS AND COMMITMENTS Administrative services -- As managing partner of the Partnership, SEI receives a fee of $250,000 per year through December 1995 and $300,000 per year for periods after December 1995. The fee is subject to annual adjustment based upon an inflation index. Approximately $333,000 in 1997, $311,000 in 1996 and $258,000 in 1995 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 $400,000, 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 agreements. This agreement expires on the date Whatcom receives its 24.5% cumulative return or the tenth F-63 117 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997 anniversary of the Project completion date, subject to renewal terms. Approximately $2,074,000 in 1997, $2,014,000 in 1996 and $2,031,000 in 1995 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 $9,000 in 1996 and $19,000 in 1995. 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 $119,000 in 1997, $107,000 in 1996 and $100,000 in 1995 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 12,000 mmbtu's of natural gas per day which may be increased to 24,000 mmbtu's per day in accordance with the agreement. 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 has a gas supply agreement with Engage Energy Canada, L.P. ("Engage") to provide the Partnership with 12,850 mmbtu per day of firm gas. The gas supply agreement with Engage will terminate on October 31, 1998. The Partnership and ENCO have a gas management agreement with 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, 1997 and 1996, 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 $3,553,000 in 1997, $3,526,000 in 1996 and $2,569,000 in 1995. Future minimum capacity commitments at December 31, 1997 are as follows:
YEAR ENDING DECEMBER 31, AMOUNT ------------ ----------- 1998............................ $ 2,848,000 1999............................ 5,619,000 2000............................ 2,939,000 2001............................ 2,978,000 2002............................ 2,939,000 Thereafter...................... 11,048,000 ----------- Total................. $28,371,000 ===========
F-64 118 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997 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, 1997 and 1996, the letter of credit had a face amount of approximately $384,000 (Canadian). Utility services -- The Partnership has an agreement for utility services with the City of Sumas, Washington. The City of Sumas has agreed to provide a guaranteed supply of water at its wholesale rate charged to external association customers. Should the Partnership fail to purchase the daily average minimum of 550 gallons per minute from the City of Sumas during the first 10 years of commercial operation, except for uncontrollable forces or reasonable and necessary shutdowns, the Partnership shall make up the lost revenue to the City of Sumas in accordance with the agreement. During 1997, the Partnership obtained a $700,000 letter of credit in favor of the City of Sumas to support a future sewer charge which will be payable to the City of Sumas. The City of Sumas is undertaking a sewer expansion project which will allow the Generation Facility to discharge its cooling tower blowdown water into the City's sewer system. The sewer expansion is expected to be completed in late 1998. When sewer service commences, the Partnership will be obligated to pay a water discharge capacity payment of approximately $12,000 per month. The Partnership 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 one cent per gallon. The agreement expires on December 31, 1998. 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 1997, $56,600 in 1996 and $48,400 in 1995. 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 $19,000 in 1997, $20,400 in 1996 and $17,700 in 1995. Future minimum land and office lease commitments as of December 31, 1997 are as follows:
YEAR ENDING DECEMBER 31, AMOUNT ------------ ---------- 1998.................................. $ 71,500 1999.................................. 71,500 2000.................................. 74,700 2001.................................. 61,300 2002.................................. 55,700 Thereafter............................ 756,800 ---------- Total....................... $1,091,500 ==========
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 LIBOR plus 3.5% and are due in full on December 31, 2003. As of December 31, 1997, no borrowings had been made under the loan. F-65 119 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 1997 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. The Company is not able to estimate the fair value of its debt with a carrying amount of $133,400,004 and $117,000,003 at December 31, 1997 and 1996, 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. F-66 120 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION OF DOCUMENT ------- ------------------------------------------------------------ 27 Exhibit Index
EX-27 2 FINANCIAL DATA SCHEDULE
5 The Schedule contains summary financial information extracted from Calpine Corporation's Consolidated Balance Sheet as of December 31, 1997 and from the Consolidated Statement of Operations for the twelve months ended December 31, 1997 and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1997 JAN-01-1997 DEC-31-1997 48,513 0 42,805 0 6,015 166,578 868,111 148,390 1,380,956 178,586 742,934 0 0 20 239,936 1,380,956 237,277 276,321 144,701 153,308 0 0 61,466 53,159 18,460 34,699 0 0 0 34,699 1.74 1.65
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