-----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, DSxHNGwRHgWK02fZ/qQJrx86u8MCgDbBDxW7gvNLTQVHOIEwDfm7zRdc0kqrc0lj s5oknp4yvd/JXFm+woY9gA== 0000891618-97-001499.txt : 19970401 0000891618-97-001499.hdr.sgml : 19970401 ACCESSION NUMBER: 0000891618-97-001499 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970331 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: 1934 Act SEC FILE NUMBER: 001-12079 FILM NUMBER: 97568636 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 THE YEAR ENDED DECEMBER 31, 1996 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 [FEE REQUIRED] FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 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, $0.01 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 21, 1997: $367.6 million Common stock outstanding as of March 21, 1997: 19,869,219 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 1997 Annual Meeting of Shareholders:.................................................... Part III (Items 10, 11, 12 and 13) ================================================================================ 2 CALPINE CORPORATION FORM 10-K ANNUAL REPORT FOR THE YEAR ENDED DECEMBER 31, 1996 TABLE OF CONTENTS
PAGE ----- PART I ITEM 1. Business................................................................ 1 ITEM 2. Properties.............................................................. 33 ITEM 3. Legal Proceedings....................................................... 34 ITEM 4. Submission of Matters To A Vote of Security Holders..................... 34 PART II ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters... 34 ITEM 6. Selected Financial Data................................................. 34 ITEM 7. Management's Discussion and Analysis of Financial Condition and Results 34 of Operations........................................................... ITEM 8. Financial Statements and Supplementary Data............................. 34 ITEM 9. Changes In and Disagreements with Accountants and Financial 34 Disclosure.............................................................. PART III ITEM 10. Executive Officers, Directors and Key Employees......................... 35 ITEM 11. Executive Compensation.................................................. 35 ITEM 12. Security Ownership of Certain Beneficial Owners and Management.......... 35 ITEM 13. Certain Relationships and Related Transactions.......................... 35 PART IV ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......... 36 Signatures.......................................................................... 43 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. 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 risks and uncertainties 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, and (iii) 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 and its subsidiaries (the "Company" or "Calpine") is engaged in the acquisition, development, 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 interests in 15 power generation facilities and steam fields having an aggregate capacity of 1,047 megawatts. Since its inception in 1984, Calpine has developed substantial expertise in all aspects of electric power generation. The Company's vertical integration has resulted in significant growth over the last five years as Calpine has applied its extensive engineering, construction management, operations, fuel management and financing capabilities to successfully implement its acquisition and development program. During the last five years, Calpine has expanded substantially, from $55.4 million of total assets as of December 31, 1992 to $1.0 billion of total assets as of December 31, 1996. Calpine's revenue for 1996 increased to $214.6 million, representing a compound annual growth rate of 52.6% since 1992. The Company's EBITDA for 1996 increased to $117.4 million (see Item 6. Selected Financial Data). Calpine's strategy is to capitalize on opportunities in the power market through an ongoing program to acquire, develop, own and operate electric generation facilities, as well as marketing power and energy services to utilities and other end users. STRATEGY Calpine's objective is to become a leading power company by capitalizing on emerging market opportunities in the domestic and international 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 Calpine believes provides it with a competitive advantage. By pursuing this strategy, the Company has significantly expanded and diversified its project portfolio. Since 1993, the Company has completed transactions involving five gas-fired cogeneration facilities and two steam fields. As a result of these transactions, the Company has more than doubled its aggregate power generation capacity and substantially diversified its fuel mix. 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, rather than exclusively through long-term power sales agreements. As part of Calpine's initial effort to develop merchant plants, the Company entered into an agreement with Phillips Petroleum Company to develop a gas-fired cogeneration project with a capacity of 240 megawatts. Under this agreement, approximately 90 megawatts of electricity will be sold to the Phillips Houston Chemical Complex, with the remainder to be sold into the competitive market through 1 4 Calpine's power marketing activities. The Company expects that this project will represent a prototype for future merchant plant developments. The development of this project is subject to the satisfaction of various conditions including required approvals. See "Development and Future Projects." 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 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. Continue to develop an integrated power marketing capability. The Company is developing an integrated power marketing capability, conducted through its wholly owned subsidiary, Calpine Power Services Company ("CPSC"). In 1995, CPSC received approval from the Federal Energy Regulatory Commission ("FERC") to conduct power marketing activities. The Company believes that a power marketing capability complements its business strategy of providing low cost power generation services. CPSC's power marketing activities will focus on the development of long-term customer service relationships, supported primarily by generating assets that are owned, operated or controlled by Calpine. CPSC will aggregate the Company's own resources, the resources of its customers, power pool resources, and market power supply to provide the customized services demanded by its customers at a competitive price. Selectively expand into international markets. Internationally, the Company intends to utilize its geothermal and gas-fired expertise in selected markets of Southeast Asia and Latin America, where demand for power is rapidly growing and private investment is encouraged. In November 1995, the Company made a loan to Coperlasa, which operates the Cerro Prieto Steam Fields located in Baja California, Mexico. In March 1996, the Company entered into a joint venture agreement to pursue the development of a geothermal resource in Indonesia with an estimated potential capacity in excess of 500 megawatts. Calpine believes that its investments in these projects will effectively position it for future expansion in Southeast Asia and Latin America. DESCRIPTION OF POWER PLANTS The Company has interests in 15 power generation facilities and steam fields with a current aggregate capacity of approximately 1,047 megawatts, consisting of seven natural gas-fired cogeneration power plants with a total capacity of 522 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 458 megawatts. Each of the power generation facilities produces electricity for sale to a utility. 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 natural 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 all power generation facilities in which the Company has an interest, except for the Thermal Power Company Steam Fields and the Cerro Prieto Steam Fields. 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 2 5 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 debt for the project. In order to provide fuel for the gas-fired power generation projects 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 structures 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 projects. 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. See Item 2. Properties. 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 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 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. See "Governmental Regulation." 3 6 The table below sets forth certain information regarding the Company's power generation facilities and steam fields currently in operation. POWER GENERATION FACILITIES
COMMENCEMENT TERM OF POWER NAMEPLATE CALPINE CALPINE NET OF POWER GENERATION CAPACITY INTEREST INTEREST COMMERCIAL UTILITY SALES POWER PLANT TECHNOLOGY (MEGAWATTS)(1) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER AGREEMENT - --------------- ------------- -------------- ------------ ----------- ------------ -------------- --------- Sumas Gas-Fired Puget Sound Cogeneration 125 75%(2) 93.8 1993 Power & Light 2013 King City Gas-Fired Pacific Gas & Cogeneration 120 100% 120 1989 Electric 2019 Gilroy Gas-Fired Pacific Gas & Cogeneration 120 100% 120 1988 Electric 2018 Greenleaf 1 Gas-Fired Pacific Gas & Cogeneration 49.5 100% 49.5 1989 Electric 2019 Greenleaf 2 Gas-Fired Pacific Gas & Cogeneration 49.5 100% 49.5 1989 Electric 2019 Agnews Gas-Fired Pacific Gas & Cogeneration 29 20% 5.8 1990 Electric 2021 Watsonville Gas-Fired Pacific Gas & Cogeneration 28.5 100% 28.5 1990 Electric 2009 West Ford Flat Geothermal Pacific Gas & 27 100% 27 1988 Electric 2008 Bear Canyon Geothermal Pacific Gas & 20 100% 20 1988 Electric 2008 Aidlin Geothermal Pacific Gas & 20 5% 1 1989 Electric 2009
STEAM FIELDS
COMMENCEMENT APPROXIMATE CALPINE CALPINE NET OF CAPACITY INTEREST INTEREST COMMERCIAL UTILITY ESTIMATED STEAM FIELD (MEGAWATTS)(3) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER LIFE(4) - ----------- -------------- ------------ ----------- ------------ --------------------- --------- Thermal 151 100% 151 1960 Pacific Gas & 2018 Power Electric Company PG&E Unit 86 100% 86 1980 Pacific Gas & 2018 13 Electric PG&E Unit 82 100% 82 1985 Pacific Gas & 2018 16 Electric SMUDGEO #1 59 100% 59 1983 Sacramento Municipal 2018 Utility District Cerro 80 100%(5) 80 1973 Comision Federal 2000(6) Prieto de Electricidad
- --------------- (1) Nameplate capacity may not represent the actual output for a facility at any particular time. (2) See "Power Generation Facilities -- Sumas Power Plant" for a description of the Company's interest in the Sumas partnership and current sales of power by the Sumas Power Plant. (3) Capacity is expected to gradually diminish as the production of the related steam fields declines. See "Steam Fields." (4) Other than for the Cerro Prieto Steam Fields, 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. See "Steam Fields." (5) 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 Fields. (6) Represents the actual termination of the steam sales agreement. See "Steam Fields -- Cerro Prieto Steam Fields." 4 7 Power Generation Facilities Sumas Power Plant The Sumas cogeneration facility (the "Sumas Power Plant") is a 125 megawatt natural gas-fired, combined cycle 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. The Company currently holds a 50% interest in Sumas and SEI holds the other 50% interest. At the time the Company receives a 24.5% pre-tax rate of return on its partnership investment in Sumas, the Company's interest will be reduced to 11.33% and SEI's interest will increase to 88.67%. Further, the Company receives an additional 25% of the cash flow of the Sumas Power Plant to repay principal and interest on $11.5 million of loans to the sole shareholder of SEI. A $1.5 million loan bears interest at 20% and matures in 2003 and a $10.0 million loan bears interest at 16.25% and matures in 2004. 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 comprised of an MS 7001EA combined cycle gas turbine manufactured by General Electric Company ("General Electric"), 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%. 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. 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 London Interbank Offered Rate ("LIBOR"), which are amortized over a 15-year period ending in 2008. 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 ------------- ------ ------------- ------ ------------- ------ 1997......... 3.38c 2003......... 6.22c 2009......... 5.40c 1998......... 3.64c 2004......... 6.33c 2010......... 5.49c 1999......... 3.98c 2005......... 6.45c 2011......... 5.58c 2000......... 4.23c 2006......... 6.57c 2012......... 5.58c 2001......... 6.23c 2007......... 5.23c 2013......... 5.58c 2002......... 6.11c 2008......... 5.31c
The variable price component is set according to a scheduled rate set forth in the agreement, which in 1996 was 0.99c per kilowatt hour, and escalates annually by a factor equal to the U.S. Gross National Product Implicit Price Deflator. For 1996, the average price paid by Puget under the power sales agreement was 4.166c 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 5 8 shared with the Sumas Power Plant. In 1996, the Sumas Power Plant's net profit increased by $501,000 as a result of the displacement provision. 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 pounds 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 qualified facility ("QF") status. See "Government Regulation." 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 130 billion cubic feet as of January 1, 1997. 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 million British thermal units per day ("mmbtu/day") to the Sumas Power Plant. The remaining 12,100 mmbtu/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. 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 1996, the Sumas Power Plant generated approximately 1,032,000,000 kilowatt hours of electrical energy and approximately $44.0 million of total revenue. In 1996, the Company recognized income of approximately $6.4 million in accordance with the terms of the Sumas partnership agreement, and recorded revenue of $2.0 million for services performed under the operating and maintenance agreement. King City Power Plant The King City cogeneration power plant (the "King City Power Plant") is a 120 megawatt natural 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/Eriksen 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 and has operated at an average availability of approximately 99%. Electricity generated by the King City Power Plant is sold to Pacific Gas and Electric Company ("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. As-delivered capacity prices are $188 per kilowatt year for 1997 and 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. Through 1998, payments for electrical energy produced are based on 100% of PG&E's avoided cost of energy for the period of January 1 through April 30, and 80% at avoided cost and 20% at fixed prices for the period of May 1 through December 31. The fixed average energy price in effect for 1997 and 1998 under the 6 9 King City power sales agreement is 13.14c per kilowatt hour. Thereafter, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E's then avoided cost of energy (as determined by the California Public Utilities Commission ("CPUC")). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c 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. See "Government Regulation." 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 pursuant to a contract with Chevron U.S.A. Inc. ("Chevron"), expiring June 30, 1997. Natural gas is transported under a firm transportation agreement, expiring June 30, 1997, via a dedicated 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 1996, the King City Power Plant generated approximately 411,977,000 kilowatt hours of electrical energy and approximately $41.5 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. The acquisition of the Gilroy Power Plant was originally financed utilizing a non-recourse project loan 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 (see Note 18 of the Notes to Consolidated Financial Statements). The power plant consists of a General Electric Frame 7 Model EA combustion turbine generator, an AEG-KANIS (ABB) 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 power plant has operated at an average availability of 94%. 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 $188 per kilowatt year for 1997. 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 electrical energy actually delivered during the 7 10 period of dispatchable operation at a price equal to PG&E's avoided cost of energy excluding adders. Thereafter, during the period of baseload operation, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E's then avoided cost of energy. PG&E's avoided cost of energy has varied from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c 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 with 1995 revenues of approximately $24.1 billion. It is necessary to continue to operate the host facility in order to maintain the Gilroy Power Plant's QF status. See "Government Regulation." Natural gas for the Gilroy Power Plant is supplied pursuant to a contract with Amoco Energy Trading Corporation ("Amoco") expiring July 31, 1997. Natural gas is transported under a firm transportation agreement, expiring July 1, 1997. 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. From August 29, 1996 through December 31, 1996, the Gilroy Power Plant generated approximately 231,365,000 kilowatt hours of electrical energy for sale to PG&E and approximately $14.7 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 Greenleaf 1 and 2 Power Plants have a combined natural gas requirement of approximately 22,000 mmbtu/day. The Company, through its wholly owned subsidiary Calpine Fuels Corporation ("Calpine Fuels"), entered into a gas supply agreement with Montis Niger, Inc. ("MNI"), an affiliate of LFC, which owns and operates a local gas field connected to the facilities. On January 31, 1997, the Company purchased the stock of MNI. Calpine Fuels supplements the MNI gas supply with a short-term contract with Coastal Gas Marketing Company, which expires on April 30, 1997. This gas is delivered over PG&E's intrastate pipeline which is directly connected to each facility. The Greenleaf 1 and 2 Power Plants have interruptible transportation agreements with PG&E, expiring in June 1997. Greenleaf 1 Power Plant. The Greenleaf 1 cogeneration facility (the "Greenleaf 1 Power Plant") is a 49.5 megawatt natural 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 power plant has operated at an average availability of approximately 92.5%. 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 8 11 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 1997. 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 a price equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c 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 1996, the Greenleaf 1 Power Plant did not experience curtailment. PG&E may also interrupt or reduce deliveries if necessary to repair its system or because of system emergencies, forced outages, force majeure and compliance with prudent electrical practices. 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. See "Government Regulation." The Greenleaf 1 Power Plant is located on 77 acres owned by the Company near Yuba City, California. For 1996, the Greenleaf 1 Power Plant generated approximately 354,182,000 kilowatt hours of electrical energy for sale to PG&E and approximately $18.1 million in revenue. Greenleaf 2 Power Plant. The Greenleaf 2 cogeneration facility (the "Greenleaf 2 Power Plant") is a 49.5 megawatt natural 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 power plant has operated at an average availability of approximately 96%. 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 1997. 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 a price equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c 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 1996, the Greenleaf 2 Power Plant did not experience curtailment. PG&E may also interrupt or reduce deliveries if necessary to repair its system or because of system emergencies, forced outages, force majeure and compliance with prudent electrical practices. 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. See "Government Regulation." 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. 9 12 For 1996, the Greenleaf 2 Power Plant generated approximately 399,707,000 kilowatt hours of electrical energy for sale to PG&E and approximately $19.3 million in revenue. Agnews Power Plant The Agnews cogeneration facility (the "Agnews Power Plant") is a 29 megawatt natural 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%. 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, 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 1997 and 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, PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c per kilowatt hour. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased under the power sales agreement by 995 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 (which has historically been less than one megawatt per year) 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. See "Government Regulation." 10 13 The supply of natural gas for the Agnews Power Plant is currently provided under a full requirements fuel supply agreement between O.L.S. Energy-Agnews and Amoco Energy Trading Corporation ("Amoco") which expires June 30, 1997. Intrastate transportation is provided under a firm gas transportation agreement with PG&E, expiring in June 1997. 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 had an initial term of six years, expiring on December 31, 1996, and was renewed for an additional six-year term effective January 1, 1997. 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 1996, the Agnews Power Plant generated approximately 205,838,000 kilowatt hours of electrical energy and total revenue of $11.0 million. In 1996, the Company recognized a loss of approximately $190,000 as a result of the Company's 20% ownership interest and recorded revenue of $2.0 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 natural gas-fired, combined cycle 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 power plant has operated at an average availability of approximately 97%. 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 the fixed energy price schedule set forth below, and 99% of the energy will be sold at PG&E's avoided cost of energy. The following schedule sets forth the fixed average energy prices (expressed in cents per kilowatt hour) and the as-delivered capacity prices per kilowatt year through 2000 for energy deliveries under the Watsonville Power Plant power sales agreement:
ENERGY AS-DELIVERED YEAR PRICE CAPACITY PRICE --------------------------------------------------- ------ -------------- 1997............................................... 13.14c $188 1998............................................... 13.90c $188 1999............................................... 13.90c $188 2000............................................... 13.90c $188
Thereafter, PG&E will pay for energy delivered at prices equal to PG&E's avoided cost of energy (as determined by the CPUC), and will pay for as-delivered capacity at the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c per kilowatt hour. 11 14 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 October 1 though April 30. From January 1, 1996 through December 31, 1996, PG&E curtailed energy purchases of 1,290 hours under the power sales agreement. In addition to the sale of electricity to PG&E, during 1996 the Watsonville Power Plant produced and sold steam to two thermal hosts, Norcal Frozen Foods, Inc. ("Norcal") and Farmers Processing, both food processors. In August 1995, Norcal sold its facility to a subsidiary of Dean Foods ("Dean Foods"), which closed the facility on February 9, 1996. The lessor of the Watsonville Power Plant has constructed a water distillation facility on the site of the Watsonville Power Plant to replace the Dean Foods food processing facility. This facility commenced operations in August 1996 and is operated by the Company. It is necessary to continue to operate the host facilities in order to maintain the Watsonville Power Plant's QF status. See "Government Regulation." Amoco is the supplier of natural gas to the Watsonville Power Plant. The Company has negotiated a contract with Amoco which will be effective through June 30, 1997. The Company's current contract is on a month-to-month basis with Amoco. PG&E provides firm gas transportation to the Watsonville Power Plant under a contract expiring June 30, 1997. The Watsonville Power Plant is located on 1.8 acres of land leased from Dean Foods under the terms of a 30-year lease expiring in 2010. For 1996, the Watsonville Power Plant generated approximately 205,942,000 kilowatt hours of electrical energy for sale to PG&E and approximately $10.6 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., and seven production wells and 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%. 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 1997 and 1998 is 13.83c cents per kilowatt hour under the West Ford Flat power sales agreement. Thereafter, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c per kilowatt hour. The Company cannot accurately predict the avoided cost of energy prices that will be in effect at the expiration of the fixed price period under this agreement. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased under this agreement by 1,000 hours. In the event of such curtailment, the Company's results of operations may be materially adversely affected. The Company currently expects the maximum amount of curtailment allowed under the agreement during 1997. The Company believes that the geothermal reserves that supply energy for use by the West Ford Flat Power Plant will be sufficient to operate at full capacity for the entire term of the power sales agreement due 12 15 principally to high reservoir pressures, low projected decline rates, limited development in adjacent areas and the substantial productive acreage dedicated to the West Ford Flat Power Plant. The West Ford Flat Power Plant is located on 267 acres of leased land located in The Geysers. For a description of the leases covering the properties located in The Geysers, see Item 2. Properties. During 1996, the West Ford Flat Power Plant generated approximately 219,849,000 kilowatt hours of electrical energy for sale to PG&E and approximately $31.9 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%. 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 and as-delivered capacity prices through 1998 are 13.83c per kilowatt hour and $188 per kilowatt year, respectively. Thereafter, PG&E will pay for energy delivered at prices equal to PG&E's avoided cost of energy (as determined by the CPUC), and will pay for as-delivered capacity at the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c per kilowatt hour. The Company cannot accurately predict the avoided cost of energy prices that will be in effect at the expiration of the fixed price period under this agreement. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased under this agreement by 1,000 hours. In the event of any such curtailment, the Company's results of operations may be materially adversely affected. The Company currently expects the maximum amount of curtailment allowed under the agreement during 1997. The Company believes that the geothermal reserves for the Bear Canyon Power Plant will be sufficient to operate at full capacity for substantially all of the remaining term of the power sales agreements due principally to high reservoir pressures, low projected decline rates, limited development in adjacent areas and the substantial productive acreage dedicated to the Bear Canyon 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. For a description of the leases covering the properties located at The Geysers, see Item 2. Properties. During 1996, the Bear Canyon Power Plant generated approximately 161,785,000 kilowatt hours of electrical energy and approximately $22.8 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 13 16 interest is held in the form of a 10% general partnership interest in a limited partnership (the "Aidlin 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 99%. 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 prices equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged approximately 2.26c per kilowatt hour. The Company cannot accurately predict the avoided cost of energy that will be in effect at the expiration of the fixed price period under this agreement. Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased under this agreement by 1,000 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 1996, the Aidlin Power Plant generated approximately 167,804,000 kilowatt hours of electrical energy and revenue of $22.3 million. In 1996, the Company recognized revenue of approximately $331,000 as a result of the Company's 5% ownership interest and $4.0 million for services performed under the operating and maintenance agreement. Steam Fields Thermal Power Company Steam Fields The Company acquired Thermal Power Company on September 9, 1994 for a purchase price of $66.5 million. Thermal Power Company 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") owns 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 over 240 production wells, 18 injection wells and 55 miles of steam-transporting pipeline. See Item 2. Properties. The 12 plants have a nameplate capacity of 978 megawatts and currently have the capability to operate at over 600 megawatts. The steam fields commenced commercial operation in 1960. 14 17 The Thermal Power Company Steam Fields produce steam for sale to PG&E under a long-term steam sales agreement. Under this steam sales agreement, the Company is paid on the basis of the amount of electricity produced by the power plants to which steam is supplied. PG&E is obligated to use its best efforts to operate its power plants to maintain monthly and annual steam field capacity. The price paid for steam under the steam sales agreement is determined according to a formula that consists of the average of three indices multiplied by a fixed price of 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 1996 was 1.622c per kilowatt hour. The price for 1997 is expected to be approximately 1.907c per kilowatt hour. In addition, the Company receives a monthly fee for effluent disposal and maintenance. During 1996, such monthly fee was $147,000 per month. In March 1996, the Company 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 the Company and Union Oil with the intent that it be at competitive market prices. The Company 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. Under the steam sales agreement, the Company is required to pay PG&E for the unamortized costs, including site clean-up, removal and abandonment costs, of power plants that are installed but are unused as a result of steam supply deficiency. The offset payments are calculated based upon a fixed amortization schedule for all power plants, which may be adjusted for future capital expenditures, and upon the steam fields' capacity in megawatts. In accordance with the steam sales agreement, the Company makes offset payments at a reduced rate until total offsets calculated since July 1, 1991 equal $15.0 million. Accordingly, the Company's share of offsets in 1996 was $672,000. In approximately 2000 or 2001, when total offsets may exceed $15.0 million, in accordance with the agreement the Company'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). In accordance with the steam sales agreement, PG&E may curtail the power plants which receive steam in order to produce energy from lower cost sources. PG&E is contractually 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. During 1996, the Thermal Power Company Steam Fields experienced curtailment of steam production due to low gas prices and abundant hydro power. The Company receives a monthly fee for PG&E's right to curtail its power plants. Such fee was $13,200 per month during 1996. The steam sales agreement with PG&E terminates two years after the closing of the last operating power plant. In addition, PG&E may terminate the contract earlier with a one-year written notice. If PG&E terminates in accordance with the steam sales agreement, the Company will provide capacity maintenance services for five years after the termination date, and will retain a right of first refusal to purchase the PG&E facilities at PG&E's unamortized cost. Alternatively, the Company may terminate the agreement with a two-year written notice to PG&E. If the Company terminates, PG&E has the right to take assignment of the Thermal Power Company Steam Fields' facilities on the date of termination. In that case, the Company would continue to pay offset payments for three years following the date of termination. Under the steam sales agreement, PG&E may retire older power plants upon a minimum of six-months' notice. The Company is unable to predict PG&E's schedule for the retirement of such power plants, which may change from time to time. If steam is abandoned (i.e., cannot be transported to the remaining plants), the abandoned steam may be delivered for use to other PG&E power plants, subject to existing contract conditions, or to other customers upon closure of a PG&E power plant. The Thermal Power Company Steam Fields currently supply steam sufficient to operate the PG&E power plants at approximately 60% of their combined nameplate capacity. This percentage reflects a decline in productivity since the commencement of operations. While it is not possible to accurately predict long-term 15 18 steam field productivity, the Company has estimated that the current annual rate of decline in steam field productivity of the Thermal Power Company Steam Fields was approximately 9% until 1995, during which year extensive curtailment interrupted the decline trend. The Company expects steam field productivity to continue to decline in the future. The Company plans to work with Union Oil and PG&E to partially offset the expected rate of decline by the development of water injection projects and power plant improvements. During 1996, the PG&E power plants produced 3,208,984,000 kilowatt hours of electrical energy of which the Company's 25% share is 802,246,000 kilowatt hours for approximately $13.1 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. See Item 2. Properties. Unit 13 and Unit 16 have nameplate capacities of 98 and 113 megawatts, respectively, and currently operate at outputs of approximately 86 and 82 megawatts, respectively. The PG&E Unit 13 Steam Field includes 956 acres, 30 production wells, three 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, one injection well, 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 1996 was 0.955c per kilowatt hour. The price for 1997 is expected to be approximately 0.985c 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 63,000,000 kilowatt hours under the steam sales agreement during 1996. The steam sales agreement with PG&E continues in effect for as long as either Unit 13 or Unit 16 remains in commercial operation, which depends on maintaining the productive capacity of the respective steam fields. However, PG&E may terminate the agreement if the quantity, quality or purity of the steam is such that the operation of Unit 13 or Unit 16 becomes economically impractical. The Company currently estimates that the productive capacity of the PG&E Unit 13 and Unit 16 Steam Fields is approximately 22 years. However, no assurance can be given that the operation of either Unit 13 or Unit 16 will not become economically impractical at any time during these periods. The Company is required to supply a sufficient quantity of steam of specified quality to Unit 16. If an insufficient quantity of steam is delivered, the Company may be subject to penalty provisions, including suspension of PG&E's obligation to pay for steam delivered. Specifically, if the Company fails to deliver to Unit 16 in any calendar month a sufficient quantity of steam adequate to operate the power plant at or above a capacity factor of 50%, 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 approximately $10.0 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. 16 19 The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient to operate Unit 13 and Unit 16 at approximately 80% 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 8.7% in 1996. 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. During 1996, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient steam to permit Unit 13 and Unit 16 to produce approximately 1,269,400,000 kilowatt hours of electrical energy and approximately $12.8 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"). See Item 2. Properties. The SMUD power plant has a nameplate capacity of 72 megawatts and currently operates at an output of 59 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 $1.77 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. Based on current estimates and analyses performed by the Company, the Company does not expect SMUD to suspend payments for steam under this provision. The 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 82% of its nameplate capacity. This percentage reflects a decline in the productivity of the SMUDGEO #1 Steam Fields since commencement of operations. Although the SMUDGEO #1 Steam Fields productivity increased in 1995 and did not decline in 1996 (due to curtailment of neighboring plants), the Company expects the SMUDGEO #1 Steam Fields' productivity to decline in the future. During 1996, the SMUDGEO #1 Steam Fields produced approximately 6,835,390 thousand pounds of steam and approximately $14.6 million of revenue. 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 17 20 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 (see Note 8 of the Notes to Consolidated Financial Statements). 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. 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 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. While the Company believes that Coperlasa is in an advantageous position to renegotiate or bid for the right to supply steam over a longer term, there can be no assurance that the steam sales agreement will be extended beyond its current termination date. DEVELOPMENT AND FUTURE PROJECTS The Company is continually engaged in the evaluation of various opportunities for the development and acquisition of additional power generation facilities. However, there is no assurance the Company will be successful in the acquisition or development of power generation projects in the future. See "Risk Factors." Pasadena Cogeneration Project 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 Cogeneration Project"). 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 marketing activities. The Company provided a $3.0 million letter of credit to Phillips to secure the performance under the Energy Project Development Agreement. On December 20, 1996, the Company entered into a credit agreement with ING U.S. Capital Corporation to provide $98.6 million of non-recourse project financing for the Pasadena Cogeneration Project. In accordance with the terms of the agreement, Calpine Corporation, through its wholly owned subsidiaries, Calpine Pasadena Cogeneration, Inc. and Calpine Texas Cogeneration, Inc., contributed $53.1 million in equity to the project. The Company commenced construction in February 1997, with commercial operation scheduled to begin in October 1998. However, there can be no assurances that the Company will be successful in completing any additional power sales agreements or that the anticipated schedule for construction will be met. 18 21 Glass Mountain Geothermal Project Calpine is pursuing the development of a geothermal power project at Glass Mountain, which is located in northern California about 25 miles south of the Oregon border (the "Glass Mountain Project"). Glass Mountain is believed to be the largest undeveloped geothermal resource in the United States. In area, the resource is larger than The Geysers, where approximately 1,200 megawatts of capacity is operating. The Company believes that Glass Mountain has an estimated potential in excess of 1,000 megawatts and is seeking potential customers for the power to be produced by this project. In August 1994, the Company entered into a partnership with Trans-Pacific Geothermal Corporation ("TGC") to construct and operate a 30 megawatt project at Glass Mountain (the "Partnership"). TGC had previously signed a memorandum of understanding ("MOU") with Bonneville Power Administration ("BPA") and the Springfield, Oregon Utility Board ("SUB") to develop the project at Vale, Oregon. BPA and SUB consented on August 25, 1994 to the assignment of the MOU to the Partnership and the relocation of the project to Glass Mountain. The MOU contemplated execution of a 45-year power purchase agreement subject to satisfaction of certain conditions precedent and included an option for an additional 100 megawatts. In December 1996, the Partnership and BPA entered into a settlement agreement which restructured the rights and obligations of the parties. In return for a $12.0 million payment by BPA to the Partnership and the grant by the Partnership to BPA of future options to purchase power at Glass Mountain, the Partnership and BPA terminated the MOU and certain ancillary agreements. In addition, BPA will pay the Partnership additional consideration should certain future events occur related to ongoing environmental review of the Glass Mountain project. Following the settlement with BPA, TGC withdrew from the Partnership (see Note 7 of the Notes to Consolidated Financial Statements). In March 1996, the Company completed the acquisition of certain Glass Mountain geothermal leases. As a result, the Company currently holds an interest in approximately 29,000 acres of federal geothermal leases at Glass Mountain. See Item 2. Properties. Indonesian Geothermal Project Calpine plans to develop geothermal facilities in the Lampung Province of Indonesia, located in southern Sumatra. The geothermal resource at Ulubelu is estimated to have potential capacity in excess of 500 megawatts. The Company anticipates that the facility would sell electricity to Perusahaan Umum Listrik Negara ("PLN"), the state-owned electric company. The first phase of the project is expected to be 110 megawatts. The Company's joint venture partner will be PT. Dharmasatrya Arthasentosa ("DATRA"), a company with interests in coal mining and other ventures. The Company expects that it will be the project's managing partner, with responsibility for the design, construction and operation of the power plant. The ownership structure, as planned, will be a joint venture with DATRA in which the Company would be the managing partner and hold at least a 50% equity interest, and as much as 85% of the project. DATRA would hold up to 50% of the project. In March 1996, the Company and DATRA entered into a joint venture agreement to develop Ulubelu. The Company and DATRA are negotiating with the National Resource Agency Pertamina ("Pertamina") regarding resource development. Deep test well drilling and flow tests by Pertamina are planned during 1997 at Ulubelu. Commercial operation is anticipated in 2001 for the initial phase of the project. There can be no assurances, however, that this transaction will be consummated on these terms, if at all, that the proposed timetable will be met or that commercial operation of these resources will be feasible. 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 19 22 energy which may be produced by such a plant and the ownership of a plant. State utility regulatory commissions must approve the rates and, in some instances, other terms and conditions under which public utilities purchase electric power from independent producers and sell retail electric power. Under certain circumstances where specific exemptions are otherwise unavailable, state utility regulatory commissions may have broad jurisdiction over non-utility electric power plants. Energy producing projects also are subject to federal, state and local laws and administrative regulations which govern the emissions and other substances produced, discharged or disposed of by a plant and the geographical location, zoning, land use and operation of a plant. Applicable federal environmental laws typically have both state and local enforcement and implementation provisions. These environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with such permits and approvals. Federal Energy Regulation PURPA The enactment of the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA") and the adoption of regulations thereunder by FERC provided incentives for the development of cogeneration facilities and small power production facilities (those utilizing renewable fuels and having a capacity of less than 80 megawatts). A domestic electricity generating project must be a QF under FERC regulations in order to take advantage of certain rate and regulatory incentives provided by PURPA. PURPA exempts owners of QFs from the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions of the Federal Power Act (the "FPA") and, except under certain limited circumstances, state laws concerning rate or financial regulation. These exemptions are important to 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 20 23 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 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. See "Public Utility Holding Company Regulation." Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at avoided costs. 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 21 24 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 seven natural 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 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 contract becomes a part of a utility's cost structure (generally reflected in its retail rates), power sales contracts 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 contracts. 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, 22 25 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 by January 1, 1988. 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 January 1, 1998 restructure implementation goal. 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 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, eligibility and phase-in schedule for customer choice (direct access), the continuation of public purpose programs and issues related to issuance of rate reduction bonds. The California Energy Commission ("CEC") and Legislature have responsibility for development of a competitive market mechanism for allocation and distribution of funds made available by the legislation for enhancement of in-state renewable resource technologies and public interest research and development programs. Funds are to be available through the four-year transition period to a fully competitive electric services industry. In addition to the significant opportunity provided for power producers such as Calpine through implementation of customer choice (direct access), the CPUC decision and the AB 1890 restructur- 23 26 ing 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. 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 material compliance with such laws with respect to such facilities. Clean Water Act The Federal Clean Water Act (the "Clean Water Act") establishes rules regulating the discharge of pollutants into waters of the United States. The Company is required to obtain a wastewater and storm water 24 27 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 material compliance with applicable discharge requirements under the Clean Water Act. Resource Conservation and Recovery Act The Resource Conservation and Recovery Act ("RCRA") regulates the generation, treatment, storage, handling, transportation and disposal of solid and hazardous waste. 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 material compliance with such laws. Comprehensive Environmental Response, Compensation, and Liability Act The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA" or "Superfund"), requires cleanup of sites from which there has been a release or threatened release of hazardous substances and authorizes the United States Environmental Protection Agency ("EPA") to take any necessary response action at Superfund sites, including ordering potentially responsible parties ("PRPs") liable for the release to take or pay for such actions. PRPs are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of wastes sent to, a site. As of the present time, 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. COMPETITION The Company competes with independent power producers, including affiliates of utilities, in obtaining long-term agreements to sell electric power to utilities. In addition, utilities may elect to expand or create generating capacity through their own direct investments in new plants. Over the past decade, obtaining a power sales agreement with a utility has become an increasingly more difficult, expensive and competitive process. In the past few years, more contracts have been awarded through some form of competitive bidding. Increased competition also has lowered profit margins of successful projects. The Company believes that the power marketing business represents an opportunity to take advantage of growing competition in the electric power industry. The Company also believes that the power marketing business will be highly competitive. The demand for power in the United States traditionally has been met by utilities constructing large-scale electric generating plants under rate-based regulation. The enactment of PURPA in 1978 spawned the growth of the independent power industry, which expanded rapidly in the 1980s. The initial independent power producers were an entrepreneurial group of cogenerators and small power producers who recognized the potential business opportunities offered by PURPA. This initial group of independents was later joined by larger, better capitalized companies, such as subsidiaries of fuel supply companies, engineering companies, equipment manufacturers and affiliates of other industrial companies. In addition, a number of regulated utilities have created subsidiaries (known as utility affiliates) that compete with independent power producers. Some independent power producers specialize in market "niches," such as a specific technology or fuel (e.g., gas-fired cogeneration, geothermal, hydroelectric, refuse-to-energy, wind, solar, coal and wood), or a specific region of the country where they believe they have a market advantage. The Company presently conducts its operations primarily in the United States and concentrates on gas-fired and geothermal cogeneration plants. The Company is the second largest producer of geothermal energy in the United States. Although the Company is an established leader in the geothermal power industry and has been rapidly growing, most of the Company's competitors have significantly greater capital, financial and operational resources. 25 28 Recent amendments to PUHCA made by the Energy Policy Act of 1992 are likely to increase the number of competitors in the independent power industry by reducing certain restrictions currently applicable to certain projects that are not QFs under PURPA. However, the recent amendments also should make it simpler for the Company to develop new projects itself, for example, by enabling the Company to develop large, gas-fired generation projects without the necessity of locating its projects in the vicinity of a steam host or otherwise finding a steam host to accept the useful thermal output required of a cogeneration facility under PURPA. EMPLOYEES As of December 31, 1996, the Company employed 254 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. RISK FACTORS High Leverage The Company is highly 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, 1996, the Company's total consolidated indebtedness was $601.1 million, its total consolidated assets were $1.0 billion and its stockholders' equity was $203.1 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. The Indenture dated as of May 16, 1996 (the "10 1/2% Indenture") relating to the 10 1/2% Senior Notes Due 2006 and the Indenture dated as of February 17, 1994 (the "9 1/4% Indenture") relating to the Company's 9 1/4% Senior Notes Due 2004 (the "9 1/4% Senior Notes") (collectively, the "Indentures" and the "Senior Notes") contain certain restrictive covenants. Such restrictions affect, and in many respects significantly limit or prohibit, among other things, the ability of the Company or its subsidiaries or such other entities, as the case may be, 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 Indentures also contain provisions that require the Company, in the event of a Change of Control Triggering Event (as such term is defined in the Indentures), to make an offer to purchase the Senior Notes. There can be no assurance that the Company will have the financial resources necessary to purchase the Senior Notes upon a Change of Control (as such term is defined in the Indentures). Such Change of Control provisions contained in the Indentures may not be waived by the Board of Directors of the Company. 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 Senior Notes, and to enable the Company to comply with the terms of its 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 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 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. 26 29 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 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. In addition, there can be no assurance that all required governmental permits and approvals for the Company's new or acquired facilities will be obtained, that the Company will be able to obtain favorable power sales agreements and adequate financing, or that the Company will be successful in the development of power generation facilities in the future. Historically, the Company has been successful in obtaining debt financing for its facilities and had relied on Electrowatt Ltd. ("Electrowatt"), formerly the Company's sole stockholder, to provide funding for a substantial portion of its facility equity commitments. Over the past few years, the Company has maintained a $50.0 million credit facility with Credit Suisse (the "Credit Suisse Credit Facility"), which was arranged for the Company by Electrowatt. In connection with the Company's initial public offering of Common Stock in September 1996 (the "Common Stock Offering"), Electrowatt sold all of its shares of Common Stock of the Company and, as a result, the Company will no longer be able to rely on Electrowatt for financing. Upon the completion of the Common Stock Offering, the Credit Suisse Credit Facility was terminated. On September 25, 1996, the Company entered into a $50.0 million three-year revolving credit facility with The Bank of Nova Scotia (the "Bank of Nova Scotia Credit Facility"). The Bank of Nova Scotia 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's power generation facilities have been financed using a variety of leveraged financing structures, primarily consisting of non-recourse debt and lease obligations. As of December 31, 1996, the Company had approximately $601.1 million of total consolidated indebtedness, of which approximately 51% represented non-recourse subsidiary debt. Each non-recourse debt and lease 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 significant 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 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 27 30 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. If the lenders or lessors were to require such guarantees, and the Company were unable to incur indebtedness in respect of such guarantees under the restrictions on indebtedness (including guarantees) contained in the Indentures, the Company's ability to fund new facilities could be adversely affected. The Indentures do not limit the ability of the Company's subsidiaries to incur non-recourse or lease financing for investment in new facilities. Calpine Geysers Company, L.P. ("CGC"), a wholly owned subsidiary of Calpine, owns the West Ford Flat Power Plant, the Bear Canyon Power Plant, the PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields. Calpine Greenleaf Corporation ("Calpine Greenleaf"), a wholly owned subsidiary of Calpine, owns the Greenleaf 1 and 2 Power Plants. The non-recourse facility financing of each of CGC and Calpine Greenleaf is collateralized by all of the assets and properties of each of the facilities and steam fields owned by such subsidiary. In the event of a reduction in revenue derived from one or more of these facilities or steam fields which results in a failure to make any payments on, or if such subsidiary otherwise defaults in its obligations under the terms of, its non-recourse project financing, the lenders would be entitled to foreclose on all of the assets of such subsidiary, including the assets pertaining to each such facility and 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. Impact of Avoided Cost Pricing; Energy Price Fluctuations Nine of the existing power plants in which the Company has an interest sell electricity to PG&E under separate long-term power sales agreements. Each of these agreements provides for both capacity payments and energy payments for the term of the agreement. During the initial ten-year period of certain of the agreements, PG&E pays a fixed price for each unit of electrical energy according to schedules set forth in such agreements. The fixed price periods under these power sales agreements expire at various times in 1998 through 2000. 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 PG&E's then prevailing avoided cost of energy, which is determined and published from time to time by the CPUC. The term "avoided cost" refers to the incremental costs that an electric utility would incur to produce or purchase an amount of power equivalent to that purchased from qualifying facilities (as defined under PURPA). The 28 31 currently prevailing avoided cost of energy is substantially lower than the fixed energy prices under these power sales agreements and is generally expected to remain so. While avoided cost does not affect capacity payments under the power sales agreements, in the event that the avoided cost of energy does not increase significantly, the Company's energy revenue under these power sales agreements would be materially reduced at the expiration of the fixed price period. Such reduction could have a material adverse effect on the Company's results of operations. The Company cannot accurately predict the likely level of avoided cost energy prices at the expiration of the fixed price periods. 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. Impact of Curtailment Each of the Company's power and steam sales agreements contains curtailment provisions pursuant to which the purchasers of energy or steam are entitled to reduce the number of hours of energy or amount of steam purchased thereunder. Curtailment provisions are customary in power and steam sales agreements. During 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 higher levels of energy generation by hydroelectric power facilities that supply electricity. In limited circumstances, energy production from third party geothermal power plants may be curtailed, which would reduce deliveries of steam by the Company under the steam sales agreements. The Company expects maximum curtailment during 1997 under its power sales agreements for certain of its facilities, and there can be no assurance that the Company will not experience curtailment in the future. In the event of such curtailment, the Company's results of operations may be materially adversely affected. 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 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. The Company has grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields such as the Transactions. 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. 29 32 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 all of the power generation facilities and steam fields in which it has an interest, except for two steam fields. 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 in excess of 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 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. 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 1996, approximately 86% and 7% of the Company's total revenue was attributable to revenue received pursuant to power and steam sales agreements with PG&E and Sacramento Municipal Utility District ("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. During 1996, an additional 4% of the Company's revenue was attributable to operating and maintenance services performed by the Company for power generation facilities that sell electricity to PG&E. 30 33 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. International Investments The Company has made an investment in the Cerro Prieto geothermal steam fields located in Mexico and intends to pursue investments primarily in Latin America and Southeast Asia. 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. Power Marketing Business It is part of the Company's strategy to continue to develop an integrated nationwide power marketing business to market power generated both by the Company's generation facilities and power generated by third parties. However, the power marketing industry is only in its early stages of development, and there are no assurances that the industry will develop in such a way as to permit the Company to achieve these goals. Furthermore, the Company has only recently commenced its power marketing business, and there can be no assurance that its power marketing strategy will be successful or that the Company's goals will be achieved. 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 31 34 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. 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. 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 net revenues. 32 35 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 new power sales agreements, and this competition has contributed to a reduction in electricity prices. In this regard, many utilities often engage in "competitive bid" solicitations to satisfy new capacity demands. This competition adversely affects the ability of the Company to obtain power sales agreements and the price paid for electricity. There also is increasing competition between electric utilities, particularly in California where the CPUC and the California legislature have launched an initiative designed to give all electric consumers the ability to choose between competing suppliers of electricity. 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. 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, 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. 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 also maintains a regional office in Santa Rosa, California under a lease that expires in 1999. The Company, through its ownership of CGC and Thermal Power Company, 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 and Thermal Power Company's 25% undivided interest in the Thermal Power Company Steam Fields which are operated by Union Oil. The Company has subleasehold interests in three leases comprising 6,825 acres of federal geothermal resource lands in the Coso area in central California. 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 33 36 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. See "Item 1. Business -- Description of Facilities" for a description of the other material properties leased or owned by the projects in which the Company has ownership interests. The Company believes that its properties are adequate for its current operations. ITEM 3. LEGAL PROCEEDINGS The Company, together with over 100 other parties, was named as a defendant in an action brought in August 1993 by the bankruptcy trustee for Bonneville Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et al., in the United States District Court for the District of Utah (the "Court"). In December 1996, the trustee and the Company entered into a settlement agreement relating to this matter. The trustee has agreed to waive all claims against the Company and to dismiss the trustee's litigation against the Company in exchange for a payment of $767,500 by the Company. The Company is involved in various other claims and legal actions arising out of the normal course of business. Management does not expect that the outcome of these cases will have a material adverse effect on the Company's financial position or results of operations. 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. Calpine Corporation 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. 34 37 ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES Incorporated by reference from Proxy Statement relating to the 1997 Annual Meeting of Shareholders. ITEM 11. EXECUTIVE COMPENSATION Incorporated by reference from Proxy Statement relating to the 1997 Annual Meeting of Shareholders. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Incorporated by reference from Proxy Statement relating to the 1997 Annual Meeting of Shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS CS Holding, a Swiss corporation, holds approximately 44.9% of the outstanding shares of Electrowatt, which, prior to the Common Stock Offering, held all of the outstanding capital stock of the Company. CS Holding also holds (i) approximately 100% of the outstanding shares of Credit Suisse and (ii) approximately 69.3% of the outstanding common stock of CS First Boston, Inc., which holds all of the outstanding common stock of CS First Boston Corporation. CS First Boston Corporation was one of the underwriters of the Company's 9 1/4% Senior Notes issued in February 1994 and was one of the placement agents in the sale of the 10 1/2% Senior Notes Due 2006. CS First Boston was also an underwriter in the Common Stock Offering. In January 1990, O.L.S. Energy-Agnews entered into a credit agreement with Credit Suisse providing for a $28 million loan to finance the construction of the Agnews Power Plant. The Company holds a 20% interest in O.L.S. Energy-Agnews. The loan is collateralized by all of the assets of the Agnews Power Plant and bears interest on the unpaid principal balance based on LIBOR plus a margin rate varying between .50% and 1.50%. After commencement of commercial operation, the Agnews Power Plant was sold to Nynex Credit Corporation under a sale leaseback arrangement with O.L.S. Energy-Agnews and Credit Suisse. Under the sale leaseback, O.L.S. Energy-Agnews entered into a 22-year lease, commencing February 1991, providing for the payment of a fixed base rental, as well as renewal options and a purchase option at the termination of the lease. As of December 31, 1995, O.L.S. Energy-Agnews's outstanding obligation of its sale leaseback arrangement was $37.6 million. In September 1990, the Company obtained a $25.3 million Credit Facility from Credit Suisse. In April 1993, the Credit Suisse Credit Facility was amended to increase the amount of credit available to the Company to $54.0 million. The Credit Suisse Credit Facility was unsecured and bore interest on the amounts outstanding from time to time, if any, at LIBOR plus .50% per annum. During 1994, the Company completed a $105.0 million public debt offering of the 9 1/4% Senior Notes. A portion of the net proceeds were used to repay $52.6 million indebtedness outstanding under the Credit Suisse Credit Facility. On April 21, 1995, the Company entered into the Credit Suisse Credit Facility providing for advances of $50.0 million. On April 29, 1996, the amount of advances available under the Credit Suisse Credit Facility was increased to $58.0 million. A portion of the proceeds of the sale of the 9 1/4% Senior Notes Due 2004 was used to repay outstanding borrowings under the Credit Suisse Credit Facility of approximately $53.7 million on May 16, 1996. The amount of advances available under the Credit Suisse Credit Facility was subsequently restored to $50.0 million. Upon completion of the Common Stock Offering, the Credit Suisse Credit Facility was terminated. In January 1992, Sumas and its wholly owned subsidiary, ENCO, entered into loan agreements with Prudential and Credit Suisse providing for a $120.0 million loan to finance the construction of the Sumas Power Plant and acquisition of associated gas reserves. See "Item 1. Business -- Description of Facilities -- Power Generation Facilities -- Sumas Cogeneration Power Plant." As of December 31, 1996, the outstanding indebtedness of Sumas and ENCO under the term loan was $117.0 million. In December 1994, the Company entered into a Consulting Agreement with Mr. George Stathakis, a Director, which was amended and restated effective June 3, 1996. See the Proxy Statement relating to the 1997 Annual Meeting of Shareholders. 35 38 In January 1995, the Company and Electrowatt entered into a management services agreement, which replaced a prior similar agreement, under which Electrowatt agreed to provide the Company with advisory services in connection with the construction, financing, acquisition and development of power projects, as well as any other advisory services as may be required by the company in connection with the operation of the Company. The Company had agreed to pay Electrowatt $200,000 per year for all services rendered under the management services agreement. Pursuant to this agreement, $166,000 and $200,000 were paid in 1996 and 1995, respectively. Upon completion of the Common Stock Offering, the management services agreement was terminated. In 1995, the Company paid $106,000 to Electrowatt pursuant to a guarantee fee agreement whereby Electrowatt agreed to guarantee the payment when due of any and all indebtedness of the Company to Credit Suisse in accordance with the terms and conditions of the Credit Suisse Credit Facility. Under the guarantee fee agreement, the Company had agreed to pay to Electrowatt an annual fee equal to 1% of the average outstanding balance of the Company's indebtedness to Credit Suisse during each quarter as compensation for all services rendered under the guarantee fee agreement. Upon completion of the Common Stock Offering, the guarantee fee agreement was terminated. In June 1995, Calpine repaid $57.5 million of non-recourse financing to Credit Suisse which was outstanding indebtedness related to the Greenleaf 1 and 2 Power Plants at the time of the acquisition of such facilities. In March 1996, Electrowatt invested $50.0 million in the Company in the form of shares of Preferred Stock, all of which were converted into shares of Common Stock in connection with the Common Stock Offering. 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, 1996 and 1995 Consolidated Statements of Operations for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 Notes to Consolidated Financial Statements for December 31, 1996
36 39 (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, 1996 and 1995 Statements of Operations for the Years Ended December 31, 1996, 1995, and 1994 Statements of Cash Flows for the Years Ended December 31, 1996, 1995, and 1994 Notes to Condensed Financial Statements for December 31, 1996 II Valuation and Qualifying Accounts SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY Independent Auditor's Report Consolidated Balance Sheets, December 31, 1996 and 1995 Consolidated Statements of Operations for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statements of Changes in Partners' Equity for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 Notes to Consolidated Financial Statements for the Years Ended December 31, 1996, 1995 and 1994
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore have been omitted. (A)-3. EXHIBITS The following exhibits are filed herewith unless otherwise indicated:
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)
37 40
EXHIBIT NUMBER DESCRIPTION - -------- ------------------------------------------------------------------------------------ 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) 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. * 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)
38 41
EXHIBIT NUMBER DESCRIPTION - -------- ------------------------------------------------------------------------------------ 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) 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. * 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) 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)
39 42
EXHIBIT NUMBER DESCRIPTION - -------- ------------------------------------------------------------------------------------ 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) 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)
40 43
EXHIBIT NUMBER DESCRIPTION - -------- ------------------------------------------------------------------------------------ 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) 10.11 Form of Indemnification Agreement for directors and officers. (l) 21.1 Subsidiaries of the Company. (m)
- --------------- (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. 41 44 (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. * Filed herewith. (B) REPORTS ON FORM 8-K No reports on Form 8-K were filed during the period from October 1, 1996 to December 31, 1996. 42 45 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 21, 1997 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 21, 1997 - ------------------------------------------ Officer and Chairman of the Peter Cartwright Board (Principal Executive Officer) /s/ ANN B. CURTIS Senior Vice President and March 21, 1997 - ------------------------------------------ Director (Principal Financial Ann B. Curtis Officer) /s/ JEFFREY E. GARTEN Director March 21, 1997 - ------------------------------------------ Jeffrey E. Garten
43 46
SIGNATURE TITLE DATE - ------------------------------------------ --------------------------------- --------------- /s/ SUSAN C. SCHWAB Director March 21, 1997 - ------------------------------------------ Susan C. Schwab /s/ GEORGE J. STATHAKIS Director March 21, 1997 - ------------------------------------------ George J. Stathakis /s/ JOHN O. WILSON Director March 21, 1997 - ------------------------------------------ John O. Wilson /s/ ORVILLE WRIGHT Director March 21, 1997 - ------------------------------------------ V. Orville Wright /s/ GLORIA S. GEE Controller (Principal Accounting March 21, 1997 - ------------------------------------------ Officer) Gloria S. Gee
44 47 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND OTHER INFORMATION DECEMBER 31, 1996
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-11 Consolidated Balance Sheets, December 31, 1996 and 1995............................... F-12 Consolidated Statements of Operations for the Years Ended December 31, 1996, 1995 and 1994................................................................................ F-13 Consolidated Statements of Shareholder's Equity for the Years Ended December 31, 1996, 1995 and 1994....................................................................... F-14 Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994................................................................................ F-15 Notes to Consolidated Financial Statements for the Years Ended December 31, 1996, 1995 and 1994............................................................................ F-16 CALPINE CORPORATION Schedule I: Condensed Financial Information of Registrant Report of Independent Public Accountants............................................ F-41 Condensed Balance Sheets, December 31, 1996 and 1995................................ F-42 Condensed Statements of Operations for the Years Ended December 31, 1996, 1995 and 1994............................................................................. F-43 Condensed Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994............................................................................. F-44 Notes to Condensed Financial Statements for December 31, 1996....................... F-45 Schedule II: Valuation and Qualifying Accounts........................................ F-48 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY Report of Independent Public Accountants.............................................. F-49 Consolidated Balance Sheets, December 31, 1996 and 1995............................... F-50 Consolidated Statement of Income for the Years Ended December 31, 1996, 1995 and 1994................................................................................ F-51 Consolidated Statement of Changes in Partners' Equity for the Years Ended December 31, 1996, 1995 and 1994................................................................. F-52 Consolidated Statement of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994................................................................................ F-53 Notes to Consolidated Financial Statements for the Years Ended December 31, 1996, 1995 and 1994............................................................................ F-54
F-1 48 SELECTED CONSOLIDATED FINANCIAL DATA The consolidated financial data set forth below for and as of the five years ended December 31, 1996 have been derived from the audited consolidated financial statements of the Company. The following selected consolidated financial data should be read in conjunction with the consolidated financial statements and the related notes thereto appearing elsewhere in this report, and "Management's Discussion and Analysis of Financial Condition and Results of Operations."
YEAR ENDED DECEMBER 31, ------------------------------------------------- 1992 1993 1994 1995 1996 ------- ------- ------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) STATEMENT OF OPERATIONS DATA: Revenue: Electricity and steam sales............................ $ -- $53,000 $90,295 $127,799 $199,464 Service contract revenue............................... 29,817 16,896 7,221 7,153 6,455 Income (loss) from unconsolidated investments in power projects............................................. 9,760 19 (2,754) (2,854) 6,537 Interest income on loans to power projects............. -- -- -- -- 2,098 ------- ------- ------- -------- -------- Total revenue........................................ 39,577 69,915 94,762 132,098 214,554 Cost of revenue.......................................... 25,921 42,501 52,845 77,388 129,200 ------- ------- ------- -------- -------- Gross profit............................................. 13,656 27,414 41,917 54,710 85,354 Project development expenses............................. 806 1,280 1,784 3,087 3,867 General and administrative expenses...................... 3,924 5,080 7,323 8,937 14,696 Compensation expense related to stock options (1)........ 1,224 -- -- -- -- Provision for write-off of project development costs (2).................................................... 800 -- 1,038 -- -- ------- ------- ------- -------- -------- Income from operations............................... 6,902 21,054 31,772 42,686 66,791 Interest expense......................................... 1,225 13,825 23,886 32,154 45,294 Other income, net........................................ (310) (1,133) (1,988) (1,895) (6,259) ------- ------- ------- -------- -------- Income before provision for income taxes and cumulative effect of change in accounting principle.......................................... 5,987 8,362 9,874 12,427 27,756 Provision for income taxes............................... 2,527 4,195 3,853 5,049 9,064 ------- ------- ------- -------- -------- Income before cumulative effect of change in accounting principle............................... 3,460 4,167 6,021 7,378 18,692 Cumulative effect of adoption of SFAS No. 109............ -- (413) -- -- -- ------- ------- ------- -------- -------- Net income........................................... $ 3,460 $ 3,754 $ 6,021 $ 7,378 $ 18,692 ======= ======= ======= ======== ======== Primary earnings per share (3) Weighted average shares outstanding............................................ -- 14,680 ======== ======== Primary earnings per share............................. -- $ 1.27 ======== ======== Fully diluted earnings per share (3) Weighted average shares outstanding.................... -- 15,130 ======== ======== Fully diluted earnings per share....................... -- $ 1.24 ======== ======== As adjusted primary earnings per share assuming conversion of preferred stock (3) Weighted average shares outstanding.................... 14,151 -- ======== ======== Primary earnings per share............................. $ 0.52 -- ======== ======== OTHER FINANCIAL DATA AND RATIOS: (in thousands, except ratio data) Depreciation and amortization............................ $ 232 $12,540 $21,580 $ 26,896 $ 40,551 EBITDA (4)............................................... $ 9,898 $42,370 $53,707 $ 69,515 $117,379 EBITDA to Consolidated Interest Expense (5).............. 4.73x 2.98x 2.23x 2.11x 2.41x Total debt to EBITDA................................... 3.70x 6.24x 6.23x 5.87x 5.12x Ratio of earnings to fixed charges (6)................... 3.41x 2.09x 1.52x 1.46x 1.45x
See footnotes on next page) F-2 49
AS OF DECEMBER 31, ------------------------------------------------------------- 1992 1993 1994 1995 1996 ------- -------- -------- -------- ---------- (IN THOUSANDS) BALANCE SHEET DATA: Cash and cash equivalents........... $ 2,160 $ 6,166 $ 22,527 $ 21,810 $ 100,010 Property, plant and equipment, net............................... 424 251,070 335,453 447,751 650,053 Total assets........................ 55,370 302,256 421,372 554,531 1,030,215 Total liabilities................... 44,865 288,827 402,723 529,304 827,088 Stockholders' equity................ 10,505 13,429 18,649 25,227 203,127
- --------------- (1) Represents a non-cash charge for compensation expense associated with the grant of certain options under the Company's stock option program. (2) Represents a write-off of certain capitalized project costs. (3) The weighted average shares outstanding and earnings per share for the year ended December 31, 1996 gave effect to the issuance of common stock upon the conversion of the Company's preferred stock in connection with the Company's initial public offering (see Note 1 of Notes to Consolidated Financial Statements). The presentation of fully diluted earnings per share for the year ended 1996 is not required by Accounting Principles Board Opinion No. 15, because it results in dilution of less than 3%. As adjusted primary earnings per share assuming conversion of preferred stock for the year ended December 31, 1995 is calculated using average shares outstanding, which includes common share equivalents using the treasury stock method and the assumed conversion of preferred stock to common stock as of January 1, 1995 in accordance with Securities and Exchange Commission staff policy. Earnings per share prior to 1995 have not been presented since such amounts are not deemed meaningful due to the significant change in the Company's capital structure that occurred in connection with its initial public offering. (4) 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 either (i) to income from operations (determined in accordance with generally accepted accounting principles) or (ii) to cash flows from operating activities (determined in accordance with generally accepted accounting principles). (5) 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. (6) 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 50 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. 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 risks and uncertainties 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, and (iii) other risks identified from time to time in the Company's reports and registration statements filed with the Securities and Exchange Commission. GENERAL Calpine is engaged in the acquisition, development, 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 interests in 15 power generation facilities and steam fields having an aggregate capacity of 1,047 megawatts. Since its inception in 1984, Calpine has developed substantial expertise in all aspects of electric power generation. The Company's vertical integration has resulted in significant growth over the last five years as Calpine has applied its extensive engineering, construction management, operations, fuel management and financing capabilities to successfully implement its acquisition and development program. During the last five years, Calpine has expanded substantially, from $55.4 million of total assets as of December 31, 1992 to $1.0 billion assets as of December 31, 1996. Calpine's revenue for 1996 increased to $214.6 million, representing a compound annual growth rate of 52.6% since 1992. The Company's EBITDA (see Selected Consolidated Financial Data) for 1996 increased to $117.4 million. On September 9, 1994, the Company acquired Thermal Power Company, which owns a 25% undivided interest in certain steam fields at The Geysers steam fields in northern California ("The Geysers") with a total capacity of 604 megawatts for a purchase price of $66.5 million. In January 1995, the Company purchased the working interest in certain of the geothermal properties at the 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 natural 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 natural gas-fired cogeneration facility, for a 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 120 megawatt King City Power Plant, 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. Each of the power generation facilities produces electricity for sale to a utility. Thermal energy produced by the gasfired 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. Nine of these agreements with Pacific Gas and Electric Company ("PG&E") provides for both capacity payments and energy payments for the term of the agreement. During the initial ten-year period of certain agreements, PG&E pays a fixed price for each unit of electrical energy according to schedules set forth in such agreements. The fixed price periods under these power sales agreements expire at various times in 1998 through 2000. After the fixed price periods expire, F-4 51 while the basis for the capacity and capacity bonus payments under these power sales agreements remains the same, the energy payments adjust to PG&E's then avoided cost of energy, which is determined by the California Public Utilities Commission ("CPUC"). The currently prevailing avoided cost of energy is substantially lower than the fixed energy prices under these power sales agreements and is generally expected to remain so. While avoided cost does not affect capacity payments under the power sales agreements, in the event that the avoided cost of energy does not increase significantly, the Company's energy revenues under these power sales agreements would 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 cannot predict the likely level of avoided cost energy prices at the expiration of the fixed price periods. 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. Each of the Company's power and steam sales agreements contains 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. During 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 facilities that supply electricity. The Company expects maximum curtailment during 1997 under its power and steam sales agreements for certain of its facilities. 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 envisions commencement of deregulation and implementation of customer choice of electricity supplier by January 1, 1998 (see Note 28 of the Notes to Consolidated Financial Statements). As part of its policy decision, the CPUC indicated that power sales agreements of existing qualifying facilities ("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. 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. SELECTED OPERATING INFORMATION Set forth below is certain selected operating information for the power generation facilities and steam fields, for which results are consolidated in the Company's 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 and the Watsonville Power Plant since their acquisitions on April 21, 1995 and June 29, 1995, respectively, the Gilroy Power Plant since its acquisition on August 29,1996, and the King City Power Plant since the effective date of the lease on May 2, 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 1996, the Thermal Power Company Steam Fields since the acquisition of Thermal Power Company 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 West Ford Flat Power Plant, Bear Canyon Power Plant, the PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields in April 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. F-5 52
YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1992 1993 1994 1995 1996 ---------- ---------- ---------- ---------- ---------- (DOLLARS IN THOUSANDS) POWER PLANTS: Electricity revenue (1): Energy............................. $ 38,325 $ 37,088 $ 45,912 $ 54,886 $ 93,851 Capacity........................... $ 7,707 $ 7,834 $ 7,967 $ 30,485 $ 65,064 Megawatt hours produced............ 403,274 378,035 447,177 1,033,566 1,985,404 Average energy price per kilowatt hour (2)........................ 9.503c 9.811c 10.267c 5.310c 4.727c STEAM FIELDS: Steam revenue: Calpine......................... $ 33,385 $ 31,066 $ 32,631 $ 39,669 $ 40,549 Other interest.................. $ 2,501 $ 2,143 $ 2,051 -- -- Megawatt hours produced............ 2,105,345 2,014,758 2,156,492 2,415,059 2,528,874 Average price per kilowatt hour.... 1.705c 1.648c 1.608c 1.643c 1.603c
- --------------- (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 hours since 1994 reflects the increase in the Company's megawatt hour production as a result of acquisitions of gas-fired cogeneration facilities by the Company. RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995 Revenue. Revenue increased 62% to $214.6 million in 1996 compared to $132.1 million in 1995, primarily due to a 56% increase in electricity and steam sales of $199.5 million in 1996 compared to $127.8 million in 1995. The King City Power Plant and the Gilroy Power Plant contributed revenues of $41.5 million and $14.7 million, respectively, to electric and steam sales revenue 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 increases in electric and steam revenue 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 West Ford Flat and Bear Canyon Power Plants. Without such curtailment, the West Ford Flat and Bear Canyon Power Plants would have generated an additional $5.7 million and $5.2 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 Cogeneration Company, L.P. ("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 which F-6 53 was acquired 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 financings. Other income, net. Other income, net increased 232% to $6.3 million for 1996 compared with $1.9 million for 1995. The increase was primarily due to $4.5 million of interest income on collateral securities purchased in connection with the King City transaction, $1.4 million of net proceeds for the settlement of the Coso project, and higher interest income for the period due to the investment of the net proceeds of the preferred stock, the 10 1/2% Senior Notes Due 2006, and from the Company's initial public offering of common shares. Offsetting these income items was a $3.7 million loss for uncollectible amounts related to the O'Brien acquisition project (see Note 13 of Notes to Consolidated Financial Statements). 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 8.84% 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. YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994 Revenue increased 39% to $132.1 million in 1995 compared to $94.8 million in 1994, primarily due to a 42% increase in electricity and steam sales to $127.8 million in 1995 compared to $90.3 million in 1994. Such an increase was primarily attributable to the $28.3 million of revenue from the Greenleaf 1 and 2 Power Plants, $5.9 million of revenue from the Watsonville Power Plant, the $5.2 million of additional revenue from the Thermal Power Company Steam Fields as a result of a full year of operation in 1995, and an increase of $3.0 million of revenue from the SMUDGEO #1 Steam Fields attributable to increased production as a result of an extended outage during 1994. Such an increase also reflects a substantial increase in capacity payments for electricity sales from $8.0 million in 1994 to $30.5 million in 1995 as a result of the transactions stated above. This revenue increase was partially offset by a $2.7 million decrease in revenue from the West Ford Flat and Bear Canyon Power Plants as a result of curtailments by PG&E due to low gas prices and high levels of precipitation during 1995 as compared to 1994, offset in part by contractual price increases for 1995. Without such curtailment, the West Ford Flat and Bear Canyon Power Plants would have generated an additional $5.2 million of revenue in 1995. Revenue for 1995 also reflects curtailment of steam production at the Thermal Power Company Steam Fields as a result of higher precipitation and lower gas prices in 1995, and at the PG&E Unit 13 and Unit 16 Steam Fields as a result of hydro-spill conditions. Without curtailment, the Thermal Power Company Steam Fields and the PG&E Unit 13 and Unit 16 Steam Fields would have generated an additional $5.7 million and $800,000 of revenue during 1995, respectively. F-7 54 Revenue for 1995 and 1994 reflects reversals of $2.7 million and $3.2 million, respectively, of previously deferred revenue. Company revenue from sales of steam was previously calculated considering a future period when steam would be delivered without receiving corresponding revenue. In May 1994, the Company ceased deferring revenue and recognized $4.0 million of its previously deferred revenue. Based on estimates and analyses performed by the Company, the Company no longer expects that it will be required to make these deliveries to SMUD. Concurrently, $800,000 of the revenue increase was reserved for future construction of gathering systems required for future production of the steam fields, with the offset recorded in property, plant and equipment. In October 1995, PG&E agreed to the termination of the free steam provision with respect to the PG&E Unit 13 Steam Fields. During 1995, the Company took additional measures regarding future capital commitments and other actions which will increase steam production and, based on additional analyses and estimates performed, the Company recognized the remaining $2.7 million of previously deferred revenue. Cost of revenue. Cost of revenue increased 47% to $77.4 million in 1995 compared to $52.8 million in 1994. The increase was due to plant operating, production royalty and depreciation and amortization expenses attributable to (i) a full year of operations at Thermal Power Company, which was purchased on September 9, 1994, (ii) operations at the Greenleaf 1 and 2 Power Plants subsequent to April 21, 1995, and (iii) operations at the Watsonville Power Plant subsequent to June 29, 1995. The increases were partially offset by lower depreciation and production royalty expenses at the West Ford Flat and Bear Canyon Power Plants and the PG&E Unit 13 and Unit 16 Steam Fields due to curtailment by PG&E during 1995. Project development expenses. Project development expenses increased to $3.1 million in 1995 compared to $1.8 million in 1994, due to new project development activities. General and administrative expenses. General and administrative expenses were $8.9 million in 1995 compared to $7.3 million in 1994. The increase in 1995 was primarily due to additional personnel and related expenses necessary to support the Company's expanded operations. Interest expense. Interest expense increased to $32.2 million in 1995 from $23.9 million in 1994. Approximately $3.6 million of the increase was attributable to a full year of interest expense incurred on the debt related to the Thermal Power Company acquisition in September 1994 and $4.1 million of interest expense incurred on the debt related to the Greenleaf transaction in April 1995. In addition, 1995 included a full year of interest expense on the 9 1/4% Senior Notes Due 2004 issued on February 17, 1994. Provision for income taxes. The effective rate for the income tax provision was approximately 41% for 1995 and 39% for 1994. The effective rates were based on statutory tax rates, with minor reductions for depletion in excess of tax basis benefits. Due to curtailment of production during 1995, the allowance for statutory depletion decreased in 1995 from 1994. 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 financings. 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, ----------------------------------- 1994 1995 1996 -------- -------- --------- (IN THOUSANDS) Cash flows from: Operating activities.................... $ 34,196 $ 26,653 $ 59,881 Investing activities.................... (84,444) (38,497) (326,834) Financing activities.................... 66,609 11,127 345,153 -------- -------- --------- Total........................... $ 16,361 $ (717) $ 78,200 ======== ======== =========
F-8 55 Operating activities for 1996 consisted of approximately $18.7 million of net income from operations, $36.6 million of depreciation and amortization, $2.0 million in deferred income taxes, and $7.8 million net increase in operating assets and liabilities, offset by $5.3 million of undistributed income from unconsolidated investments in power projects. Investing activities used $326.8 million during 1996, primarily due to $29.9 million of capital expenditures and capitalized project costs, $98.4 million for the purchase of collateral securities, a $12.9 million loan to Coperlasa in connection with the Cerro Prieto project, $138.1 million for the acquisition of the Gilroy Power Plant, and a $41.6 million increase in restricted cash requirements related to the construction of the Pasadena Power Plant. Financing activities provided $345.2 million of cash during 1996. The Company issued $50.0 million of preferred stock to Electrowatt, borrowed $161.8 million of bank debt and an additional $46.9 million under the credit facilities, received net proceeds of $174.9 million from the 10 1/2% Senior Notes Due 2006, and received $109.2 million upon the issuance of common stock. The Company subsequently repaid $46.2 million of bank debt, all borrowings outstanding under the credit facilities of $66.7 million, and $84.7 million of non-recourse project financing. As of December 31, 1996, cash and cash equivalents were $100.0 million and working capital was $96.2 million. For the twelve months ended December 31, 1996, working capital increased by $145.2 million and cash and cash equivalents increased by $78.2 million as compared to the comparable period in 1995. The increase in working capital is primarily due to remaining net proceeds from the issuance of common stock in September 1996, and reflects the inclusion of $57.0 million of non-recourse project financing in current liabilities as of December 31, 1995. On May 16, 1996, the Company issued the 10 1/2% Senior Notes Due 2006. A portion of the funds from the issuance of the 10 1/2% Senior Notes Due 2006 was used to refinance current bank debt and borrowings under the Credit Suisse credit facility, and to repay the $57.0 million non-recourse indebtedness to The Bank of Nova Scotia. As a developer, owner and operator of power generation projects, 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. The Company currently has outstanding $105.0 million of 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 has $180.0 million of 10 1/2% Senior Notes Due 2006 which mature on May 15, 2006 and bear interest semi-annually on May 15 and November 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 include dividends and certain purchases and investments, incur additional indebtedness and engage in certain transactions. At December 31, 1996, the Company had $309.3 million of non-recourse project financing associated with power generating facilities and steam fields at the West Ford Flat Power Plant, the Bear Canyon Power Plant, the PG&E Unit 13 and Unit 16 Steam Fields, the SMUDGEO #1 Steam Fields, the Greenleaf 1 and 2 Power Plants and the Gilroy Power Plant. As of December 31, 1996, the annual maturities for all non-recourse project financing were $30.6 million for 1997, $32.7 million for 1998, $24.2 million for 1999, $24.8 million for 2000, $24.6 million for 2001 and $170.5 million thereafter. 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 LIBOR or at The Bank of Nova Scotia base rate plus a mutually agreed margin. At December 31, 1996, the Company had no borrowings outstanding and $5.9 million of letters of credit outstanding under the revolving credit facility (see Note 16 of Notes to Consolidated Financial Statements). The Bank of Nova Scotia 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 payments of certain indebtedness, pay dividends, make F-9 56 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, 1996, the Company had no borrowings under this working capital line and $900,000 of letters of credit outstanding. Borrowings are at prime plus 1%. The Company also has outstanding a non-interest bearing promissory note to Natomas Energy Company in the amount of $6.5 million representing a portion of the September 1994 purchase price of Thermal Power Company. This note has been discounted to yield 8% per annum and is due September 9, 1997. The Company intends to continue to seek the use of non-recourse project financing for new projects, where appropriate. 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, 1996, the Company had commitments for capital expenditures in 1997 totaling $4.0 million related to various projects at its geothermal facilities. 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. Capital expenditures for 1996 were $30.2 million compared to $17.4 million for 1995, primarily due to the purchase of new equipment. For 1996, capital expenditures included $12.5 million related to the Pasadena Power Plant, $4.0 million for the purchase of geothermal leases for the Glass Mountain project, $3.1 million for the new rotor at the PG&E Unit 13 facility, $3.2 million for geothermal well drilling, $2.1 million for a reinjection pipeline at the Company's geothermal steam fields, and $5.4 million of capital expenditures at various cogeneration facilities. The Company continues to pursue the acquisition and development of new power generation projects. The Company expects to commit significant capital in future years for the acquisition and development of these projects. 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 and 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. IMPACT OF RECENT ACCOUNTING PRONOUNCEMENT In February 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 128, Earnings Per Share, which simplifies the standards for computing earnings per share previously found in Accounting Principles Board Opinion ("APBO") No. 15. SFAS No. 128 replaces the presentation of primary earnings per share with a presentation of basic earnings per share, which excludes dilution. SFAS No. 128 also requires dual presentation of basic and diluted earnings per share on the face of the income statement for all entities with complex capital structures and requires a reconciliation. Diluted earnings per share is computed similarly to fully diluted earnings per share pursuant to APBO No. 15. SFAS No. 128 must be adopted for financial statements issued for periods ending after December 15, 1997, including interim periods; earlier application is not permitted. SFAS No. 128 requires restatement of all prior-period earnings per share data presented. The Company has not yet quantified the effect of adopting SFAS No. 128. F-10 57 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, 1996 and 1995, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1996. 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 and 1995. The Company has recorded income of $6.4 million and losses of $3.0 million and $2.9 million representing its share of the net income or loss of Sumas for the years ended December 31, 1996, 1995 and 1994, 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 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 other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP San Jose, California March 7, 1997 F-11 58 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1996 AND 1995 (IN THOUSANDS)
1996 1995 ---------- -------- ASSETS Current assets: Cash and cash equivalents.......................................... $ 100,010 $ 21,810 Accounts receivable from related parties............................................ 2,826 2,177 from others..................................................... 39,962 17,947 Acquisition project receivables.................................... 791 8,805 Collateral securities, current portion............................. 5,470 -- Interest receivable on collateral securities....................... 1,065 -- Prepaid operating lease............................................ 12,668 -- Other current assets............................................... 8,395 5,491 ---------- -------- Total current assets....................................... 171,187 56,230 Property, plant and equipment, net................................... 650,053 447,751 Investments in power projects........................................ 13,937 8,218 Collateral securities, net of current portion........................ 89,806 -- Notes receivable from related parties................................ 18,182 19,391 Notes receivable from Coperlasa...................................... 17,961 6,394 Restricted cash...................................................... 55,219 9,627 Other assets......................................................... 13,870 6,920 ---------- -------- Total assets............................................... $1,030,215 $554,531 ========== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current portion of non-recourse project financing.................. $ 30,627 $ 84,708 Notes payable and short-term borrowings............................ 6,865 1,177 Accounts payable................................................... 18,363 6,876 Accrued payroll and related expenses............................... 3,912 2,789 Accrued interest payable........................................... 7,332 7,050 Other accrued expenses............................................. 7,870 2,657 ---------- -------- Total current liabilities.................................. 74,969 105,257 Long-term line of credit............................................. -- 19,851 Non-recourse project financing, net of current portion............... 278,640 190,642 Notes payable........................................................ -- 6,348 Senior Notes......................................................... 285,000 105,000 Deferred income taxes, net........................................... 100,385 97,621 Deferred lease incentive............................................. 78,521 -- Other liabilities.................................................... 9,573 4,585 ---------- -------- Total liabilities.......................................... 827,088 529,304 ---------- -------- Commitments and contingencies (Note 28) Stockholders' equity Common stock, $0.01 par value per share; authorized 100,000,000 shares in 1996 and 33,760,000 shares in 1995; issued and outstanding 19,843,400 shares in 1996 and 10,387,693 shares in 1995............................................................ 20 10 Additional paid-in capital......................................... 165,412 6,214 Retained earnings.................................................. 37,726 19,034 Cumulative translation adjustment.................................. (31) (31) ---------- -------- Total stockholders' equity................................. 203,127 25,227 ---------- -------- Total liabilities and stockholders' equity................. $1,030,215 $554,531 ========== ========
The accompanying notes are an integral part of these consolidated financial statements. F-12 59 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1996 1995 1994 -------- -------- ------- Revenue: Electricity and steam sales........................... $199,464 $127,799 $90,295 Service contract revenue.............................. 6,455 7,153 7,221 Income (loss) from unconsolidated investments in power projects........................................... 6,537 (2,854) (2,754) Interest income on loans to power projects............ 2,098 -- -- -------- -------- ------- Total revenue................................. 214,554 132,098 94,762 -------- -------- ------- Cost of revenue: Plant operating expenses.............................. 61,894 33,162 14,944 Depreciation.......................................... 39,818 26,264 21,202 Production royalties.................................. 10,793 10,574 11,153 Operating lease expense............................... 9,295 1,542 -- Service contract expenses............................. 7,400 5,846 5,546 -------- -------- ------- Total cost of revenue......................... 129,200 77,388 52,845 -------- -------- ------- Gross profit............................................ 85,354 54,710 41,917 Project development expenses............................ 3,867 3,087 1,784 General and administrative expenses..................... 14,696 8,937 7,323 Provision for write-off of project development costs.... -- -- 1,038 -------- -------- ------- Income from operations........................ 66,791 42,686 31,772 Other (income) expense: Interest expense Related party...................................... 894 1,663 375 Other.............................................. 44,400 30,491 23,511 Other income, net..................................... (6,259) (1,895) (1,988) -------- -------- ------- Income before provision for income taxes........... 27,756 12,427 9,874 Provision for income taxes............................ 9,064 5,049 3,853 -------- -------- ------- Net income.................................... $ 18,692 $ 7,378 $ 6,021 ======== ======== ======= Earnings per share: Weighted average shares outstanding................... 14,680 -- -- ======== ======== ======= Earnings per share.................................... $ 1.27 -- -- ======== ======== ======= As adjusted earnings per share assuming conversion of preferred stock: Weighted average shares outstanding................... -- 14,151 -- ======== ======== ======= Earnings per share.................................... -- $ 0.52 -- ======== ======== =======
The accompanying notes are an integral part of these consolidated financial statements. F-13 60 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (IN THOUSANDS)
PREFERRED STOCK COMMON STOCK ADDITIONAL CUMULATIVE --------------- --------------- PAID-IN RETAINED TRANSLATION SHARES AMOUNT SHARES AMOUNT CAPITAL EARNINGS ADJUSTMENT TOTAL ------ ------ ------ ------ ---------- -------- ---------- -------- Balance, December 31, 1993.............. -- $ -- 10,388 $ 10 $ 6,214 $ 7,235 $(31) $ 13,428 Dividend ($0.40 per share)............ -- -- -- -- -- (800) -- (800) Net income............................ -- -- -- -- -- 6,021 -- 6,021 ------ ---- ------ --- -------- ------- ---- -------- Balance, December 31, 1994.............. -- -- 10,388 10 6,214 12,456 (31) 18,649 Dividend ($0.40 per share)............ -- -- -- -- -- (800) -- (800) Net income............................ -- -- -- -- -- 7,378 -- 7,378 ------ ---- ------ --- -------- ------- ---- -------- Balance, December 31, 1995.............. -- -- 10,388 10 6,214 19,034 (31) 25,227 Issuance of preferred stock........... 5,000 50 -- -- 49,950 -- -- 50,000 Conversion of preferred stock to common stock........................ (5,000) (50) 2,179 3 47 -- -- -- Issuance of common stock, net......... -- -- 7,276 7 109,172 -- -- 109,179 Tax benefit from stock options exercised........................... -- -- -- -- 29 -- -- 29 Net income............................ -- -- -- -- -- 18,692 -- 18,692 ------ ---- ------ --- -------- ------- ---- -------- Balance, December 31, 1996.............. -- $ -- 19,843 $ 20 $165,412 $37,726 $(31) $203,127 ====== ==== ====== === ======== ======= ==== ========
The accompanying notes are an integral part of these consolidated financial statements. F-14 61 CALPLNE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (IN THOUSANDS)
1996 1995 1994 --------- -------- -------- Cash flows from operating activities: Net income................................................... $ 18,692 $ 7,378 $ 6,021 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization, net......................... 36,600 25,931 20,342 Deferred income taxes, net................................. 2,028 (1,027) 3,180 (Income) loss from unconsolidated investments in power projects................................................ (5,263) 2,854 2,754 Provision for write-off of project development costs and other................................................... -- -- 1,038 Change in operating assets and liabilities: Accounts receivable..................................... (12,652) (3,354) (2,578) Acquisition project receivables......................... 8,014 (8,805) -- Other current assets.................................... (6,521) (737) 79 Accounts payable and accrued expenses................... 15,636 6,847 6,218 Deferred revenue........................................ 3,347 (2,434) (2,858) --------- -------- -------- Net cash provided by operating activities............. 59,881 26,653 34,196 --------- -------- -------- Cash flows from investing activities: Acquisition of property, plant and equipment................. (24,057) (17,434) (7,023) Acquisition of Greenleaf, net of cash on hand................ -- (14,830) -- Watsonville transaction, net of cash on hand................. -- 494 -- Acquisition of TPC, net of cash on hand...................... -- -- (62,770) Loans to Coperlasa........................................... (12,926) (6,062) -- (Increase) decrease in notes receivable...................... 2,750 (286) (13,556) Investment in collateral securities.......................... (98,446) -- -- King City transaction, net of cash on hand................... (11,567) -- -- Maturities of collateral securities.......................... 2,900 -- -- Acquisition of Gilroy, net of cash on hand................... (138,073) -- -- Capitalized project costs.................................... (5,887) (1,258) (175) Decrease (increase) in restricted cash....................... (41,591) 1,186 (900) Other, net................................................... 63 (307) (20) --------- -------- -------- Net cash used in investing activities................. (326,834) (38,497) (84,444) --------- -------- -------- Cash flows from financing activities: Payment of dividends......................................... -- (800) (800) Net borrowings from (repayments of) line of credit........... (19,851) 19,851 (52,595) Borrowings from non-recourse project financing............... 119,760 76,026 60,000 Repayments of non-recourse project financing................. (84,708) (79,388) (12,735) Proceeds from short-term borrowings.......................... 45,000 2,683 4,500 Repayments of short-term borrowings.......................... (46,177) (6,006) -- Proceeds from issuance of Senior Notes....................... 180,000 -- 105,000 Proceeds from issuance of preferred stock.................... 50,000 -- -- Proceeds from issuance of common stock....................... 109,208 -- -- Financing costs.............................................. (8,079) (1,239) (3,921) Proceeds from note payable................................... -- -- 5,167 Repayment of notes payable -- FMRP........................... -- -- (36,807) Other, net................................................... -- -- (1,200) --------- -------- -------- Net cash provided by financing activities............. 345,153 11,127 66,609 --------- -------- -------- Net increase (decrease) in cash and cash equivalents........... 78,200 (717) 16,361 Cash and cash equivalents, beginning of period................. 21,810 22,527 6,166 --------- -------- -------- Cash and cash equivalents, end of period....................... $ 100,010 $ 21,810 $ 22,527 ========= ======== ======== Supplementary information -- cash paid during the year for: Interest..................................................... $ 43,805 $ 32,162 $ 19,890 Income taxes................................................. 6,947 4,294 683
The accompanying notes are an integral part of these consolidated financial statements. F-15 62 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 1. ORGANIZATION AND OPERATIONS OF THE COMPANY Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries (collectively, the "Company") are engaged in the development, acquisition, ownership and operation of power generation facilities in the United States and selected international markets. The Company has ownership interests in and operates geothermal steam fields, geothermal power generation facilities, and natural gas-fired cogeneration facilities in northern California and Washington. Each of the generation facilities produces electricity for sale to utilities. 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. For the year ended December 31, 1996, primarily all electricity and steam sales revenue from consolidated subsidiaries was derived from sales to two customers in northern California (see Note 27), of which 48% related to geothermal activities. In 1996, the Company began marketing power and energy services to utilities and other end users. In July 1996, the Company's Board of Directors authorized the reincorporation of the Company into Delaware in connection with the Company's initial public offering. In addition, the Board of Directors approved a stock split of approximately 5.194-for-1. On September 13, 1996, the reincorporation of the Company 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 (see Note 24). 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation -- The consolidated financial statements include the accounts of Calpine Corporation and its wholly owned and majority-owned subsidiaries. All significant intercompany accounts and transactions are eliminated in consolidation. Prior to 1994, the Company acquired Calpine Geysers Company, L.P. ("CGC"). During 1994, the Company formed Calpine Thermal Power, Inc. ("Calpine Thermal") and Calpine Siskiyou Geothermal Partners, L.P. (see Notes 4 and 7, respectively). Calpine Thermal acquired Thermal Power Company ("TPC") during 1994. During 1995, the Company formed Calpine Greenleaf Corporation ("Calpine Greenleaf"), Calpine Monterey Cogeneration, Inc. ("CMCI") and Calpine Vapor, Inc. ("Calpine Vapor"). Calpine Greenleaf indirectly acquired two operating gas-fired cogeneration plants (see Note 5) and CMCI acquired an operating lease for a gas-fired cogeneration facility (see Note 6). Calpine Vapor made loans to fund construction of new geothermal wells in Mexico (see Note 8). During 1996, the Company formed Calpine King City Cogen L.L.C. ("CKCC"), Calpine Gilroy Cogen, L.P. ("Gilroy"), and Pasadena Cogeneration, L.P. CKCC completed an operating lease transaction for a gas-fired cogeneration plant (see Note 9) and Calpine Gilroy acquired the assets of a gas-fired cogeneration plant in California (see Note 10). In December 1996, Pasadena Cogeneration entered into an energy sales agreement and will construct a 240 megawatt gas-fired power plant (see Note 11). Accounting for Jointly Owned Geothermal Properties -- The Company uses the proportionate consolidation method to account for TPC's 25% interest in jointly owned geothermal properties. TPC has a steam sales agreement with Pacific Gas and Electric Company ("PG&E") pursuant to which the steam derived from its interest in the properties is sold (see Note 4). 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 Note 7), the estimated "free steam" liability (see Note 3), receivables which the Company believes to be collectible (see Note 15) and the realization of deferred income taxes (see Note 21). Additionally, the Company believes that certain industry restructuring F-16 63 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (see Note 28, Regulation and CPUC Restructuring) will not have a material effect on existing power service agreements ("PSA") 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 CGC were entered into prior to May 1992. Had the Company applied this principle, the revenues of the Company recorded for the years ended December 31, 1996, 1995 and 1994, would have been approximately $16.1 million, $12.6 million, and $11.9 million less, respectively. The Company performs operations and maintenance services for all projects in which it has an interest, except for TPC and the geothermal investment in Mexico. Revenue from investees is recognized on these contracts when the services are performed. Revenue from consolidated subsidiaries is eliminated in consolidation. 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. 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 statements of cash flows. Investment in Collateral Securities -- The Company's investments in collateral securities are related to the King City transaction (see Note 9) and 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 lease payment. 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, 1996 are as follows (in thousands):
UNREALIZED AMORTIZED AGGREGATE HOLDING COST FAIR VALUE GAINS --------- ---------- ---------- Debt securities issued by the United States.................................... $54,826 $ 56,737 $1,911 Corporate debt securities................... 40,450 40,499 49 ------- ------- ------ $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 and accounts / notes receivable. The Company's cash accounts are held by eight major financial institutions. The Company's accounts / notes receivable are concentrated within entities engaged in the energy industry, mainly within the United States, some of which are related parties. Certain of the Company's notes receivable are with a company in Mexico (see Note 15). Property, Plant and Equipment -- Property, plant and equipment are stated at cost less accumulated depreciation and amortization. F-17 64 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 Calpine Thermal. Proceeds from the sale of geothermal properties are applied against capitalized costs, with no gain or loss recognized. Geothermal costs, including an estimate of future 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 thirty years. The value of the above-market pricing provided in PSAs acquired is recorded in property, plant and equipment and is amortized over the life of the PSA or operating lease. 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 the results of operations. As of December 31, 1996 and 1995, the components of property, plant and equipment are as follows (in thousands):
1996 1995 -------- -------- Geothermal properties.................................. $297,002 $296,495 Buildings, machinery and equipment..................... 277,572 198,358 Power sales agreement.................................. 145,957 -- Miscellaneous assets................................... 11,287 2,425 -------- -------- 731,818 497,278 Less accumulated depreciation and amortization......... 100,674 60,511 -------- -------- 631,144 436,767 Land................................................... 754 754 Construction in progress............................... 18,155 10,230 -------- -------- Property, plant and equipment, net................... $650,053 $447,751 ======== ========
Investments in Power Projects -- The Company accounts for its unconsolidated investments in power projects under the equity method. The Company's share of income from these investments is calculated according to the Company's equity ownership or in accordance with the terms of the appropriate partnership agreement (see Note 14). Capitalized Project Costs -- The Company capitalizes project development costs upon the execution of a memorandum of understanding or a letter of intent for a power or steam sales agreement. These costs include F-18 65 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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. Earnings Per Share and As Adjusted Earnings Per Share -- For the calendar year ending after the Company's initial public offering in September 1996, net income per share was computed using the weighted average number of common and common equivalent shares using the treasury stock method for outstanding stock options. Net income per share also gives effect to common equivalent shares from convertible preferred shares from the original date of issuance that automatically converted upon completion of the Company's initial public offering (using the if-converted method). For the year ended December 31, 1995, as adjusted net income per share was computed using the weighted average number of common equivalent shares, which includes the net additional number of shares which would be issuable upon the exercise of outstanding stock options, assuming the Company used the proceeds received to purchase additional shares at an assumed public offering price. Net income per share also gives effect to common equivalent shares from preferred stock that converted upon the closing of the Company's initial public offering assuming such shares were outstanding from the beginning of the period in accordance with Securities and Exchange Commission staff policy. Earnings per share prior to 1995 have not been presented since such amounts are not deemed meaningful due to the significant change in the Company's capital structure that occurred in connection with its initial public offering. 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, 1996, CPSC held forward sales and purchase contracts with notional quantities of approximately 724,000 megawatt hours and 631,600 megawatt hours, respectively. Net open positions may exist due to the origination of new transactions and the Company's evaluation of changing market conditions. The open position exposes the Company to the risk that fluctuating market prices may adversely impact its financial position or results of operations. However, the net open position is actively managed. The impact of such fluctuations 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 currently for net aggregate losses of the entire portfolio resulting from the effect of market changes on the net open positions. Net gains are recognized when realized. With respect to open power contracts, CPSC has established certain reserves and allowances, principally for adverse changes in market conditions prior to termination of the commitments. At December 31, 1996, the Company had recorded allowances of approximately $917,000 which is included in Service contract revenue in the accompanying consolidated statement of operations. The Company's credit risk associated with power contracts results from the risk of loss as a result of non-performance by counterparties. The Company reviews and assesses counterparty risk to limit any material impact to its financial position and results of operations. The Company does not anticipate non-performance by the counterparties. The Company sets credit limits prior to entering into transactions and has not obtained collateral or other security. Impact of Recent Accounting Pronouncements -- In March 1995, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. This pronouncement requires that long-lived assets and certain identifiable intangible assets be reviewed for impairment whenever F-19 66 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is to be recognized when the sum of undiscounted cash flows is less than the carrying amount of the asset. Measurement of the loss for assets that the entity expects to hold and use are to be based on the fair market value of the asset. The Company adopted SFAS No. 121 effective January 1, 1996, and determined that adoption of this pronouncement had no material impact on the results of operations or financial condition as of January 1, 1996. In February 1997, the FASB issued SFAS No. 128, Earnings Per Share, which simplifies the standards for computing earnings per share previously found in Accounting Principles Board Opinion ("APBO") No. 15. SFAS No. 128 replaces the presentation of primary earnings per share with a presentation of basic earnings per share, which excludes dilution. SFAS No. 128 also requires dual presentation of basic and diluted earnings per share on the face of the income statement for all entities with complex capital structures and requires a reconciliation. Diluted earnings per share is computed similarly to fully diluted earnings per share pursuant to APBO No. 15. SFAS No. 128 must be adopted for financial statements issued for periods ending after December 15, 1997, including interim periods; earlier application is not permitted. SFAS No. 128 requires restatement of all prior-period earnings per share data presented. The Company has not yet quantified the effect of adopting SFAS No. 128. Reclassifications -- Prior years' amounts in the consolidated financial statements have been reclassified where necessary to conform to the 1996 presentation. 3. CALPINE GEYSERS COMPANY, L.P. CGC, a wholly owned subsidiary of the Company, is the owner of two operating geothermal power plants and their respective steam fields, Bear Canyon and West Ford Flat, and three geothermal steam fields, which provide steam to PG&E's Unit 13 and Unit 16 power plants and to Sacramento Municipal Utility District's ("SMUD") geothermal power plant. The power plants and steam fields are located in The Geysers area of northern California. Electricity from CGC's two operating geothermal power plants is sold to PG&E under 20-year agreements. Under the PG&E Unit 16 and the SMUD agreements, if the quantity of steam delivered is less than 50% of the units' capacities, then neither PG&E nor SMUD is required to make payment for steam delivered during such month until the cost of the affected power plant has been completely amortized. Further, both PG&E and SMUD can terminate their agreements with written notice under conditions specified in the agreement if further operation of the plants becomes uneconomical. In the event that CGC terminates the agreements, PG&E or SMUD may require CGC to assign them all rights, title and interest to the wells, lands and related facilities. In consideration for such an assignment to SMUD, SMUD shall reimburse CGC for its original costs net of depreciation for any associated materials or facilities. CGC revenues from sales of steam were calculated considering a future period when steam would be delivered without receiving corresponding revenue. The estimated "free steam" obligation was recorded at an average rate over future steam production as deferred revenue in 1993. As of December 31, 1993, the Company had deferred revenue of $8.6 million. During 1994, based on estimates and analyses performed, the Company determined that these deliveries would no longer be required for a customer and reversed approximately $5.9 million of its deferred revenue liability. This reversal was recorded as a $1.9 million purchase price reduction to property, plant and equipment, with the remaining $4.0 million as an increase in revenue. Concurrently, $800,000 of the revenue increase was reserved for future construction of gathering systems required for future production of the steam fields, with the offset recorded in property, plant and equipment. In October 1994, PG&E agreed to the termination of the free steam provision for one of the geothermal steam fields. During 1995, CGC took additional measures regarding future capital commitments and other F-20 67 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) actions which will increase steam production and, based on additional analyses and estimates performed, the Company recognized the remaining $2.7 million of previously deferred revenue. On April 19, 1993, the Company acquired Freeport-McMoRan Resource Partners, L.P.'s ("FMRP") interest in CGC for $23.0 million in cash and non-recourse notes payable to FMRP totaling $40.5 million. On February 17, 1994, the Company exercised its option to prepay the notes utilizing a discount rate of 10% by paying $36.9 million including interest in full satisfaction of its obligations under the FMRP notes. The difference between the original carrying amount of the notes and the prepayment was recorded as an adjustment to the purchase price. 4. CALPINE THERMAL POWER, INC. On September 9, 1994, Calpine Thermal acquired the outstanding capital stock of TPC for a total purchase price of $66.5 million, consisting of a $60.0 million cash payment and the issuance by Calpine of a non-interest bearing promissory note to Natomas in the amount of $6.5 million (discounted to $5.2 million), which is due September 9, 1997. Calpine received payments of $3.0 million from the seller, which represented cash from TPC's operations for the period from July 1, 1994 to September 8, 1994. These payments were treated as purchase price adjustments. Calpine Thermal owns a 25% undivided interest in certain producing geothermal steam fields located at The Geysers area of northern California. Union Oil Company of California owns the remaining 75% interest in the steam fields, which deliver geothermal steam to twelve operating plants owned by PG&E. The steam fields currently provide the twelve operating plants with sufficient steam to generate approximately 604 megawatts of electricity. Steam from Calpine Thermal's steam field is sold to PG&E under a steam sales agreement. In addition, Calpine Thermal receives a monthly capacity maintenance fee, which provides for effluent disposal costs and facilities support costs, and a monthly fee for PG&E's right to curtail its power plants. The steam price, capacity maintenance and curtailment fees are adjusted annually. Calpine Thermal is required to compensate PG&E for the unused capacity of its geothermal power plants due to insufficient field capacities of its steam supply (offset payment). In accordance with the steam sales agreement, PG&E may curtail the power plants which receive steam from the Union Oil/Calpine Thermal Steam Fields in order to produce energy from lower cost sources. However, PG&E is constrained by its contractual obligation to operate all the power plants at a minimum of 40% of the field capacity during any given year. During 1995 and 1996, Calpine Thermal experienced extensive curtailments of steam production due to low gas prices and abundant hydro power. In March 1996, the Company 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 PG&E would likely curtail under the existing steam sales agreement. The price for this portion of steam will be set by the Company and Union Oil with the intent that it be at competitive prices. The steam sales agreement between Calpine Thermal and PG&E terminates two years after the closing of the last PG&E operating unit. PG&E may terminate the agreement upon a one-year written notice to Calpine Thermal. In the event the agreement is terminated by PG&E, Calpine Thermal has the right to purchase PG&E's facilities at PG&E's unamortized cost. Calpine Thermal will provide capacity maintenance services for five years after termination by PG&E or closure of the last PG&E operating unit. Alternatively, Calpine Thermal may terminate the agreement upon a two-year written notice to PG&E. PG&E has the right to take assignment of Calpine Thermal's facilities on the date of termination. In such a case, Calpine Thermal would generally continue to pay offset payments for 36 months following the date of termination. F-21 68 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. CALPINE GREENLEAF CORPORATION On April 21, 1995, Calpine Greenleaf 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. The acquisition was accounted for as a purchase, and the purchase price has been allocated to the acquired assets and liabilities based on their estimated fair values. The adjusted allocation of the purchase price is as follows (in thousands): Current assets.................................................... $ 6,572 Property, plant and equipment..................................... 122,545 --------- Total assets................................................. 129,117 --------- Current liabilities............................................... (1,079) Deferred income taxes, net........................................ (46,580) --------- Total liabilities............................................... (47,659) --------- Net purchase price................................................ $ 81,458 =========
The Acquired Companies own 100% of the assets of two 49.5 megawatt natural 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 PG&E pursuant to two long-term PSAs (expiring in 2019) at prices equal to PG&E's full short-run avoided operating costs, adjusted annually. The PSA 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. The thermal energy generated is used by thermal hosts adjacent to the Greenleaf Power Plants. Gas for the Greenleaf Power Plants is supplied by Montis Niger, Inc. ("MNI"). On January 31, 1997, the Company purchased MNI for $7.5 million. 6. CALPINE MONTEREY COGENERATION, INC. On June 29, 1995, CMCI acquired a 14.5-year operating lease (through December 2009) for a 28.5 megawatt natural gas-fired cogeneration power plant located in Watsonville, California. The Company acquired the operating lease from Ford Motor Credit Company for $900,000. The Watsonville Power Plant sells electricity to PG&E under a 20-year PSA, generally at prices equal to PG&E's full short-run avoided operating costs. Basic and contingent lease rental payments are described in Note 26. The power plant also provides steam to two local food processing plants. The Company also provides project and fuels management services. 7. CALPINE SISKIYOU GEOTHERMAL PARTNERS, L.P. In 1994, the Company formed a partnership with Trans-Pacific Geothermal Corporation ("TGC") to build a geothermal power generation facility located at Glass Mountain in northern California. TGC had previously signed a memorandum of understanding ("MOU") with Bonneville Power Administration ("BPA") and the Springfield, Oregon Utility Board ("SUB") to develop the project at Vale, Oregon. BPA and SUB consented in August 1994 to the assignment of the MOU to the partnership and the relocation of the project to Glass Mountain. The MOU contemplated execution of a 45-year power purchase agreement subject to satisfaction of certain conditions precedent and included an option for an additional 100 megawatts. The partnership is consolidated as the Company owns a controlling interest. F-22 69 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In December 1996, the partnership and BPA entered into a settlement agreement which restructured the rights and obligations of the parties. In return for the payment of $12.0 million by BPA to the partnership and the grant by the partnership to BPA of future options to purchase power at Glass Mountain, the partnership and BPA terminated the MOU and certain ancillary agreements. In addition, BPA will pay the partnership additional consideration should certain future events occur related to the ongoing environmental review of the Glass Mountain project. Following the settlement with BPA, TGC withdrew from the partnership. Of the $12.0 million received by the partnership in December 1996, $4.7 million was allocated to TGC, of which $3.0 million was received by the Company in payment of a loan (see Note 15). Previously capitalized project costs were charged to expense, and no significant gain or loss was included in net income for the year 1996. At December 31, 1996, the Company had $4.0 million of geothermal leases at Glass Mountain recorded as Property, plant and equipment, net in the accompanying consolidated balance sheet. 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. 8. CALPINE VAPOR, INC. In November 1995, Calpine Vapor entered into agreements with Constructora y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain Mexican bank lenders to loan funds to Coperlasa in connection with a geothermal steam production contract at the Cerro Prieto geothermal resource in Baja California, Mexico. 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. Calpine Vapor loaned $18.5 million to Coperlasa, and received fees for technical services provided to the project. At December 31, 1996, notes receivable (see Note 15) totaled $18.0 million. 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. In December 1995, Calpine Vapor also paid $1.5 million for an option to purchase an equity interest in Coperlasa. The option is being amortized over the estimated repayment period of the Coperlasa loan and is included in Other assets. 9. 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 natural 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 PSA through 2019 and provides steam to a vegetable processing plant. The Company makes semi-annual lease payments to BAF on each February 15 and August 15, a portion of which is supported by a $95.0 million collateral fund owned by the Company. The collateral fund consists of investment grade and U.S. Treasury Securities that mature serially in amounts equal to a portion of the lease payment. The collateral fund securities are classified as held-to-maturity investments (see Note 2). As of December 31, 1996, future rent payments are $24.4 million for 1997, $23.8 million for 1998, $19.4 million for 1999, $20.1 million for 2000, $20.8 million for 2001, and $183.2 million thereafter. Included in the accompanying December 31, 1996 balance sheet is approximately $12.7 million of unamortized prepaid lease costs. The Company recorded the value of the above-market pricing provided in the PSA as an asset which is included in property, plant and equipment. The Company has also recorded a deferred lease incentive of $78.5 million at December 31, 1996 equal to the value of the above-market payments to be received. The asset and liability are being amortized over the life of the power sales agreement and lease, respectively. F-23 70 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 10. GILROY TRANSACTION On August 29, 1996, the Company acquired a 120 megawatt natural 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. The Company recorded the value of the above-market pricing provided in the PSA of $82.1 million as an asset which is included in Property, plant and equipment. Electricity generated by the Gilroy Power Plant is sold to PG&E pursuant to a long-term PSA terminating in 2018. The PSA 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 transactions had occurred on January 1, 1995 (in thousands, except per share amounts):
1996 1995 -------- -------- Revenue................................................ $237,924 $221,447 Net income............................................. $ 18,954 $ 11,288 Earnings per share..................................... $ 1.29 $ 0.80
11. PASADENA COGENERATION PROJECT The Company 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. In December 1996, 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. The Company provided a $3.0 million letter of credit to Phillips to secure the performance under the project development agreement. The Company also entered into a credit agreement with ING U.S. Capital Corporation to provide $98.6 million of non-recourse project financing. In accordance with the credit agreement, the Company contributed $53.1 million in cash to the project, of which the remaining $41.0 million is included in Restricted cash in the accompanying consolidated balance sheet. The Company commenced construction in February 1997, with commercial operation scheduled to begin in October 1998. There can be no assurances that the Company will be successful in completing any additional PSAs or that the anticipated schedule for construction will be met. 12. ACCOUNTS RECEIVABLE At December 31, 1996, accounts receivable of $42.8 million included $1.9 million to be received from the Los Angeles Department of Water and Power for reimbursement of costs related to the Coso development project incurred by the Company in prior years. Such amount was received in 1997. F-24 71 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Accounts receivable from related parties at December 31, 1996 and 1995 include the following (in thousands):
1996 1995 ------ ------ O.L.S. Energy-Agnews, Inc.................................. $ 687 $ 806 Geothermal Energy Partners, Ltd. .......................... 350 462 Sumas Cogeneration Company, L.P............................ 590 908 Electrowatt Ltd. and subsidiaries.......................... 1,199 1 ------ ------ $2,826 $2,177 ====== ======
At December 31, 1996, the $1.2 million receivable from Electrowatt Ltd. was for reimbursement of costs for the sale of Electrowatt's ownership of Calpine common stock during the Company's initial public offering. 13. ACQUISITION PROJECT RECEIVABLES In connection with an unsuccessful bid to acquire O'Brien Environmental Energy, Inc. ("OEE") in 1995 through the U.S. Bankruptcy Court, the Company incurred and capitalized project acquisition costs. On November 8, 1996, the court denied Calpine's application for approval of such costs and fees and the Company recorded a $3.7 million loss for unrecoverable amounts (included in Other income, net in the accompanying consolidated statement of operations). The Company is appealing the court's decision. The Company also purchased $1.9 million of accounts receivable from two subsidiaries of OEE. Payments were made to the Company based on cash availability for each subsidiary. In February 1996, the Company received approximately $1.1 million against these receivables. The Company purchased for $900,000 from Stewart & Stevenson, Inc. ("S&S") a participation interest in a $1.0 million note issued by OEE. The Company received principal plus accrued interest in 1996. The Company purchased all of S&S's rights and obligations in a Subordinated Loan Agreement and Note between S&S and O'Brien (Newark) Cogeneration, Inc. The purchase price was $2.8 million and the notes bore interest at prime plus 2.0%. The Company received principal plus accrued interest in 1996. 14. INVESTMENTS IN POWER PROJECTS The Company has unconsolidated investments in power projects which are accounted for under the equity method. Financial information related to these investments is as follows (in thousands):
SUMAS O.L.S. GEOTHERMAL COGENERATION ENERGY- ENERGY COMPANY, AGNEWS, PARTNERS, L.P. INC. LTD. ------------ ------------ ------------ 1996 Operating revenue.............................. $ 44,092 $ 11,023 $ 22,302 Net income (loss).............................. 8,494 (840) 6,367 Assets......................................... 129,273 37,160 69,249 Liabilities.................................... 125,652 36,711 38,304 Company's percentage ownership................. (a) 20% 5% Equity investments in power projects........... 11,382 124 1,556 Project development costs...................... 875 -- -- -------- ------- ------- Total investments in power projects............ 12,257 124 1,556 ======== ======= ======= Company's share of net income (loss)........... $ 6,396 $ (190) $ 331 ======== ======= =======
F-25 72 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUMAS O.L.S. GEOTHERMAL COGENERATION ENERGY- ENERGY COMPANY, AGNEWS, PARTNERS, L.P. INC. LTD. ------------ ------------ ------------ 1995 Operating revenue.............................. $ 31,526 $ 10,779 $ 21,676 Net income (loss).............................. (6,098) (483) 5,538 Assets......................................... 122,802 40,330 76,017 Liabilities.................................... 123,377 39,034 51,439 Company's percentage ownership................. (a) 20% 5% Equity investments in power projects........... 5,763 314 1,229 Project development costs...................... 912 -- -- -------- ------- ------- Total investments in power projects............ 6,675 314 1,229 ======== ======= ======= Company's share of net income (loss)........... $ (3,049) $ (82) $ 227 ======== ======= =======
SUMAS O.L.S. GEOTHERMAL COGENERATION ENERGY- ENERGY COMPANY, AGNEWS, PARTNERS, L.P. INC. LTD. ------------ ------------ ------------ 1994 Operating revenue.............................. $ 32,060 $ 11,985 $ 21,721 Net income (loss).............................. (5,777) (415) 5,548 Assets......................................... 130,148 42,596 77,081 Liabilities.................................... 124,625 40,864 58,041 Company's percentage ownership................. (a) 20% 5% Equity investments in power projects........... 8,812 396 952 Project development costs...................... 946 8 -- -------- ------- ------- Total investments in power projects............ 9,758 404 952 ======== ======= ======= Company's share of net income (loss)........... $ (2,888) $ (143) $ 277 ======== ======= =======
- --------------- (a) Distributions will be made out of operating income after certain required deposits are made and certain minimum balances are met. After receiving certain preferential distributions, the Company will have a 50% interest in the profits and losses of Sumas until earning a 24.5% pre-tax cumulative return on its investment, at which time the Company's interest in Sumas will be reduced to 11.33%. Sumas Cogeneration Company, L.P. -- Sumas Cogeneration Company, L P. ("Sumas") is a Delaware limited partnership formed between Sumas Energy, Inc. ("SEI"), a Washington State Subchapter S corporation, and Whatcom Cogeneration Partners, L.P. ("Whatcom"), a wholly owned partnership of the Company. SEI is the general partner and Whatcom is the limited partner. Sumas has a wholly owned Canadian subsidiary, ENCO Gas, Ltd. ("ENCO"), which is incorporated in New Brunswick, Canada. Sumas owns and operates a 125 megawatt natural gas-fired cogeneration power plant. In connection with the Sumas power plant is a lumber dry kiln facility and a 3.5 mile private natural gas pipeline. ENCO acquired, developed and is operating a portfolio of proven natural gas reserves in British Columbia and Alberta, Canada to provide a dedicated fuel supply for the Sumas Power Plant. Sumas produces and sells electrical energy to Puget Sound Power & Light Company ("Puget") under a 20-year agreement for an average 123 megawatts. Sumas leases the dry kiln facility and sells steam to Socco, Inc. ("Socco"), a custom lumber drying operation owned by an affiliated individual. F-26 73 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Construction financing was provided through a $95.2 million construction and term loan agreement with The Prudential Insurance Company of America ("Prudential") and Credit Suisse, an affiliate of the Company. In addition, ENCO has a $24.8 million loan agreement with Prudential and Credit Suisse. On May 25, 1993, the entire $120.0 million was converted to a term loan. In addition, the Company provides operations and maintenance services to Sumas and receives a fixed fee of $1.1 million per year adjusted annually for inflation, an annual base fee of $150,000 per year also adjusted annually for inflation and certain other reimbursable expenses. The Company is entitled to an annual performance bonus of up to $400,000 based upon the achievement of certain performance levels. This arrangement will expire upon the date Whatcom receives its 24.5% pre-tax return or 10 years, subject to renewal terms, whichever is later. The Company recorded revenue of approximately $2.0 million, $2.0 million, and $1.9 million associated with this arrangement during the years ended December 31, 1996, 1995 and 1994, respectively. O.L.S. Energy-Agnews, Inc. -- The Company has a 20% interest in O.L.S. Energy-Agnews, Inc., a joint venture with GATX Capital Corporation, which owns and operates a 29 megawatt gas-fired combined-cycle cogeneration facility at the State-owned Agnews Developmental Center ("Center") in San Jose, California. The cogeneration plant provides the Center with all of its thermal and electric requirements. Excess electricity is sold to PG&E under a Standard Offer No. 4 contract. The Company's original investment was $1.8 million. In addition to its interest as stated above, the Company has been contracted by the joint venture to provide operations and maintenance services at cost plus overhead and fees, as specified. The Company recorded revenue of $2.0 million, $1.5 million, and $1.4 million associated with this service agreement and for other services provided to the joint venture for the years ended December 31, 1996, 1995 and 1994, respectively. In January 1990, O.L.S Energy-Agnews, Inc. entered into a credit agreement with Credit Suisse providing for a $28.0 million loan. The loan is secured by all of the assets of the Agnews Power Plant and bears interest on the unpaid principal balance based on the London Interbank Offered Rate ("LIBOR") plus a margin rate varying between 0.05% and 1.5%. Geothermal Energy Partners, Ltd. -- During 1989, the Company acquired a 5% interest in Geothermal Energy Partners Ltd. ("GEP"). GEP was established in 1988 to develop, finance and construct a 20 megawatt geothermal power production facility located in The Geysers area of northern California. The facility began operations on June 6, 1989. In addition to its interest as stated above, the Company has been contracted by GEP to provide operations and maintenance services at cost plus overhead and fees, as specified. The Company recorded revenue of $4.0 million, $3.5 million and $3.7 million associated with this service agreement to GEP for the years ended December 31, 1996, 1995 and 1994, respectively. The Company accounts for its investment in GEP under the equity method because control of the project is deemed to be shared under the terms of the partnership agreement, and the Company has significant influence over the operation of the venture. 15. NOTES RECEIVABLE In May 1993, in accordance with the Sumas partnership agreement, the Company was entitled to receive a distribution of $1.5 million and 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 loan bears interest at 20% and is secured by a security interest in the loan between SEI and its sole shareholder. The Company will receive payments of 50% of SEI's cash F-27 74 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) distributions from Sumas. The payments will first reduce any accrued and unpaid interest and then reduce the principal balance. On May 25, 2003, all unpaid principal and interest is due. In March 1994, the Company loaned $10.0 million to the sole shareholder of SEI. The loan matures in 10 years and bears interest at 16.25%. The loan is secured by a pledge to Calpine of SEI's interest in Sumas. In order to provide for the payment of principal and interest on the loan, an additional 12 1/2% of the cash flow generated by Sumas was assigned to Calpine. The Company deferred the recognition of interest income from these notes until Sumas generated net income. In 1996, the Company recognized a total of $2.1 million of interest income related to the above two loans, which represents the portion of Sumas' earnings not recognized by Calpine related to its equity investment in Sumas. In August 1994, the Company entered into a loan agreement providing for loans up to $4.8 million to Trans-Pacific Geothermal Glass Mountain Ltd. ("TGGM"), a subsidiary of TGC (see Note 7). The loan bore interest at 10% and had a maturity date which was based on certain future events. The loan was secured by a pledge to Calpine of the partner's interest in the Glass Mountain project. The Company was deferring the recognition of income from this note until the Glass Mountain project generated sufficient income to support the collectibility of interest earned. At December 1, 1996, $4.1 million was outstanding. In December 1996, the Company received $3.0 million from TGGM in payment of the loan and recorded a $1.1 million loss for uncollectible amounts, which was included in Other income, net (see Note 7). As of December 31, 1996, Calpine Vapor had notes receivable of $18.0 million from Coperlasa and associated unamortized loan acquisition fees of $1.1 million (see Note 8). Interest accrues on the outstanding notes receivable at approximately 18.9%. The Company is deferring the recognition of income from this note until the Cerro Prieto project generates sufficient cash flows available for distribution to support the collectibility of interest earned. 16. REVOLVING CREDIT FACILITY AND LINES OF CREDIT At December 31, 1996, the Company had a $50.0 million three-year credit facility available with a consortium of commercial lending institutions which include The Bank of Nova Scotia, International Nederlanden U.S. Capital Corporation, Sumitomo Bank of California and Canadian Imperial Bank of Commerce. As of December 31, 1996, the Company had no borrowings and $5.9 million of letters of credit outstanding, which reflect $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 or at 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, 1995, the Company had a $50.0 million credit facility with Credit Suisse (whose parent company owns approximately 44.9% of Electrowatt Ltd. ("Electrowatt"), the former indirect sole owner of the Company prior to the initial public offering on September 25, 1996). At December 31, 1995, the Company had $19.9 million of borrowings outstanding, bearing interest at LIBOR plus 0.5% (6.4% at December 31, 1995). Interest could be paid at either LIBOR or the Credit Suisse base rate, plus applicable margins in both cases. The credit agreement specified that the Company maintain certain covenants with which the Company was in compliance. The Company terminated its Credit Suisse credit facility on September 25, 1996. At December 31, 1996, the Company had a loan facility with available borrowings totaling $1.2 million. There were no borrowings and $900,000 of letters of credit outstanding as of December 31, 1996. At December 31, 1995, the Company had three loan facilities with available borrowings totaling $10.2 million. F-28 75 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Borrowings and letters of credit outstanding were $1.2 million and $3.8 million as of December 31, 1995, respectively. Interest is payable at variable interest rates based on bank base rates, LIBOR or prime plus applicable margins in all cases (approximately 7.6% at December 31, 1995 on borrowings). The credit agreements specified that the Company maintain certain covenants with which the Company was in compliance. 17. WORKING CAPITAL LOAN The Company has a $5.0 million working capital loan agreement with a bank providing for advances and letters of credit. The aggregate unpaid principal of the working capital loan is payable in full at least once a year, with the final payment of principal, interest and fees due June 30, 1998. Interest on borrowings accrues at the option of the Company at either a base rate, LIBOR, or a certificate of deposit rate (plus applicable margins in all cases) over the term of the loan. No borrowings were outstanding at December 31, 1996 and 1995. The Company had letters of credit outstanding of $459,000 at December 31, 1996 and 1995. Outstanding letters of credit bear interest at 0.625% payable quarterly. 18. NON-RECOURSE PROJECT FINANCING The components of non-recourse project financing as of December 31, 1996 and 1995 are (in thousands):
1996 1995 -------- -------- Senior-term loans: Fixed rate portion................................... $ 73,000 $ 99,400 Variable rate portion................................ 20,000 20,000 Premium on debt...................................... 1,824 2,959 -------- -------- Total senior-term loans...................... 94,824 122,359 Junior-term loans...................................... 19,965 19,965 Notes payable to banks................................. 194,478 133,026 -------- -------- Total long-term debt......................... 309,267 275,350 Less current portion......................... 30,627 84,708 -------- -------- Long-term debt, less current portion......... $278,640 $190,642 ======== ========
The Company entered into the Senior-Term Loans and Junior-Term Loans in connection with the Company's acquisition of CGC in 1993. Senior-Term Loans -- Principal and interest are payable in quarterly installments at variable amounts with the final payment of principal, interest and fees due June 30, 2002. A portion of the senior-term loans bears interest fixed at 9.93% (see discussion on swap agreement below) with the remainder accruing interest at LIBOR plus an applicable margin (6.75% and 6.69% at December 31, 1996 and 1995, respectively) over the term of the loan, collateralized by all of CGC's assets and the Company's interest in CGC. The premium is amortized over the life of the fixed rate portion of the loan using the interest method. Junior-Term Loans -- Principal and interest are payable in quarterly installments at variable amounts beginning September 30, 2002 with the final payment of principal, interest and fees due June 30, 2005; interest accrues at LIBOR plus an applicable margin (7.75% and 7.69% at December 31, 1996 and 1995, respectively) over the term of the loan, collateralized by all of CGC's assets and the Company's interest in CGC. The Company entered into two interest rate swap agreements to minimize the impact of changes in interest rates on a portion of its senior-term loans. These agreements fix the interest on this portion at 9.93%. At December 31, 1996, the swap agreements applied to debt with a principal balance total of $73.0 million. The interest rate swap agreements mature through December 31, 2000. The premium on debt was recorded in F-29 76 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) conjunction with the acquisition as discussed above. The amortization of the premium adjusts the effective interest rate on the fixed-rate debt to 7.05% per annum. The floating interest rate associated with this portion of the senior-term loans was LIBOR plus an applicable margin (6.63% at December 31, 1996 and 6.99% at December 31, 1995). The Company is exposed to credit risk in the event of non-performance by the other parties to the swap agreements. Notes Payable to Banks -- In September 1994, the Company entered into a two-year agreement with The Bank of Nova Scotia to finance the acquisition of TPC. In May 1996, a portion of the net proceeds from the Company's issuance of the 10 1/2% Senior Notes Due 2006 was utilized to repay the total $57.0 million of borrowings under this agreement. In June 1995, the Company entered into an agreement with Sumitomo Bank to finance the acquisition of the Greenleaf Power Plants. Of the $74.7 million debt outstanding at December 31, 1996, $59.0 million bears interest fixed at 7.4%, with the remaining floating rate portion accruing interest at LIBOR plus an applicable margin (6.24% as of December 31, 1996). At December 31, 1995, $76.0 million of debt was outstanding, of which $60.0 million was at the fixed interest rate of 7.4%, with the remaining floating rate portion accruing interest at approximately 6.5%. This debt is secured by all of the assets of Greenleaf 1 and 2. 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 $74.7 million debt will be repaid quarterly, with a final maturity date of December 31, 2010. 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, 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. In addition, BNP provided two additional tranches for the payment of certain contingent consideration, which at December 31, 1996 totaled $19.6 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% (see discussion below), with the remainder accruing interest at LIBOR plus an applicable margin (6.6% at December 31, 1996). Interest on the floating rate portion may be at BNP's base rate plus an applicable margin or at LIBOR plus an applicable margin. Interest on base rate 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 $119.8 million debt will be repaid semi-annually beginning August 31, 1997, 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 $87.5 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. F-30 77 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The annual principal maturities of the non-recourse debt outstanding at December 31, 1996 are as follows (in thousands): 1997.............................................. $ 30,627 1998.............................................. 32,658 1999.............................................. 24,183 2000.............................................. 24,851 2001.............................................. 24,631 Thereafter........................................ 170,493 -------- 307,443 Unamortized premium on fixed portion of senior loans........................................... 1,824 -------- Total................................... $309,267 ========
The carrying value of $73.0 million and $99.4 million of the senior-term loan as of December 31, 1996 and 1995, respectively, has an effective rate of 9.93% under the Company's interest rate swap agreements (7.05% after consideration of the debt premium). Based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities, the fair value of the debt as of December 31, 1996 and 1995 is approximately $83.2 million and $107.3 million, respectively. The carrying value of the remaining $20.0 million of the senior-term and the $20.0 million junior-term loans and the notes payable to banks approximate the debts' fair market value as the rates are variable and based on the current LIBOR rate. The non-recourse debt is held by subsidiaries of Calpine. 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. On December 20, 1996, the Company entered into a credit agreement with ING U.S. Capital Corporation to provide $98.6 million of non-recourse project financing for the Pasadena Cogeneration Project (see Note 11). No borrowings were outstanding at December 31, 1996. 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 no less 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. 19. 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 has been discounted to yield 8.0% per annum, due September 9, 1997. The carrying amount of $6.2 million at December 31, 1996 approximates fair market value. In January 1995, the Company purchased the working interest covering certain properties in its geothermal properties at CGC from Santa Fe Geothermal, Inc. The purchase price included $6.0 million cash, and a $750,000 non-interest bearing note discounted to yield 9% per annum and due on December 26, 1997. The Company may repay all or any part of the note at any time without penalty. The carrying value of $686,000 of the discounted non-interest bearing note at December 31, 1996 approximates fair market value. F-31 78 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 20. SENIOR NOTES On May 16, 1996, the Company issued $180.0 million aggregate principal amount of 10 1/2% Senior Notes Due 2006. The net proceeds of $174.9 million were used to repay $53.7 million of borrowings under the Credit Suisse Credit Facility, $57.0 million of non-recourse project financing and $45.0 million of borrowings from The Bank of Nova Scotia. The remaining $19.2 million was available for general corporate purposes. Transaction costs of $5.1 million incurred in connection with the public debt offering were recorded as a deferred charge and are amortized over the ten-year life of the 10 1/2% Senior Notes Due 2006. 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 $191.7 million as of December 31, 1996. On February 17, 1994, the Company completed a $105.0 million public debt offering of 9 1/4% Senior Notes Due 2004. Transaction costs of $4.1 million incurred in connection with the public debt offering were recorded as a deferred charge and are amortized over the ten-year life of the 9 1/4% Senior Notes Due 2004. 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 $105.7 million as of December 31, 1996. The Senior Note indentures specify that the Company maintain 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. 21. 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, 1996 and 1995 are (in thousands):
1996 1995 --------- --------- Expenses deductible in a future period............... $ 3,329 $ 1,674 Net operating loss and credit carryforwards.......... 19,856 19,480 Other differences.................................... 1,186 2,034 --------- --------- Deferred tax asset, before valuation allowance..... 24,371 23,188 Valuation allowance.................................. (692) (749) --------- --------- Deferred tax asset................................. 23,679 22,439 --------- --------- Property differences................................. (119,842) (116,314) Difference in taxable income and income from investments recorded on the equity method.......... (2,753) (2,311) Other differences.................................... (1,469) (1,435) --------- --------- Deferred tax liabilities........................... (124,064) (120,060) --------- --------- Net deferred tax liability...................... $(100,385) $ (97,621) ========= =========
F-32 79 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The net operating loss and credit carryforwards consist of Federal and State net operating loss carryforwards which expire 2005 through 2010 and 2000, respectively, and Federal and State alternative minimum tax credit carryforwards which can be carried forward indefinitely. At December 31, 1996, the Federal and State net operating loss carryforwards were approximately $23.8 million and $12.0 million, respectively. At December 31, 1996, the State net operating losses have been fully reserved for in the valuation allowance due to the limited carryforward period allowed by the State of California. At December 31, 1996, Federal and State alternative minimum tax credit carryforwards were approximately $6.7 million and $1.7 million, respectively. 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. 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 8.84% effective January 1, 1997. The provision for income taxes for the years ended December 31, 1996, 1995 and 1994 consists of the following (in thousands):
1996 1995 1994 ------ ------ ------ Current: Federal........................................ $5,671 $3,085 $ 96 State.......................................... 1,805 1,163 365 Deferred: Federal........................................ 3,890 816 2,546 State.......................................... (801) (15) 547 Adjustment in state tax rate................ (769) -- -- Revision in prior years' tax estimates...... (732) -- -- Increase in valuation allowance............. -- -- 299 ------ ------ ------ Total provision........................ $9,064 $5,049 $3,853 ====== ====== ======
The Company's effective rate for income taxes for the years ended December 31, 1996, 1995 and 1994 differs from the U.S. statutory rate, as reflected in the following reconciliation.
1996 1995 1994 ----- ----- ----- U.S. statutory tax rate............................. 35.0% 35.0% 35.0% State income tax, net of Federal benefit............ 6.0 6.0 6.0 Depletion allowance................................. (2.3) (0.3) (8.6) Effect of change in tax rates....................... (3.0) -- -- Revision in prior years' tax estimates.............. (2.6) -- -- Increase in valuation allowance..................... -- -- 7.8 Other, net.......................................... (0.4) (0.1) (1.2) ---- ---- ---- Effective income tax rate......................... 32.7% 40.6% 39.0% ==== ==== ====
F-33 80 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 22. 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 1996, 1995, and 1994 totaled $485,000, $350,000 and $311,000, respectively. 23. PREFERRED STOCK 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 Company's initial public offering, all of the Series A Preferred Stock was converted into approximately 2.2 million shares of common stock and sold to the public in the offering by Electrowatt (see Note 24). 24. COMMON STOCK In September 1996, Calpine completed the initial public offering of 18,045,000 shares of its common stock with $0.01 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 sold 12,567,180 shares of common stock, representing its entire ownership interest in Calpine. As a result of the Common Stock Offering, Electrowatt no longer owns any interest in Calpine. 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. Approximately $13.0 million of total net proceeds was used to repay short-term bank borrowings. The remaining net proceeds are for working capital and general corporate purposes, and for the development and acquisition of power generation facilities. 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 preferred stock into shares of common stock. 25. STOCK-BASED COMPENSATION PROGRAMS 1996 Employee Stock Purchase Plan The Company adopted 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. Shares are purchased on February 28 and August 31 of each year. On the first purchase date of February 28, 1997, employees purchased 25,819 shares of common stock at a weighted average fair value of $13.60 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; such plan succeeded the Company's previously adopted stock option program. The Company accounts for this plan under APB Opinion No. 25, under which no compensation cost has been recognized in 1996. Had compensation cost for F-34 81 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) this plan been determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation, the Company's net income and earning per share would have been reduced to the following pro forma amounts (in thousands, except per share amounts):
1996 1995 ------- ------ Net income.................................. As reported $18,692 $7,378 Pro forma $18,145 $7,232 Primary earnings per share.................. As reported $ 1.27 -- Pro forma $ 1.24 -- As adjusted primary earnings per share assuming conversion of preferred stock.... As reported -- $ 0.52 Pro forma -- $ 0.51
Because the SFAS No. 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. The Company may grant options for up to 4,041,858 shares under the SIP. As of December 31, 1996, the Company had granted options to purchase 2,340,294 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. A summary of the status of the Company's SIP at December 31, 1996 and changes during the year then ended is presented in the table and narrative below:
SHARES OF COMMON STOCK --------------------------- WEIGHTED AVAILABLE SIP AVERAGE FOR OPTION OPTION EXERCISE OR AWARD SHARES PRICE ------------- --------- -------- Balance, January 1, 1995.................. 1,160,782 1,436,141 $ 1.53 Granted................................. (444,333) 444,333 $ 4.91 Forfeited............................... 25,963 (25,963) $ 2.13 --------- ----- Balance, 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 Forfeited............................... 56,796 (56,796) $ 7.90 --------- ----- Balance, December 31, 1996................ 1,696,564 2,340,294 $ 3.69 ========= =====
F-35 82 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table summarizes information concerning outstanding and exercisable options at December 31, 1996:
OPTIONS OUTSTANDING --------------------------- OPTIONS EXERCISABLE WEIGHTED ------------------------ AVERAGE WEIGHTED REMAINING AVERAGE EXERCISE NUMBER CONTRACTUAL NUMBER EXERCISE PRICES OUTSTANDING LIFE EXERCISABLE PRICE --------------------------------------- ----------- ----------- ----------- -------- $ 0.50................................. 934,920 6.00 934,920 $ 0.50 $ 1.85................................. 174,193 6.25 174,193 $ 1.85 $ 4.57................................. 296,058 7.75 222,043 $ 4.57 $ 4.91................................. 434,290 8.97 104,590 $ 4.91 $ 8.57................................. 490,833 10.00 -- $ 8.57 $16.00................................. 10,000 9.99 10,000 $16.00 --------- --------- ----- 2,340,294 1,445,746 $ 1.71 ========= ========= =====
The estimated average fair value of options granted in 1995 and 1996 is $1.23 and $3.29 on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: risk-free interest rates of 5.4% to 6.2%; expected dividend yields of zero percent; expected lives of 3 years; expected volatility of 0% to 27%. 26. RELATED PARTY TRANSACTIONS In January 1995, the Company and Electrowatt entered into a management services agreement whereby Electrowatt agreed to provide the Company with advisory services in connection with the construction, financing, acquisition and development of power projects, as well as any other advisory services as may be required by the Company in connection with the operation of the Company. Pursuant to this agreement, the Company paid $166,000 and $200,000 of such management expenses in 1996 and 1995, respectively. The management services agreement terminated September 25, 1996, with completion of the initial public offering. During 1996, 1995, and 1994, the Company paid $123,000, $106,000, and $69,000, respectively, to Electrowatt pursuant to a guarantee fee agreement whereby Electrowatt agreed to guarantee the payment, when due, of any and all indebtedness of the Company to Credit Suisse in accordance with the terms and conditions of the line of credit. Under the guarantee fee agreement, the Company had agreed to pay to Electrowatt an annual fee equal to 1% of the average outstanding balance of the Company's indebtedness to Credit Suisse during each quarter as compensation for all services rendered under the guarantee fee agreement. The guarantee fee agreement terminated in September 1996. At December 31, 1996, the Company had approximately $1.2 million in accounts receivable from Electrowatt (see Note 12) related to reimbursement of costs for the sale of Electrowatt's common stock in Calpine. As a result of Electrowatt's sale of Calpine common shares, Electrowatt no longer owns any interest in Calpine. F-36 83 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 27. SIGNIFICANT CUSTOMERS The Company's electricity and steam sales revenue is primarily from two sources -- PG&E and SMUD. Revenues earned from these sources for the years ended December 31, 1996, 1995 and 1994 were as follows (in thousands):
1996 1995 1994 -------- -------- ------- PG&E........................................ $183,531 $112,522 $77,010 SMUD........................................ 14,609 12,345 9,296 Other....................................... 1,324 173 804 -------- -------- -------- 199,464 125,040 87,110 Deferred revenues recognized (see Note 3)... -- 2,759 3,185 -------- -------- -------- Total electricity and steam sales........... $199,464 $127,799 $90,295 ======== ======== ========
PG&E, the Company's primary customer, is also affected by industry restructuring and deregulation (see Note 28 regarding Regulation and CPUC Restructuring). 28. COMMITMENTS AND CONTINGENCIES Capital Projects -- The Company has 1997 commitments for capital expenditures totaling $4.0 million related to various projects at its geothermal facilities. In March 1996, the Company entered into an energy development agreement with Phillips Petroleum Company to develop, construct, own and operate a 240 megawatt gas-fired cogeneration facility at Phillips Houston Chemical Complex in Pasadena, Texas. The Company commenced construction in February 1997, with commercial operation scheduled to begin in October 1998. The Company has 1997 commitments of $97.2 million related to this 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. The Company also has working interest agreements with third parties providing for the sharing of approximately 25% to 30% of drilling and other well costs, various percentages of other operating costs and 25% to 30% of revenues on specified wells. Expenses under these agreements for the years ended December 31, 1996, 1995 and 1994 are (in thousands):
1996 1995 1994 ------- ------- ------- Production royalties.......................... $10,793 $10,574 $11,153 Lease payments................................ $ 246 $ 225 $ 252
Natural Gas Purchases -- The Company enters into long-term gas purchase contracts with third parties to supply gas to its gas-fired cogeneration projects. Such contracts generally have terms of 1 to 24 months, and existing contracts expire though July 31, 1997, continuing month to month thereafter unless either party terminates the agreement upon sixty days written notice. On January 31, 1997, the Company purchased MNI which supplies gas to the Greenleaf Power Plants (see Note 5). F-37 84 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Watsonville Operating Lease -- The Company is committed under an operating lease (through December 2009) for a 28.5 megawatt natural gas-fired cogeneration power plant located in Watsonville, California (see Note 6). 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, 1996, future basic rent payments are $2.9 million for each year from 1997 to 2001, and $24.4 million thereafter through December 2009. Contingent rent payments are 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. Office and Equipment Leases -- The Company leases its corporate office, Houston office, Portland office, Santa Rosa office facilities and certain office equipment under noncancellable operating leases expiring through 2001. Future minimum lease payments under these leases are (in thousands): 1997................................................ $1,138 1998................................................ 1,125 1999................................................ 977 2000................................................ 936 2001................................................ 367 Thereafter.......................................... -- ------ Total future minimum lease commitments.............. $4,543 ======
Lease payments are subject to adjustment for the Company's pro rata portion of annual increases or decreases in building operating costs. In 1996, 1995 and 1994, rent expense for noncancellable operating leases amounted to $1,036,000, $733,000 and $663,000, respectively. Regulation and CPUC Restructuring -- Electricity and steam sales agreements with PG&E are regulated by the CPUC. In December 1995, the CPUC proposed the transition of the electric generation market to a competitive market beginning January 1, 1998, with all consumers participating by 2003. Since the proposed restructure results in widespread impact on the market structure and requires participation and oversight of the Federal Energy Regulatory Commission ("FERC"), the CPUC has sought to build a California consensus involving the legislature, the Governor, public and municipal utilities and customers. The consensus has resulted in filings with FERC which should permit both the CPUC and FERC to collectively proceed with implementation of the new competitive market structure. On September 23, 1996 state legislation was passed, AB 1890 (the "Bill"), which codified much of the CPUC decision and directed the CPUC to proceed with implementation of restructure no later than January 1, 1998. The Bill accelerated the transition period to a fully competitive market from five years to four years with all consumers participating by the year 2002. The Bill provided for an electricity rate freeze for the period of transition and mandated through issuance of rate reduction bonds a 10% rate reduction for small commercial and residential customers effective January 1, 1998. The proposed restructuring provides for phased-in customer choice (direct access), development of a non-discriminatory market structure, full recovery of utility stranded costs, sanctity of existing contracts, and continuation of existing public policy programs including funds for enhancement of in-state renewable energy technologies during the transition period. 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. 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 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 F-38 85 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) "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 PSA, 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 -- The Company, together with over 100 other parties, was named as a defendant in an action brought in August 1993 by the bankruptcy trustee for Bonneville Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et al., in the United States District Court for the District of Utah (the "Court"). In December 1996, the trustee and the Company entered into a settlement agreement relating to this matter. The trustee has agreed to waive all claims against the Company and to dismiss the trustee's litigation against the Company in exchange for a payment of $767,500 by the Company. The Company is involved in various other claims and legal actions arising out of the normal course of business. Management does not expect that the outcome of these cases will have a material adverse effect on the Company's financial position or results of operations. 29. 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. In the first quarter of 1996, the Company issued $50.0 million of preferred stock to Electrowatt (see Note 23). In the second quarter of 1996, the Company entered into an operating lease for the King City Power Plant (see Note 9) and issued $180.0 million of 10 1/2% Senior Notes Due 2006 (see Note 20). In the third quarter of 1996, the Company acquired the Gilroy Power Plant (see Note 10) and charged to earnings a $3.7 million uncollectible amount associated with the attempt to acquire the O'Brien companies (see Note 13). The Company also incurred an employee bonus expense of $1.4 million related to the initial public offering of common stock in September 1996, and recorded a $1.8 million loss related to its electricity trading operations. In addition, the Company decreased its deferred income taxes by $769,000 to reflect the change in California's state income tax rate from 9.3% to 8.84% effective January 1, 1997. In the fourth quarter of 1996, the Company recorded a $1.4 million net gain related to the settlement of the Coso project, offset by a $767,500 expense related to the settlement of certain litigation (see Note 28). In addition, the Company revised its prior years' tax estimates by $700,000. The Company's common stock has been traded on the New York stock exchange beginning September 19, 1996. There were approximately 39 common stockholders of record at December 31, 1996. No dividends have been paid to-date. F-39 86 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
QUARTER ENDED ----------------------------------------------- DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31 ----------- ------------ ------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1996 Total revenue....................................... $61,663 $ 70,897 $50,321 $31,673 Income from operations.............................. $14,303 $ 29,097 $16,203 $ 7,188 Net income.......................................... $ 3,537 $ 10,732 $ 4,717 $ (294) Earnings per common share........................... $ 0.17 $ 0.76 $ 0.35 $ (0.03) Common stock price per share High.............................................. $ 20.00 $ 16.38 -- -- Low............................................... $ 16.00 $ 16.00 -- -- 1995 Total revenue....................................... $39,570 $ 42,176 $28,342 $22,010 Income from operations.............................. $11,473 $ 16,446 $ 8,195 $ 6,572 Net income.......................................... $ 2,115 $ 4,965 $ 239 $ 59 As adjusted earnings per common share assuming conversion of preferred stock (see Note 2)........ $ 0.15 $ 0.35 $ 0.02 --
F-40 87 REPORT OF INDEPENDENT PUBLIC AUDITORS 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 March 7, 1997. 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 March 7 , 1997 F-41 88 CALPINE CORPORATION SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS DECEMBER 31, 1996 AND 1995
1996 1995 ------------ ------------ ASSETS Current assets: Cash and cash equivalents..................................... $ 33,150,134 $ (1,970,526) Accounts receivable........................................... 5,023,945 1,348,969 Accounts receivable from affiliates........................... 4,534,048 4,955,625 Acquisition project receivables............................... 791,206 8,805,186 Other current assets.......................................... 811,816 270,806 ------------ ------------ Total current assets.................................. 44,311,149 13,410,060 Property, plant and equipment, net.............................. 5,711,074 724,359 Investments in power projects................................... 141,816,204 82,610,719 Intercompany receivables........................................ 302,230,313 48,323,629 Notes receivable from related parties........................... 18,182,372 19,390,952 Deferred charges................................................ 8,325,857 3,390,677 Other assets.................................................... 121,358 197,144 ------------ ------------ Total assets.......................................... $520,698,327 $168,047,540 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable.............................................. $ 503,598 $ 2,667,808 Accrued payroll and related expenses.......................... 3,477,246 2,582,194 Accrued interest payable...................................... 6,461,875 4,051,785 Other accrued expenses........................................ 5,385,747 2,704,257 ------------ ------------ Total current liabilities............................. 15,828,466 12,006,044 Long-term line of credit........................................ -- 14,000,000 Senior Notes.................................................... 285,000,000 105,000,000 Deferred income taxes........................................... 11,229,502 7,877,537 Deferred revenue................................................ 5,513,458 3,937,175 ------------ ------------ Total liabilities..................................... 317,571,426 142,820,756 ------------ ------------ Stockholders' equity: Common stock, $0.01 par value................................. 19,843 20,000 Additional paid-in capital.................................... 165,412,455 6,204,000 Retained earnings............................................. 37,694,603 19,002,784 ------------ ------------ Total stockholders' equity............................ 203,126,901 25,226,784 ------------ ------------ Total liabilities and stockholders' equity............ $520,698,327 $168,047,540 ============ ============
The accompanying notes are an integral part of these condensed financial statements. F-42 89 CALPINE CORPORATION SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994 ------------ ----------- ----------- Revenue: Service contract revenue from related parties.... $ 36,581,736 $28,733,399 $22,929,897 Income from unconsolidated investments in power projects...................................... 66,625,486 32,397,392 23,711,895 ------------ ----------- ----------- Total revenue................................. 103,207,222 61,130,791 46,641,792 Cost of revenue: Service contract expenses........................ 34,953,440 27,433,069 19,161,445 ------------ ----------- ----------- Gross profit....................................... 68,253,782 33,697,722 27,480,347 Project development expenses....................... 3,866,828 3,087,316 2,822,459 General and administrative expenses................ 13,650,881 8,081,458 6,867,520 ------------ ----------- ----------- Income from operations........................ 50,736,073 22,528,948 17,790,368 Other (income) expense: Interest expense................................. 23,036,232 10,479,144 9,207,381 Other income, net................................ (56,420) (377,276) (1,290,739) ------------ ----------- ----------- Income before provision for income taxes...... 27,756,261 12,427,080 9,873,726 Provision for income taxes......................... 9,064,445 5,049,568 3,853,115 ------------ ----------- ----------- Net income.................................... $ 18,691,816 $ 7,377,512 $ 6,020,611 ============ =========== =========== Primary earnings per share Weighted average number of shares outstanding.... 14,679,984 -- -- ============ =========== =========== Earnings per share............................... $ 1.27 -- -- ============ =========== =========== As adjusted primary earnings per share, assuming Weighted average number of shares outstanding.... -- 14,150,837 -- ============ =========== =========== Earnings per share............................... -- $ 0.52 -- ============ =========== ===========
The accompanying notes are an integral part of these condensed financial statements. F-43 90 CALPINE CORPORATION SCHEDULE I CONDENSED FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994 ------------- ----------- ------------ Net cash used in operating activities............ $(281,904,648) $(8,874,945) $(44,753,732) ------------- ------------ ------------ Cash flows from investing activities: Acquisition of property, plant and equipment... (5,320,508) (367,711) (299,961) Investments in power projects.................. -- (1,262,000) (175,352) Decrease (increase) in notes receivable, net... 2,750,000 (10,336,640) 3,294,727 Other, net..................................... 75,786 (122,244) 97,838 ------------- ------------ ------------ Net cash provided by (used in) investing activities..................................... (2,494,722) (12,088,595) 2,917,252 ------------- ------------ ------------ Cash flows from financing activities: Payment of dividends........................... -- (800,000) (800,000) Borrowings under line of credit................ 46,861,000 14,000,000 -- Repayment of borrowings under line of credit... (60,861,000) -- (52,595,000) Proceeds from Senior Notes Due 2004............ -- -- 105,000,000 Proceeds from Senior Notes Due 2006............ 180,000,000 -- -- Proceeds from issuance of preferred stock...... 50,000,000 -- -- Proceeds from issuance of common stock......... 109,208,298 -- -- Costs associated with future financing......... (5,688,268) 279,012 (3,419,003) Repayment of note payable to shareholder....... -- -- (1,200,000) ------------- ------------ ------------ Net cash provided by financing activities........................... 319,520,030 13,479,012 46,985,997 ------------- ------------ ------------ Net increase (decrease) in cash and cash equivalents.................................... 35,120,660 (7,484,528) 5,149,517 Cash and cash equivalents, beginning of period... (1,970,526) 5,514,002 364,485 ------------- ------------ ------------ Cash and cash equivalents, end of period......... $ 33,150,134 $(1,970,526) $ 5,514,002 ============= ============ ============ Supplementary information: Cash paid during the period for: Interest....................................... $ 19,762,029 $ 9,945,443 $ 4,917,773 Income taxes................................... $ 6,947,000 $ 4,293,725 $ 683,364
The accompanying notes are an integral part of these condensed financial statements. F-44 91 CALPINE CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS DECEMBER 31, 1996 1. ORGANIZATION AND OPERATION OF CALPINE Calpine Corporation ("Calpine") is a Delaware corporation 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 into 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. On September 13, 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. 2. LINES OF CREDIT AND REVOLVING CREDIT FACILITY At December 31, 1996, Calpine had a $50.0 million three-year credit facility available with a consortium of commercial lending institutions which include The Bank of Nova Scotia, International Nederlanden U.S. Capital Corporation, Sumitomo Bank of California and Canadian Imperial Bank of Commerce. As of December 31, 1996, the Company had no borrowings and $5.9 million of letters of credit outstanding, which reflect $3.0 million to secure performance with the Pasadena Power Plant and $2.9 million related to operating expenses at a subsidiary. Borrowings bear interest at The Bank of Nova Scotia's base rate or at 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 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, 1995, Calpine had a $50.0 million credit facility with Credit Suisse (whose parent company owns approximately 44.9% of Electrowatt Ltd. ("Electrowatt"), the former indirect sole owner of Calpine prior to the initial public offering on September 25, 1996. At December 31, 1995, Calpine had $19.9 million of borrowings outstanding, bearing interest at LIBOR plus 0.5% (6.4% at December 31, 1995). Interest was payable at either LIBOR or the Credit Suisse base rate, plus applicable margins in both cases. The credit agreement specified that Calpine maintain certain covenants with which Calpine was in compliance. Calpine terminated its Credit Suisse credit facility on September 25, 1996. At December 31, 1996, Calpine had one loan facility with available borrowings totaling $1.2 million. There were no borrowings and 900,000 of letters of credit outstanding as of December 31, 1996. At December 31, 1995, Calpine had three loan facilities with available borrowings totaling $10.2 million. Borrowings and letters of credit outstanding were $1.2 million and $3.8 million as of December 31, 1995, respectively. Interest is payable at variable interest rates based on bank base rates, LIBOR or prime plus applicable margins in all cases (approximately 7.6% at December 31, 1995 on borrowings). The credit agreements specified that Calpine maintain certain covenants with which Calpine was in compliance. 3. NOTE PAYABLE TO ELECTROWATT On December 31, 1991, Calpine declared a dividend of $1.2 million to its parent company, Electrowatt Services, Inc. On the same date, Calpine issued a note payable to Electrowatt Services, Inc. for $1.2 million. F-45 92 CALPINE CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED) Interest was paid quarterly at a rate of 4.25%, which approximated market. The note was paid on June 30, 1994, the maturity date. 4. SENIOR NOTES On May 16, 1996, the Company issued $180.0 million aggregate principal amount of 10 1/2% Senior Notes Due 2006. The net proceeds of $174.9 million were used to repay $53.7 million of borrowings under the Credit Suisse Credit Facility, $57.0 million of non-recourse project financing and $45.0 million of borrowings from The Bank of Nova Scotia. The remaining $19.2 million was available for general corporate purposes. Transaction costs of $5.1 million incurred in connection with the public debt offering were recorded as a deferred charge and are amortized over the ten-year life of the 10 1/2% Senior Notes Due 2006. 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 $191.7 million as of December 31, 1996. On February 17, 1994, Calpine completed a $105.0 million public debt offering of 9 1/4% Senior Notes Due 2004. Transaction costs of $4.1 million incurred in connection with the public debt offering were recorded as a deferred charge and are amortized over the ten-year life of the 9 1/4% Senior Notes Due 2004. The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. Calpine has no sinking fund or mandatory redemption obligations with respect to the 9 1/4% Senior Notes Due 2006. 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 $105.7 million as of December 31, 1996. The Senior Note indentures specify that Calpine maintain certain covenants with which Calpine was in compliance. Calpine 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. 5. COMMITMENTS AND CONTINGENCIES Capital Projects -- Calpine has 1997 commitments for capital expenditures totaling $4.0 million related to various projects at its geothermal facilities. In March 1996, Calpine entered into an energy development agreement with Phillips Petroleum Company to develop, construct, own and operate a 240 megawatt gas-fired cogeneration facility at Phillips Houston Chemical Complex in Pasadena, Texas. The initial permitting process is underway, with construction of the facility planned to begin in late 1996 and to be completed in 1998. Calpine has 1997 commitments of $97.2 million related to this project. Office and Equipment Leases -- Calpine leases its corporate office, Houston office, Portland office, Santa Rosa office facilities and certain office equipment under noncancellable operating leases expiring through 2001. Future minimum lease payments under these leases are (in thousands): 1997.............................................. $1,138 1998.............................................. 1,125 1999.............................................. 977 2000.............................................. 936 2001.............................................. 367 Thereafter........................................ -- ------ Total future minimum lease commitments............ $4,543 ======
F-46 93 CALPINE CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED) Lease payments are subject to adjustment for Calpine's pro rata portion of annual increases or decreases in building operating costs. In 1996, 1995 and 1994, rent expense for noncancellable operating leases amounted to $1,036,000, $733,000 and $663,000, 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 proposed the transition of the electric generation market to a competitive market beginning January 1, 1998, with all consumers participating by 2003. Since the proposed restructure results in widespread impact on the market structure and requires participation and oversight of the Federal Energy Regulatory Commission ("FERC"), the CPUC has sought to build a California consensus involving the legislature, the Governor, public and municipal utilities and customers. The consensus has resulted in filings with FERC which should permit both the CPUC and FERC to collectively proceed with implementation of the new competitive market structure. On September 23, 1996 state legislation was passed, AB 1890 ("the Bill"), which codified much of the CPUC decision and directed the CPUC to proceed with implementation of restructure no later than January 1, 1998. The Bill accelerated the transition period to a fully competitive market from five years to four years with all consumers participating by year 2002. The Bill provided for an electricity rate freeze for the period of transition and mandated through issuance of rate reduction bonds a 10% rate reduction for small commercial and residential customers effective January 1, 1998. The proposed restructuring provides for phased-in customer choice (direct access), development of a non-discriminatory market structure, full recovery of utility stranded costs, sanctity of existing contracts, and continuation of existing public policy programs including funds for enhancement of in-state renewable energy technologies during the transition period. Calpine cannot predict the final form or timing of the proposed restructuring and the impact, if any, that such restructuring would have on Calpine's existing business or results of operations. Calpine 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. A domestic electricity generating project must be a qualified 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 ("PUHPA"), 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 PSA, 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 -- Calpine, together with over 100 other parties, was named as a defendant in an action brought in August 1993 by the bankruptcy trustee for Bonneville Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et al., in the United States District Court for the District of Utah (the "Court"). In December 1996, the trustee and Calpine entered into a settlement agreement relating to this matter. The trustee has agreed to waive all claims against Calpine and to dismiss the trustee's litigation against Calpine in exchange for a payment of $767,500 by Calpine. Calpine is involved in various other claims and legal actions arising out of the normal course of business. Management does not expect that the outcome of these cases will have a material adverse effect on Calpine's financial position or results of operations. F-47 94 CALPINE CORPORATION VALUATION AND QUALIFYING ACCOUNTS SCHEDULE II (IN THOUSANDS) FOR THE YEAR ENDED DECEMBER 31, 1996
ADDITIONS ------------------------------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF 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 COSTS AND OTHER END OF DESCRIPTION OF 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, 1994
ADDITIONS ------------------------------------------------- BALANCE AT CHARGED TO CHARGED TO BALANCE AT BEGINNING COSTS AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD - -------------------------------------------- ---------- ---------- ---------- ---------- ---------- Reserve for capitalized costs............... $ 800 $1,038 $ -- $ -- $1,838(1) Allowance for uncollectible accounts........ $ -- 238 -- -- $ 238 ====== ====== ====== ====== ======
- --------------- (1) Provision for write-off of project development expenses. F-48 95 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, 1996 and 1995, and the related consolidated statements of income, changes in partners' equity, and cash flows for each of the three years ended December 31, 1996. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sumas Cogeneration Company, L.P. and Subsidiary as of December 31, 1996 and 1995, and the results of their operations and cash flows for each of the three years ended December 31, 1996, in conformity with generally accepted accounting principles. MOSS ADAMS LLP Everett, Washington January 24, 1997 F-49 96 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY CONSOLIDATED BALANCE SHEET
DECEMBER 31, ------------------------------- 1996 1995 ------------ ------------ ASSETS Current assets Cash and cash equivalents................................... $ 317,196 $ 199,169 Current portion of restricted cash and cash equivalents..... 5,787,121 2,937,884 Accounts receivable......................................... 4,605,135 3,090,213 Prepaid expenses............................................ 220,130 222,828 ------------ ------------ Total current assets................................ 10,929,582 6,450,094 Restricted cash and cash equivalents, net of current portion..................................................... 15,666,647 8,017,758 Property, plant and equipment, at cost, net................... 91,737,933 95,589,737 Other assets.................................................. 10,938,732 12,744,480 ------------ ------------ Total assets........................................ $129,272,894 $122,802,069 ============ ============ LIABILITIES AND PARTNERS' EQUITY Current liabilities Accounts payable and accrued liabilities.................... $ 2,988,207 $ 2,051,178 Related party distributions and payables Calpine Corporation payable.............................. 476,390 4,864 National Energy Systems Company payable.................. 1,490 1,861 Whatcom Cogeneration Partners, L.P. distribution......... 3,517,491 -- Current portion of long-term debt........................... 3,600,000 2,000,000 ------------ ------------ Total current liabilities........................... 10,583,578 4,057,903 Related party payable -- Calpine Corporation, net of current portion..................................................... -- 908,679 Long-term debt, net of current portion........................ 113,400,003 117,000,003 Future removal and site restoration costs..................... 679,600 502,600 Deferred income taxes......................................... 988,400 907,800 Commitments................................................... -- -- Partners' equity (deficit).................................... 3,621,313 (574,916) ------------ ------------ Total liabilities and partners' equity.............. $129,272,894 $122,802,069 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-50 97 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, ---------------------------------------------- 1996 1995 1994 ------------ ------------ ------------ Revenues Power sales.................................... $ 43,488,465 $ 30,603,018 $ 29,206,469 Natural gas sales, net......................... 434,611 893,690 2,832,668 Other.......................................... 169,146 29,146 20,490 ------------ ------------ ------------ Total revenues......................... 44,092,222 31,525,854 32,059,627 ------------ ------------ ------------ Costs and expenses Operating and production costs................. 16,852,253 18,493,245 19,032,754 Depletion, depreciation and amortization....... 5,702,310 6,965,496 6,715,156 General and administrative..................... 2,481,470 1,400,129 1,412,326 ------------ ------------ ------------ Total costs and expenses............... 25,036,033 26,858,870 27,160,236 ------------ ------------ ------------ Income from operations........................... 19,056,189 4,666,984 4,899,391 ------------ ------------ ------------ Other income (expense) Interest income................................ 406,537 490,071 436,741 Interest expense............................... (10,678,618) (11,006,056) (10,172,959) Other expense.................................. (133,958) (60,664) (359,000) ------------ ------------ ------------ Total other expense.................... (10,406,039) (10,576,649) (10,095,218) ------------ ------------ ------------ Income (loss) before provision for income taxes.......................................... 8,650,150 (5,909,665) (5,195,827) Provision for income taxes....................... (155,951) (188,387) (581,190) ------------ ------------ ------------ Net income (loss)...................... $ 8,494,199 $ (6,098,052) $ (5,777,017) ============ ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-51 98 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 Partners' Equity, December 31, 1993........................................... $11,300,153 Net loss...................................................................... (5,777,017) ----------- 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 ===========
The accompanying notes are an integral part of these consolidated financial statements. F-52 99 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, -------------------------------------------- 1996 1995 1994 ------------ ----------- ----------- Cash flows from operating activities Net income (loss)................................ $ 8,494,199 $(6,098,052) $(5,777,017) Adjustments to reconcile net income (loss) to net cash from operating activities Depletion, depreciation and amortization...... 6,571,522 6,965,496 6,715,156 Deferred income taxes......................... 80,600 134,000 532,400 Change in operating assets and liabilities Accounts receivable......................... (1,514,922) 1,017,993 (1,254,639) Prepaid expenses............................ 2,698 9,497 (30,342) Accounts payable and accrued liabilities.... 1,114,029 (1,407,621) 1,081,431 Related party distributions and payables.... (437,524) 425,479 132,296 ------------ ----------- ----------- Net cash from operating activities....... 14,310,602 1,046,792 1,399,285 ------------ ----------- ----------- Cash flows from investing activities Decrease (increase) in restricted cash and cash equivalents................................... (10,498,126) 2,908,466 2,922,819 Acquisition of property, plant and equipment..... (913,970) (3,710,025) (3,690,399) Other assets..................................... -- -- (167,483) ------------ ----------- ----------- Net cash from investing activities....... (11,412,096) (801,559) (935,063) ------------ ----------- ----------- Cash flows from financing activities Repayment of long-term debt...................... (2,000,000) (400,000) (400,025) Distributions to partners........................ (780,479) -- -- ------------ ----------- ----------- Net cash from financing activities....... (2,780,479) (400,000) (400,025) ------------ ----------- ----------- Net increase (decrease) in cash and cash equivalents...................................... 118,027 (154,767) 64,197 Cash and cash equivalents, beginning of year....... 199,169 353,936 289,739 ------------ ----------- ----------- Cash and cash equivalents, end of year............. $ 317,196 $ 199,169 $ 353,936 ============ =========== =========== Supplementary disclosure of cash flow information Cash paid for interest during the year........... $ 10,678,618 $11,006,056 $10,172,959 ============ =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. F-53 100 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994 NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) GENERAL -- Sumas Cogeneration Company, L.P. (the Partnership) is a Delaware limited partnership formed on August 28, 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. The Partnership agreement specifies that certain preferential distributions are paid to SEI and Whatcom. 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 has acquired and is operating and developing a portfolio of proven 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 incidental 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 Power & Light Company (Puget) under a 20-year electricity sales contract. 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 megawatt hours of electricity to Puget as follows:
MEGAWATT YEAR ENDED DECEMBER 31, HOURS REVENUE ---------------------------------------------------- --------- ----------- 1996................................................ 1,031,900 $43,488,000 1995................................................ 1,026,000 $30,603,000 1994................................................ 1,000,400 $29,206,000
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 (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. (b) 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. SEI and Whatcom are both currently entitled to a 50% interest in the profits and losses of the Partnership, after the payment of certain preferential distributions to Whatcom of approximately $2,756,000 and $6,239,000 at December 31, 1996 and 1995, respectively, and to SEI of approximately $536,000 and $441,000 at December 31, 1996 and 1995, respectively. A portion of these preferential distributions compound at 20% per annum. After Whatcom has received cumulative distributions representing a fixed rate-of-return of 24.5% on its equity investment, exclusive of the preferential distributions referred to above, SEI's share of operating distributions will increase to 88.67% and Whatcom's share of operating distributions will decrease to 11.33%. F-54 101 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (c) 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, 1996, distributions totaling $4,297,970 were paid or accrued. As of January 31, 1997, the accrued balance of $3,517,491 of distributions were paid. No distributions were paid or accrued for the years ended December 31, 1995 and 1994. (d) REVENUE RECOGNITION -- Revenue from the sale of electricity is recognized based on kilowatt hours generated and delivered to Puget at contractual rates. 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. (e) GAS ACQUISITION AND DEVELOPMENT COSTS -- ENCO follows the full cost method of accounting for gas acquisition and development expenditures, wherein all costs related to the development of gas reserves in Canada are initially capitalized. Costs capitalized include land acquisition costs, geological and geophysical expenditures, rentals on undeveloped properties, cost of drilling productive and nonproductive wells, and well equipment. Gains or losses are not recognized upon disposition or abandonment of natural gas properties unless a disposition or abandonment would significantly alter the relationship between capitalized costs and proven reserves. All capitalized costs of gas properties, including the estimated future costs to develop proven reserves, are depleted using the unit-of-production method based on estimated proven gas reserves as determined by independent engineers. ENCO has not assigned any value to its investment in unproven gas properties and, accordingly, no costs have been excluded from capitalized costs subject to depletion. Costs subject to depletion under the full cost method include estimated future costs of dismantlement and abandonments of $3,718,000 in 1996, $3,748,000 in 1995 and $3,630,000 in 1994. 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 $177,000 in 1996, $193,000 in 1995 and $169,000 in 1994 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%. (f) JOINT VENTURE ACCOUNTING -- Substantially all 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. (g) 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. (h) 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, excluding restricted cash and cash equivalents. (i) 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 F-55 102 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. (j) 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. (k) 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.................................. 15 years Gas contract costs............................... 20 years
(l) INCOME TAXES -- Profits or losses of the Partnership are passed 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. (m) 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. NOTE 2 -- PROPERTY, PLANT AND EQUIPMENT
DECEMBER 31, ----------------------------- 1996 1995 ------------ ------------ Land and land improvements...................... $ 381,071 $ 381,071 Plant and equipment............................. 84,152,257 84,061,359 Acquisition of gas properties, including development thereon........................... 25,838,035 25,030,165 Furniture and fixtures.......................... 211,116 195,914 ------------ ------------ 110,582,479 109,668,509 Less accumulated depreciation and depletion..... 18,844,546 14,078,772 ------------ ------------ $ 91,737,933 $ 95,589,737 ============ ============
Depreciation expense was $3,159,774 in 1996, $3,316,748 in 1995 and $3,069,446 in 1994. Depletion expense was $1,606,000 in 1996, $1,843,000 in 1995 and $1,671,000 in 1994. F-56 103 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 3 -- OTHER ASSETS
DECEMBER 31, --------------------------- 1996 1995 ----------- ----------- Organization, start-up and development costs...... $ 4,844,015 $ 6,165,574 Financing costs................................... 3,909,886 4,254,719 Gas contract costs................................ 2,184,831 2,324,187 ----------- ----------- $10,938,732 $12,744,480 =========== ===========
NOTE 4 -- LONG-TERM DEBT The Partnership and ENCO have loan agreements with The Prudential Insurance Company of America (Prudential) and Credit Suisse (collectively, the Lenders). Through September 1996, Credit Suisse was an affiliate of Whatcom. At December 31, 1996 and 1995, amounts outstanding under the term loan agreements, by entity, were as follows:
DECEMBER 31, ----------------------------- 1996 1995 ------------ ------------ Sumas Cogeneration Company, L.P................. $ 92,781,003 $ 94,367,003 ENCO Gas, Ltd................................... 24,219,000 24,633,000 ------------ ------------ 117,000,003 119,000,003 Less current portion............................ 3,600,000 2,000,000 ------------ ------------ $113,400,003 $117,000,003 ============ ============
Scheduled annual principal payments under the loan agreements as of December 31, 1996 are as follows:
YEAR ENDING DECEMBER 31, AMOUNT --------------------------------------------------------------- ------------ 1997........................................................... $ 3,600,000 1998........................................................... 4,200,000 1999........................................................... 5,400,000 2000........................................................... 7,200,000 2001........................................................... 10,800,000 Thereafter..................................................... 85,800,003 ------------ $117,000,003 ============
The Partnership's loan is 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 quarterly 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 2.25% to .875% as stated in the loan agreement. During the year ended December 31, 1996, interest rates on the variable rate loan ranged from 6.94% to 7.38%. The loans mature in May 2008. ENCO's loan is 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 quarterly at either the LIBOR, certificate of deposit rate or Credit Suisse's base rate, plus an applicable margin as stated in the loan agreement. During the year ended December 31, 1996, interest rates on the variable rate loan ranged from 6.94% to 7.38%. The loans mature in May 2008. F-57 104 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Partnership pays Prudential an agency fee of $50,000 per year, adjusted annually by an inflation index, 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. NOTE 5 -- INCOME TAXES The provision for income taxes represents Canadian taxes which consist of the following:
YEAR ENDED DECEMBER 31, ---------------------------------- 1996 1995 1994 -------- -------- -------- Current Federal large corporation tax.................... $ 41,340 $ 34,625 $ 31,314 British Columbia capital taxes................... 34,011 19,762 17,476 -------- -------- -------- 75,351 54,387 48,790 Deferred........................................... 79,744 135,400 178,400 -------- -------- -------- 155,095 189,787 227,190 Utilization of loss carryforwards for Canadian income tax purposes.............................. -- 47,700 259,000 Reduction of (increase in) Canadian loss carryforwards due to foreign exchange and other adjustments...................................... 856 (49,100) 95,000 -------- -------- -------- $155,951 $188,387 $581,190 ======== ======== ========
The principal sources of temporary differences resulting in deferred tax assets and liabilities are as follows:
DECEMBER 31, ------------------------- 1996 1995 ---------- ---------- Deferred tax asset Canadian net operating loss carryforwards......... $ (919,400) $ (840,900) Deferred tax liabilities Acquisition and development costs of gas deducted for tax purposes in excess of amounts deducted for financial reporting purposes............... 1,907,800 1,748,700 ---------- ---------- Net deferred tax liability..................... $ 988,400 $ 907,800 ========== ==========
F-58 105 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The provision for income taxes differs from the Canadian statutory rate principally due to the following:
YEAR ENDED DECEMBER 31, ---------------------------------- 1996 1995 1994 -------- -------- -------- Canadian statutory rate............................ 44.62% 44.62% 44.34% Income taxes based on statutory rate............... $(45,824) $(33,852) $ 82,909 Capital taxes, net of deductible portion........... 60,175 47,028 36,678 Non-deductible provincial royalties, net of resource allowance............................... 123,464 95,671 39,836 Depletion on gas properties with no tax basis...... 36,488 44,641 38,420 Foreign exchange adjustments....................... 16,362 14,860 29,347 Other.............................................. (35,570) 21,439 -- -------- -------- -------- $155,095 $189,787 $227,190 ======== ======== ========
As of December 31, 1996, ENCO has non-capital loss carryforwards of approximately $2,061,000, which may be applied against taxable income of future periods which expire as follows: 1999............................................. $1,619,000 2000............................................. $ 260,000 2003............................................. $ 182,000
NOTE 6 -- RELATED PARTY TRANSACTIONS AND COMMITMENTS (a) 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 $311,000 in 1996, $258,000 in 1995 and $253,000 in 1994 was paid to SEI under this agreement. (b) 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 anniversary of the Project completion date, subject to renewal terms. Approximately $2,014,000 in 1996, $2,031,000 in 1995 and $1,946,000 in 1994 was earned under this agreement. (c) 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, $19,000 in 1995 and $61,000 in 1994. (d) 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 $107,000 in 1996, $100,000 in 1995 and $101,000 in 1994 was paid under this agreement. F-59 106 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (e) 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 gas supply agreements with Westcoast Gas Services, Inc. (WGSI) to provide the Partnership with quantities of firm gas. Commencing April 1, 1993, WGSI must provide the Partnership with quantities of gas ranging from 10,000 MMBtu's per day up to 12,900 MMBtu's per day at a firm price, as provided under the agreements. Deliveries under the agreement are expected to terminate on October 31, 1997. The Partnership and ENCO have a gas management agreement with WGSI. WGSI is paid a gas management fee for each MMBtu of gas delivered. 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. ENCO is committed to the utilization of pipeline capacity on the Westcoast Energy Inc. System. These firm capacity commitments are predominantly under one-year renewable contracts. Firm capacity has been accepted at an annual cost of approximately $3,526,000 in 1996, $2,569,000 in 1995 and $2,776,000 in 1994. As collateral for the obligations of the Company under the gas supply and gas management agreements with WGSI, the Partnership secured an irrevocable standby letter of credit with Credit Suisse in favor of WGSI. In January 1996, the face amount of the letter of credit was reduced, in accordance with its terms, from $2,500,000 to $500,000. Accordingly, the required balance in the cash collateral account supporting the letter of credit was reduced from $2,500,000 to $500,000. As of December 31, 1996, the letter of credit had a face amount of $500,000 and the Partnership had a restricted cash deposit of $500,000. As of December 31, 1995, the letter of credit had a face amount of $2,500,000 and the Partnership had a restricted cash deposit of $2,500,000. (f) UTILITY SERVICES -- The Partnership entered into an agreement for utility services with the City of Sumas, Washington. The City of Sumas has agreed to provide a guaranteed annual 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. The Partnership entered into 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 received a permit for waste water disposal from the Washington State Department of Ecology which expires June 30, 2000. (g) 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 $56,600 in 1996 and $48,400 in 1995 and 1994. In April 1992, ENCO signed an operating lease for office space which expires in March 1997. Monthly rental expense is approximately $1,700. Rental expense was approximately $20,400 in 1996, $17,700 in 1995 and $17,000 in 1994. F-60 107 SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Future minimum land and office lease commitments as of December 31, 1996 are as follows:
YEAR ENDING DECEMBER 31, AMOUNT ----------------------------------------------------------------- ---------- 1997............................................................. $ 51,000 1998............................................................. 49,300 1999............................................................. 49,300 2000............................................................. 52,500 2001............................................................. 55,700 Thereafter....................................................... 812,600 ---------- $1,070,400 ==========
(h) PARTNER LOAN -- In March 1994, the sole shareholder of SEI borrowed $10,000,000 from Calpine. The loan bears interest at 16.25%, compounded quarterly, and is collateralized by a subordinated assignment in SEI's interest in the Partnership and a subordinated pledge of SEI's stock. The loan requires payments of interest and principal to be made from 50% of SEI's cash distributions from the Partnership, less amounts due to Whatcom under a previous note. On March 15, 2004, all unpaid principal and interest on the loan is due. NOTE 7 -- FAIR VALUES OF FINANCIAL INSTRUMENTS The carrying amount of all cash and cash equivalents 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 long-term debt with a carrying amount of $117,000,003 and $119,000,003 at December 31, 1996 and 1995, 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-61 108 EXHIBIT 11 CALPINE CORPORATION AND SUBSIDIARIES CALCULATION OF EARNINGS PER SHARE (AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
FOR YEAR ENDING DECEMBER 31, ------------------- 1996 1995 ------- ------- Net income............................................................... $18,692 $ 7,378 ======= ======= Primary earnings per share Average number of common shares outstanding............................ 12,293 Conversion of preferred stock.......................................... 1,700 Common shares issuable upon exercise of stock options using the treasury method..................................................... 687 ------- 14,680 ------- Primary earnings per share.......................................... $ 1.27 ======= Fully diluted earnings per share Average number of common shares outstanding............................ 12,293 Conversion of preferred stock.......................................... 1,700 Common shares issuable upon exercise of stock options using the treasury method..................................................... 1,137 ------- 15,130 ------- Fully diluted earnings per share.................................... $ 1.24 ======= As adjusted primary earnings per share assuming conversion of preferred stock Average number of common shares outstanding............................ 10,388 Assumed conversion of preferred stock.................................. 2,179 Common shares issuable upon exercise of stock options using the treasury method..................................................... 1,584 ------- 14,151 ------- As adjusted primary earnings per share.............................. $ 0.52 =======
109 EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION - ----------- -------------------------------------------------------------------------------- 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. 10.3.11 Amended and Restated Energy Sales Agreement, dated December 16, 1996, between Phillips Petroleum Company and Pasadena Cogeneration, L.P. 27 Financial Data Schedule
EX-10.1.17 2 CREDIT AGREEMENT, DATED DECEMBER 20, 1996 1 EXHIBIT 10.1.17 ================================================================================ CREDIT AGREEMENT among PASADENA COGENERATION L.P., a Delaware limited partnership (Borrower) and ING (U.S.) CAPITAL CORPORATION (Agent for the Banks) and THE BANKS PARTIES HERETO _________________________________ 240 MW Cogeneration Facility Pasadena, Texas ============================================================================== 2 TABLE OF CONTENTS
PAGE ---- ARTICLE 1 - DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1.1 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1.2 Rules of Interpretation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 ARTICLE 2 - THE CREDIT FACILITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2.1 Loan Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2.1.1 Construction Loan Facility . . . . . . . . . . . . . . . . . . . . . . . . . 1 2.1.2 Term Loan Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 2.1.3 Interest Provisions Relating to All Loans . . . . . . . . . . . . . . . . . 4 2.1.4 Promissory Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 2.1.5 Loan Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 2.1.6 Conversion of Loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 2.1.7 Prepayments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 2.2 Total Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 2.2.1 Loan Commitment Amounts . . . . . . . . . . . . . . . . . . . . . . . . . . 8 2.2.2 Reductions and Cancellations . . . . . . . . . . . . . . . . . . . . . . . . 8 2.3 Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2.3.1 Advisory Fee; Syndication Fee . . . . . . . . . . . . . . . . . . . . . . . 9 2.3.2 Annual Agency Fee . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2.3.3 Loan Commitment Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2.4 Other Payment Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2.4.1 Place and Manner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2.4.2 Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2.4.3 Late Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2.4.4 Net of Taxes, Etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 2.4.5 Application of Payments . . . . . . . . . . . . . . . . . . . . . . . . . . 11 2.4.6 Failure to Pay Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 2.4.7 Withholding Exemption Certificates . . . . . . . . . . . . . . . . . . . . . 12 2.5 Pro Rata Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 2.5.1 Borrowings, Commitment Reductions, Etc. . . . . . . . . . . . . . . . . . . 12 2.5.2 Sharing of Payments, Etc. . . . . . . . . . . . . . . . . . . . . . . . . . 13 2.6 Change of Circumstances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2.6.1 Inability to Determine Rates . . . . . . . . . . . . . . . . . . . . . . . . 13 2.6.2 Illegality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2.6.3 Increased Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 2.6.4 Capital Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 2.6.5 Notice; Participating Banks' Rights . . . . . . . . . . . . . . . . . . . . 15 2.7 Funding Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 2.8 Alternate Office; Minimization of Costs . . . . . . . . . . . . . . . . . . . . . . 15
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Page ---- ARTICLE 3 - CONDITIONS PRECEDENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 3.1 Conditions Precedent to the Closing Date . . . . . . . . . . . . . . . . . . . . . 16 3.1.1 Resolutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 3.1.2 Incumbency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 3.1.3 Formation Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 3.1.4 Good Standing Certificates . . . . . . . . . . . . . . . . . . . . . . . . . 17 3.1.5 Satisfactory Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . 17 3.1.6 Operative Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 3.1.7 Certificate of Borrower . . . . . . . . . . . . . . . . . . . . . . . . . . 18 3.1.8 Legal Opinions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 3.1.9 Certificate of Insurance Consultant . . . . . . . . . . . . . . . . . . . . 18 3.1.10 Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 3.1.11 Certificate of the Independent Engineer . . . . . . . . . . . . . . . . . . 18 3.1.12 Reports of the Borrower's Environmental Consultant . . . . . . . . . . . . . 18 3.1.13 Certificate of the Fuel Consultant . . . . . . . . . . . . . . . . . . . . . 18 3.1.14 Certificate of Power Marketing Consultant . . . . . . . . . . . . . . . . . 18 3.1.15 Power Marketing Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 3.1.16 Schedule of Applicable Permits and Applicable Third Party Permits . . . . . 19 3.1.17 No Change in Tax Laws . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 3.1.18 Absence of Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 3.1.19 Payment of Filing Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 3.1.20 Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 3.1.21 UCC Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 3.1.22 Project Budget . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 3.1.23 Base Case Project Projections . . . . . . . . . . . . . . . . . . . . . . . 20 3.1.24 No Material Adverse Change . . . . . . . . . . . . . . . . . . . . . . . . . 20 3.1.25 A.L.T.A. Surveys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 3.1.26 Title Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 3.1.27 Qualifying Facility Status . . . . . . . . . . . . . . . . . . . . . . . . . 21 3.1.28 Notice to Proceed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 3.1.29 Establishment of Accounts . . . . . . . . . . . . . . . . . . . . . . . . . 22 3.1.30 Representations and Warranties of Partners and Borrower . . . . . . . . . . 22 3.1.31 Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 3.1.32 Interest Rate Hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 3.1.33 Key Personnel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 3.1.34 Project Schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 3.1.35 Reports of Borrower's Tax Consultants . . . . . . . . . . . . . . . . . . . 22 3.1.36 Reports of Borrower's HCC Evaluation Consultant . . . . . . . . . . . . . . 22 3.1.37 Phillips Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 3.2 Conditions Precedent to Each Construction Credit Event . . . . . . . . . . . . . . 23
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Page ---- 3.2.1 Credit Event Conditions Satisfied . . . . . . . . . . . . . . . . . . . . . 23 3.2.2 Monthly Drawdown Frequency . . . . . . . . . . . . . . . . . . . . . . . . . 23 3.2.3 Notice of Borrowing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 3.2.4 Drawdown Certificate and Engineer's Certificate . . . . . . . . . . . . . . 23 3.2.5 Amount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 3.2.6 Title Policy Endorsement . . . . . . . . . . . . . . . . . . . . . . . . . . 23 3.2.7 Lien Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 3.2.8 Applicable Permits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 3.2.9 Equity Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 3.2.10 Additional Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . 24 3.2.11 Acceptable Work; No Liens . . . . . . . . . . . . . . . . . . . . . . . . . 24 3.2.12 Casualty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 3.2.13 Absence of Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 3.2.14 Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 3.2.15 Key Personnel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 3.3 Conditions Precedent to Term-Conversion . . . . . . . . . . . . . . . . . . . . . . 25 3.3.1 Payment of Obligations. . . . . . . . . . . . . . . . . . . . . . . . . . 25 3.3.2 Final Drawing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 3.3.3 Certificates of Occupancy . . . . . . . . . . . . . . . . . . . . . . . . . 26 3.3.4 Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 3.3.5 Equity Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 3.3.6 Annual Budget . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 3.3.7 Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 3.3.8 Reserve Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 3.4 Conditions Precedent to Each Credit Event . . . . . . . . . . . . . . . . . . . . . 27 3.4.1 Representations and Warranties True and Correct . . . . . . . . . . . . . . 27 3.4.2 No Event of Default or Inchoate Default . . . . . . . . . . . . . . . . . . 27 3.4.3 Operative Documents, Applicable Permits and Applicable Third Party Permits in Effect . . . . . . . . . . . . . . . . . . . . . . . 27 3.4.4 No Material Adverse Effect . . . . . . . . . . . . . . . . . . . . . . . . . 27 3.5 Conditions Precedent to Initial Distribution . . . . . . . . . . . . . . . . . . . 27 3.5.1 Term-Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 3.5.2 Revised Base Case Projections . . . . . . . . . . . . . . . . . . . . . . . 27 3.5.3 Delivery of Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 3.5.4 Applicable Permits and Applicable Third Party Permits . . . . . . . . . . . 27 3.5.5 A.L.T.A. Surveys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 3.5.6 Term Loan Title Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 3.5.7 Power Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 3.6 No Approval of Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 3.7 Waiver of Funding; Adjustment of Drawdown Requests . . . . . . . . . . . . . . . . 29 ARTICLE 4 - REPRESENTATIONS AND WARRANTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
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Page ---- 4.1 Organization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 4.2 Authorization; No Conflict . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 4.3 Enforceability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 4.4 Compliance with Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 4.5 Business, Debt, Contracts, Joint Ventures Etc. . . . . . . . . . . . . . . . . . . 30 4.6 Adverse Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 4.7 Investment Company Act, Etc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 4.8 ERISA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 4.9 Permits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 4.10 Qualifying Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 4.11 Hazardous Substance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 4.12 Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 4.13 Labor Disputes and Acts of God . . . . . . . . . . . . . . . . . . . . . . . . . . 33 4.14 Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 4.15 Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 4.16 Private Offering by Borrower . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 4.17 Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 4.18 Governmental Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 4.19 Regulation U, Etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 4.20 Project Budget; Projections; Commercial Operation Date . . . . . . . . . . . . . . 34 4.21 Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 4.22 Existing Defaults . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 4.23 No Default . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 4.24 Offices, Location of Collateral . . . . . . . . . . . . . . . . . . . . . . . . . . 35 4.25 Title and Liens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 4.26 Trademarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 4.27 Collateral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 4.28 Sufficiency of Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . 36 4.29 Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 4.30 Roads/Transmission Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 4.31 Proper Subdivision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 4.32 Flood Zone Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 ARTICLE 5 - COVENANTS OF THE BORROWER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 5.1 Use of Proceeds and Project Revenues . . . . . . . . . . . . . . . . . . . . . . . 38 5.1.1 Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 5.1.2 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 5.2 Payment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 5.2.1 Credit Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 5.2.2 Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 5.3 Warranty of Title . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 5.4 Notices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
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Page ---- 5.5 Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 5.6 Books, Records, Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 5.7 Compliance with Laws, Instruments, Etc. . . . . . . . . . . . . . . . . . . . . . . 42 5.8 Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 5.9 Existence, Conduct of Business, Properties, Etc. . . . . . . . . . . . . . . . . . 43 5.10 Debt Service Coverage Ratios . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 5.11 Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 5.12 Qualifying Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 5.13 Construction of Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 5.14 Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 5.15 Operation of Project and Annual Operating Budget . . . . . . . . . . . . . . . . . 47 5.16 Adjustments to Project Projections . . . . . . . . . . . . . . . . . . . . . . . . 48 5.17 Preservation of Rights; Further Assurances . . . . . . . . . . . . . . . . . . . . 50 5.18 Project Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 5.19 Maintenance of Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 5.20 Taxes, Other Government Charges and Utility Charges . . . . . . . . . . . . . . . . 53 5.21 Event of Eminent Domain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 5.22 Interest Rate Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 5.22.1 Interest Rate Agreements . . . . . . . . . . . . . . . . . . . . . . . . . 54 5.22.2 Hedge Breaking Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 5.22.3 Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 5.22.4 Bank Participation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 5.23 Alternative Thermal Host Action Plan . . . . . . . . . . . . . . . . . . . . . . . 55 5.24 Performance Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 5.25 Power Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 5.25.1 Replacement of Power Marketer . . . . . . . . . . . . . . . . . . . . . . . 55 5.25.2 Requests for Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . 56 5.25.3 Firm Sales to HL&P . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 5.25.4 Arrangements with Power Marketer . . . . . . . . . . . . . . . . . . . . . 56 5.26 Auxiliary Boilers Contractor . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 5.27 Construction Management Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 5.28 Operating Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 5.29 Stand-Alone Easements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 5.30 Extension of Lease, Lease of Expansion Property . . . . . . . . . . . . . . . . . . 58 5.31 License from Port Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 5.32 Phillips License from Port Authority . . . . . . . . . . . . . . . . . . . . . . . 58 5.33 Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 5.34 Option Title Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 ARTICLE 6 - NEGATIVE COVENANTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 6.1 Contingent Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 6.2 Limitations on Liens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
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Page ---- 6.3 Indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 6.4 Sale or Lease of Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 6.5 Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 6.6 Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 6.7 Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 6.8 Transactions With Affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 6.9 Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 6.10 ERISA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 6.11 Partnerships, etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 6.12 Dissolution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 6.13 Amendments; Change Orders; Completion. . . . . . . . . . . . . . . . . . . . . . . 60 6.14 Compliance with Operative Documents . . . . . . . . . . . . . . . . . . . . . . . . 62 6.15 Name and Location; Fiscal Year . . . . . . . . . . . . . . . . . . . . . . . . . . 62 6.16 Use of Project Site . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 6.17 Assignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 6.18 Abandonment of Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 6.19 Hazardous Substance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 6.20 Additional Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 6.21 Project Budget Amendments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 ARTICLE 7 - APPLICATION OF FUNDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 7.1 Construction Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 7.1.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 66 7.1.2 Disbursements from Construction Account . . . . . . . . . . . . . . . . . . 66 7.1.3 Rights of Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 7.1.4 Proceeds of the Final Drawing . . . . . . . . . . . . . . . . . . . . . . . 67 7.1.5 Disbursements Following Term-Conversion . . . . . . . . . . . . . . . . . . 68 7.2 Revenue Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 7.2.1 Establishment of Account; Priority of Payments . . . . . . . . . . . . . . . 68 7.2.2 O&M Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 7.2.3 Subordinated Fuel Costs . . . . . . . . . . . . . . . . . . . . . . . . . . 70 7.2.4 Subordinated O&M Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 7.2.5 Mandatory Prepayment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 7.3 Major Maintenance Reserve Account . . . . . . . . . . . . . . . . . . . . . . . . . 71 7.3.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 71 7.3.2 Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 7.3.3 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 7.3.4 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 7.4 Emissions Offsets Reserve Account . . . . . . . . . . . . . . . . . . . . . . . . . 72 7.4.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 72 7.4.2 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 7.4.3 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
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Page ---- 7.4.4 Letters of Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 7.5 Fuel Supply Reserve Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 7.5.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 73 7.5.2 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 7.5.3 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 7.5.4 Letters of Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 7.6 Debt Service Reserve Account . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 7.6.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 74 7.6.2 Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 7.6.3 Replenishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 75 7.6.4 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 7.6.5 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 7.6.6 Letters of Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 7.7 Operating Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 7.7.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 76 7.7.2 Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 7.7.3 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 7.8 Loss Proceeds Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 7.9 Accrual Sub-Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 7.9.1 Establishment of Sub-Account . . . . . . . . . . . . . . . . . . . . . . . . 76 7.9.2 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 7.9.3 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 7.10 Distribution Suspense Account; Initial Distribution Suspense Account . . . . . . . 77 7.10.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 77 7.10.2 Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 7.10.3 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 7.11 Application of Insurance Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . 78 7.11.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 7.11.2 Business Interruption Insurance . . . . . . . . . . . . . . . . . . . . . . 78 7.11.3 Applications; Mandatory Prepayments . . . . . . . . . . . . . . . . . . . . 78 7.11.4 Proceeds Less than $1,000,000 . . . . . . . . . . . . . . . . . . . . . . . 79 7.11.5 Proceeds in Excess of $1,000,000, Not in Excess of $5,000,000 . . . . . . . 79 7.11.6 Proceeds in Excess of $5,000,000 . . . . . . . . . . . . . . . . . . . . . . 79 7.11.7 Repair and Restoration Procedures . . . . . . . . . . . . . . . . . . . . . 80 7.11.8 Excess Insurance Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . 80 7.11.9 Events of Default . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 7.12 Application of Eminent Domain Proceeds . . . . . . . . . . . . . . . . . . . . . . 81 7.13 Application of Certain Damages Payments; Mandatory Prepayments . . . . . . . . . . 81 7.13.1 Contractor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 7.13.3 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 7.14 Security Interest in Proceeds and Accounts . . . . . . . . . . . . . . . . . . . . 81
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Page ---- 7.15 Permitted Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 7.16 Earnings on Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 7.17 Dominion and Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 7.18 Termination of Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 ARTICLE 8 - EVENTS OF DEFAULT; REMEDIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 8.1 Events of Default . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 8.1.1 Failure to Make Payments . . . . . . . . . . . . . . . . . . . . . . . . . . 82 8.1.2 Judgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 8.1.3 Misstatements; Omissions . . . . . . . . . . . . . . . . . . . . . . . . . . 83 8.1.4 Bankruptcy; Insolvency . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 8.1.5 Debt Cross Default . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 8.1.6 ERISA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 8.1.7 Breach of Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . 84 (a) Borrower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 (b) Third Party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 (c) Termination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 8.1.8 Breach of Terms of Agreement . . . . . . . . . . . . . . . . . . . . . . . . 85 8.1.9 Term-Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86 8.1.10 Conditions to Initial Distributions . . . . . . . . . . . . . . . . . . . . 86 8.1.11 Loss of Qualifying Facility Status . . . . . . . . . . . . . . . . . . . . . 86 8.1.12 Abandonment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86 8.1.13 Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86 8.1.14 Loss of Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 8.1.15 Loss of or Failure to Obtain Applicable Permits or Applicable Third Party Permits . . . . . . . . . . . . . . . . . . . . . . 87 8.1.16 Loss of Collateral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 8.1.17 Material Adverse Effect . . . . . . . . . . . . . . . . . . . . . . . . . . 88 8.2 Remedies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 8.2.1 No Further Loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 8.2.2 Cure by Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 8.2.3 Acceleration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 8.2.4 Cash Collateral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 8.2.5 Possession of Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 8.2.6 Remedies Under Credit Documents . . . . . . . . . . . . . . . . . . . . . . . 89 ARTICLE 9 - SCOPE OF LIABILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 ARTICLE 10 - THE AGENT; SUBSTITUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90 10.1 Appointment, Powers and Immunities . . . . . . . . . . . . . . . . . . . . . . . . 90 10.2 Reliance by Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91 10.3 Non-Reliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
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Page ---- 10.4 Defaults . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 10.5 Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 10.6 Successor Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 10.7 Authorization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 10.8 Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 10.9 Amendments; Waivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 10.10 Withholding Tax . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94 10.11 General Provisions as to Payments . . . . . . . . . . . .. . . . . . . . . . . . . 95 10.12 Substitution of Bank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 10.13 Participation . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . 95 10.14 Transfer of Commitment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96 10.15 Laws . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . 96 10.16 Assignability to Federal Reserve Bank . . . . . . . . . . . . . . . . . . . . . . 96 ARTICLE 11 - INDEPENDENT CONSULTANTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 11.1 Removal and Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 11.2 Duties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 11.3 Independent Consultants' Certificates . . . . . . . . . . . . . . . . . . . . . . . 97 11.4 Certification of Dates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 ARTICLE 12 - MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 12.1 Addresses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 12.2 Additional Security; Right to Set-Off . . . . . . . . . . . . . . . . . . . . . . . 99 12.3 Delay and Waiver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99 12.4 Costs, Expenses and Attorneys' Fees; Syndication . . . . . . . . . . . . . . . . . 99 12.5 Entire Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 12.6 Governing Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 12.7 Severability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 12.8 Headings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 12.9 Accounting Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 12.10 Additional Financing . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . 100 12.11 No Partnership, Etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 12.12 Deed of Trust/Collateral Documents . . . . . . . . . . . . .. . . . . . . . . . . . 101 12.13 Limitation on Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 12.14 Waiver of Jury Trial . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . 101 12.15 Consent to Jurisdiction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 12.16 Usury . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . 102 12.17 Knowledge and Attribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102 12.18 Successors and Assigns . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . 102 12.19 Counterparts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
ix 11 INDEX OF EXHIBITS Exhibit A Definitions and Rules of Interpretation NOTES Exhibit B-1 Form of Construction Note Exhibit B-2 Form of Term Note LOAN DISBURSEMENT PROCEDURES Exhibit C-1 Form of Notice of Borrowing Exhibit C-2 Form of Notice of Term-Conversion Exhibit C-3 Form of Confirmation of Interest Period Selection Exhibit C-4 Form of Notice of Conversion of Loan Type Exhibit C-5 Form of Drawdown Certificate Exhibit C-6 Form of Engineer's Certificate Exhibit C-7 Form of Disbursement Requisition Exhibit C-8 Form of Reserve Account Disbursement Requisition EQUITY AND SECURITY-RELATED DOCUMENTS Exhibit D-1 Form of Depositary Agreement Exhibit D-2A Form of Equity Commitment Guaranty Exhibit D-2B Form of Contingent Equity Guaranty Exhibit D-3 Form of Deed of Trust Exhibit D-4 Form of Security Agreement Exhibit D-5 Form of Partnership Interest Pledge and Security Agreement Exhibit D-6 Form of Shareholder Pledge and Security Agreement Exhibit D-7 Form of Plant Operator Subordination Agreement Exhibit D-8 Form of Lien Subordination Agreement Exhibit D-9 Form of Subordination Agreement (Subordinated Debt) Exhibit D-10 Schedule of Permitted Encumbrances Exhibit D-11 Schedule of Security Filings CONSENTS Exhibit E-1 Form of Consent for Contracting Party Exhibit E-2 Schedule of Closing Date Consents CLOSING CERTIFICATES Exhibit F-1 Form of Borrower's Closing Certificate Exhibit F-2 Form of Insurance Consultant's Certificate Exhibit F-3 Form of Independent Engineer's Certificate Exhibit F-4 Form of Fuel Consultant's Certificate Exhibit F-5 Form of Power Marketing Consultant's Certificate PROJECT DESCRIPTION EXHIBITS Exhibit G-1 Description of Project
x 12 Exhibit G-2 Power Marketing Plan Exhibit G-3 Schedule of Applicable Permits Exhibit G-4 Project Budget Exhibit G-5 Base Case Project Projections Exhibit G-6 Project Schedule Exhibit G-7 Pending Litigation Exhibit G-8 Hazardous Substances Disclosure OTHER Exhibit H Banks/Lending Offices Exhibit I Amortization Schedule Exhibit J-1 Form of Withholding Certificate (Treaty) Exhibit J-2 Form of Withholding Certificate (Effectively Connected) Exhibit K Insurance Requirements Exhibit L Annual Insurance Consultant's Certificate Exhibit M Dispute Resolution
xi 13 THIS CREDIT AGREEMENT (this "Agreement") dated as of December 20, 1996, is entered into among PASADENA COGENERATION L.P., a Delaware limited partnership, as Borrower, the financial institutions listed on Exhibit H or who later become a party hereto (the "Banks") and ING (U.S.) CAPITAL CORPORATION, as Agent for the Banks. In consideration of the agreements herein and in the other Credit Documents and in reliance upon the representations and warranties set forth herein and therein, the parties agree as follows: ARTICLE 1 - DEFINITIONS 1.1 Definitions. Except as otherwise expressly provided, capitalized terms used in this Agreement and its exhibits shall have the meanings given in Exhibit A. 1.2 Rules of Interpretation. Except as otherwise expressly provided, the rules of interpretation set forth in Exhibit A shall apply to this Agreement and the other Credit Documents. ARTICLE 2 - THE CREDIT FACILITIES 2.1 Loan Facilities. 2.1.1 Construction Loan Facility. (a) Availability. Subject to the terms and conditions set forth in this Agreement, each Bank severally agrees to advance to Borrower from time to time during the Construction Loan Availability Period such loans as Borrower may request under this Section 2.1.1 (individually, a "Construction Loan" and collectively the "Construction Loans"), in an aggregate principal amount not to exceed such Bank's Construction Loan Commitment. (b) Notice of Borrowing. Borrower shall request Construction Loans by delivering to Agent a written notice in the form of Exhibit C-1, appropriately completed (a "Notice of Borrowing"), which specifies, among other things: (i) The principal portion of the requested Borrowing which will bear interest as provided in (1) Section 2.1.1(c)(i) (individually, a "Base Rate Construction Loan") and/or (2) Section 2.1.1(c)(ii) (individually, a "LIBOR Construction Loan"); (ii) The amount of the requested Borrowing, which shall be in the minimum amount of $1,000,000 or an integral multiple of $10,000 in excess thereof; (iii) The date of the requested Borrowing, which shall be a Banking Day; and (iv) If the requested Borrowing is to consist of LIBOR Construction Loans, the initial Interest Periods selected by Borrower for such Loans. 14 Borrower shall give each Notice of Borrowing relating to Construction Loans to Agent so as to provide the Minimum Notice Period applicable to Construction Loans of the Type requested. Any Notice of Borrowing may be modified or revoked by Borrower through the Banking Day prior to the Minimum Notice Period, and shall thereafter be irrevocable. (c) Construction Loan Interest. Borrower shall pay interest on the unpaid principal amount of each Construction Loan from the date of such Construction Loan until the maturity or prepayment thereof at the following rates per annum: (i) With respect to the principal portion of such Construction Loan which is, and during such periods as such Construction Loan is, a Base Rate Construction Loan, at a rate per annum equal to the Base Rate plus 0.750%, such rate to change from time to time as the Base Rate shall change; and (ii) With respect to the principal portion of such Construction Loan which is, and during such portion of such periods as such Construction Loan is, a LIBOR Construction Loan, at a rate per annum, at all times during each Interest Period for such LIBOR Construction Loan, equal to the LIBO Rate for such Interest Period plus 1.500%. (d) Construction Loan Principal Payments. Borrower shall repay to Agent, for the account of each Bank, in full on the Construction Loan Maturity Date the unpaid principal amount of all Construction Loans made by such Bank which will not be Term-Converted to Term Loans as provided in Section 2.1.2(a). Upon payment or Term-Conversion, in full, of the aggregate principal amount of the Construction Loans and all accrued and unpaid interest thereon, the Banks shall promptly mark the Construction Notes cancelled and return such cancelled Construction Notes to Borrower. 2.1.2 Term Loan Facility. (a) Availability. Subject to the terms and conditions set forth in this Agreement, each Bank severally agrees to make to Borrower on the date of Term-Conversion specified pursuant to Section 2.1.2(b)(iii), at the request of Borrower, a term loan under this Section 2.1.2 (individually a "Term Loan" and collectively the "Term Loans") in an aggregate principal amount not to exceed such Bank's Term Loan Commitment. Each Bank shall make its Term Loan by converting the portion of its outstanding Construction Loans equal to such Bank's Term Loan Commitment to a Term Loan. (b) Notice of Term-Conversion. Upon satisfaction of the conditions set forth in Section 3.3, Borrower shall request the Term-Conversion by delivering to Agent a written notice in the form of Exhibit C-2, appropriately completed ("Notice of Term-Conversion"), which specifies: 2 15 (i) The principal portion of the Term Loans which will bear interest as provided in (1) Section 2.1.2(c)(i)(A) (individually, a "Base Rate Term Loan") and/or (2) Section 2.1.2(c)(i)(B) (individually, a "LIBOR Term Loan"); (ii) The aggregate amount of the Term Loans, which shall not exceed the lesser of the Total Term Loan Commitment and the aggregate principal amount of all Construction Loans outstanding on the date of Term-Conversion (immediately prior to Term-Conversion, after giving effect to the Final Drawing and the application of: (x) all Base Equity pursuant to Section 5.18, (y) all liquidated damages required to be applied to the prepayment of Construction Loans pursuant to Section 7.1.4 or 7.13, and (z) any Base Equity or Additional Borrower Equity required to be applied to the prepayment of Construction Loans pursuant to Section 5.18); (iii) The proposed date of the Term-Conversion, which shall be no later than the Construction Loan Maturity Date; and (iv) If the Term Loans are to consist of LIBOR Loans, the initial Interest Periods selected by Borrower for such Loans. Borrower shall so deliver the Notice of Term-Conversion to Agent so as to provide at least the Minimum Notice Period applicable to Loans of the Type requested upon Term-Conversion. The Notice of Term-Conversion may be modified or revoked by Borrower through the Banking Day prior to the Minimum Notice Period, and thereafter shall be irrevocable. (c) Term Loan Interest. (i) Borrower shall pay interest on the unpaid principal amount of each Term Loan from the date of such Term Loan until the maturity or prepayment thereof at one of the following rates per annum: (A) With respect to the principal portion of such Term Loan which is, and during such periods as such Term Loan is, a Base Rate Term Loan, at a rate per annum equal to the Base Rate plus the percentage listed below, such rate to change from time to time as the Base Rate shall change: First Term Period 0.500% Second Term Period 0.750% Third Term Period 1.125% Fourth Term Period 1.750%
(B) With respect to the principal portion of such Term Loan which is, and during such periods as such Term Loan is, a LIBOR Term Loan, at a rate per annum during each Interest Period for such LIBOR Term Loan equal to the LIBO Rate for such Interest Period plus the percentage listed below: 3 16 First Term Period 1.250% Second Term Period 1.500% Third Term Period 1.875% Fourth Term Period 2.500%
provided, however, that, in the case of clauses (A) and (B) above, (a) in the event that and for so long as, from time to time, Borrower has met the Extension Requirements on the last day of the last preceding calendar quarter, then (i) the percentages set forth above for the Third Term Period and the Fourth Term Period shall, from and after the day following the date of Term- Conversion, be reduced by 0.250% and (ii) the percentage set forth above for the Fourth Term Period shall, from and after the day following the tenth anniversary of the date of Term-Conversion, be reduced by an additional 0.375%; provided further, however, notwithstanding anything to the contrary in the foregoing proviso, in the event that from time to time, the Four-Quarter Average Debt Service Coverage Ratio calculated on the last day of the last preceding calendar quarter is less than 1.50 to 1.00, then each of the percentages set forth above shall not be decreased and instead shall be increased by .250%, until such time as the Four- Quarter Average Debt Service Coverage Ratio as of the end of any subsequent calendar quarter is equal to or greater than 1.50 to 1.00 at which time the percentages set forth above shall no longer be increased by such 0.250% and shall return to the percentages set forth above (subject to increase or decrease pursuant to this Section 2.1.2(c)). (d) Term Loan Principal Payment. Borrower shall repay to Agent, for the account of each Bank, the aggregate unpaid principal amount of the Term Loan made by such Bank in installments payable on each Repayment Date in accordance with the repayment schedule set forth on Exhibit I, with any remaining unpaid principal, interest, fees and costs due and payable on the Term Loan Maturity Date. 2.1.3 Interest Provisions Relating to All Loans. (a) Interest Payment Dates. Borrower shall pay accrued interest on the unpaid principal amount of each Loan (i) in the case of each Base Rate Loan, on the last Banking Day of each calendar quarter, (ii) in the case of each LIBOR Loan, on the last day of each Interest Period related to such LIBOR Loan and, if such Interest Period is longer than three months, every three months after the date of such LIBOR Loan and (iii) in all cases, upon prepayment (to the extent thereof and including any optional prepayments or Mandatory Prepayments), upon conversion from one Type of Loan to another Type, and at maturity (whether by acceleration or otherwise). (b) LIBOR Loan Interest Periods. (i) The initial and subsequent Interest Period for LIBOR Loans shall be a maximum of one month during the six month period immediately following the Closing Date; provided that Agent may otherwise approve, in its sole discretion, a longer Interest Period which is requested by Borrower and otherwise complies with the following provisions of 4 17 this Section 2.1.3(b)(i). Thereafter, each subsequent Interest Period (including any Interest Period referenced in the proviso of the first sentence of this Section 2.1.3(b) selected by Borrower for all LIBOR Loans shall be one, two, three or six months or such other period as close to three months as is practicable to enable Borrower to limit the number of LIBOR Loans as required by this Section 2.1.3(b) or to comply with clauses (C), (D) or (E) of the next sentence. Notwithstanding anything to the contrary in either of the two preceding sentences, (A) any Interest Period which would otherwise end on a day which is not a Banking Day shall be extended to the next succeeding Banking Day unless such next Banking Day falls in another calendar month, in which case such Interest Period shall end on the immediately preceding Banking Day; (B) any Interest Period which begins on the last Banking Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Banking Day of a calendar month; (C) Borrower may not select Interest Periods which would leave a greater principal amount of Loans subject to Interest Periods ending after a date upon which Loans are or may be required to be repaid (including the Construction Loan Maturity Date and each Repayment Date) than principal amount of Loans scheduled to be outstanding after such date; (D) unless Term-Conversion has occurred, any Interest Period for a Construction Loan which would otherwise end after the Construction Loan Maturity Date shall end on the Construction Loan Maturity Date; (E) any Interest Period for a Term Loan which would otherwise end after the Term Loan Maturity Date shall end on the Term Loan Maturity Date; (F) LIBOR Loans for each Interest Period shall be in the amount of at least $100,000; and (G) Borrower may not at any time have outstanding more than six different Interest Periods relating to LIBOR Loans. (ii) Borrower may contact Agent at any time prior to the end of an Interest Period, for a quotation of Interest Rates in effect at such time for given Interest Periods and Agent shall promptly provide such quotation. Borrower may select an Interest Period telephonically within the time periods specified in Section 2.1.6, which selection shall be irrevocable on and after the applicable Minimum Notice Period. Borrower shall confirm such telephonic notice to Agent by telecopy on the day such notice is given (in substantially the form of Exhibit C-3, a "Confirmation of Interest Period Selection"). Borrower shall promptly deliver to Agent the original of the Confirmation of Interest Period Selection initially delivered by telecopy. If Borrower fails to notify Agent of the next Interest Period for any LIBOR Loans in accordance with this Section 2.1.3(b), such Loans shall automatically convert to Base Rate Loans on the last day of the current Interest Period therefor. Agent shall as soon as practicable (and, in any case, within two Banking Days after delivery of the Confirmation of Interest Period Selection) notify Borrower of each determination of the Interest Rate applicable to each Loan. (c) Interest Account and Interest Computations. Borrower authorizes Agent to record in an account or accounts maintained by Agent on its books (i) the interest rates applicable to all Loans and the effective dates of all changes thereto, (ii) the Interest Period for each LIBOR Loan, (iii) the date and amount of each principal and interest payment on each Loan and (iv) such other information as Agent may determine is necessary for the computation of interest payable by Borrower hereunder. Borrower agrees that all computations by Agent of interest shall be conclusive in the absence of manifest error. All computations of 5 18 interest on Base Rate Loans shall be based upon a year of 365 or 366 days and the actual days elapsed, and shall be adjusted in accordance with any changes in the Base Rate to take effect on the beginning of the day of such change in the Base Rate. All computations of interest on LIBOR Loans shall be based upon a year of 360 days and the actual days elapsed. 2.1.4 Promissory Notes. The obligation of Borrower to repay the Loans made by each Bank and to pay interest thereon at the rates provided herein shall be evidenced by promissory notes in the form of Exhibit B-1 (individually, a "Construction Note") and Exhibit B-2 (individually, a "Term Note"), each payable to the order of such Bank and in the principal amount of such Bank's Construction Loan Commitment and Term Loan Commitment, respectively. Borrower authorizes each Bank to record on the schedule annexed to such Bank's Note or Notes, the date and amount of each Loan made by such Bank, and each payment or prepayment of principal thereunder and agrees that all such notations shall constitute prima facie evidence of the matters noted. Borrower further authorizes each Bank to attach to and make a part of such Bank's Note or Notes continuations of the schedule attached thereto as necessary. No failure to make any such notations, nor any errors in making any such notations, shall affect the validity of Borrower's obligations to repay the full unpaid principal amount of the Loans or the duties of Borrower hereunder or thereunder. 2.1.5 Loan Funding. (a) Notice. Each Notice of Borrowing shall be delivered to Agent in accordance with Section 12.1. Agent shall promptly notify each Bank of the contents of each Notice of Borrowing. (b) Pro Rata Loans. All Loans shall be made on a pro rata basis by the Banks in accordance with their respective Proportionate Shares of such Loans, with each Borrowing to consist of a Loan by each Bank equal to such Bank's Proportionate Share of such Borrowing. (c) Bank Funding. Each Bank shall, before 12:00 noon on the date of each Borrowing, make available to Agent at its office specified in Section 12.1, in same day funds, such Bank's Proportionate Share of such Borrowing. The failure of any Bank to make the Loan to be made by it as part of any Borrowing shall not relieve any other Bank of its obligation hereunder to make its Loan on the date of such Borrowing. No Bank shall be responsible for the failure of any other Bank to make the Loan to be made by such other Bank on the date of any Borrowing. (d) Construction Account. No later than 2:00 p.m. on the date specified in each Notice of Borrowing, if the applicable conditions precedent listed in Article 3 have been satisfied and to the extent Agent shall have received the appropriate funds from the Banks, Agent will make available the Construction Loans requested in such Notice of Borrowing (or so much thereof as the Banks shall have approved pursuant to this Agreement) in Dollars and 6 19 in immediately available funds, at Agent's New York Branch, and shall deposit such Construction Loans into the Construction Account. 2.1.6 Conversion of Loans. Borrower may convert Loans from one Type of Loans to another Type; provided, however, that (i) any conversion of LIBOR Loans into Base Rate Loans shall be made on, and only on, the first day after the last day of an Interest Period for such LIBOR Loans and (ii) Loans shall be converted only in amounts of $100,000 or more. Borrower shall request such a conversion by a written notice to Agent in the form of Exhibit C-4, appropriately completed (a "Notice of Conversion of Loan Type"), which specifies: (a) The Loans, or portion thereof, which are to be converted; (b) The Type into which such Loans, or portion thereof, are to be converted; (c) If such Loans are to be converted into LIBOR Loans, the initial Interest Period selected by Borrower for such Loans in accordance with Section 2.1.3(b); and (d) The date of the requested conversion, which shall be a Banking Day. Borrower shall so deliver each Notice of Conversion of Loan Type so as to provide at least the applicable Minimum Notice Period. Any Notice of Conversion of Loan Type may be modified or revoked by Borrower through the Banking Day prior to the Minimum Notice Period, and shall thereafter be irrevocable. Each Notice of Conversion of Loan Type shall be delivered by first-class mail or telecopy to Agent at the office or to the telecopy number and during the hours specified in Section 12.1; provided, however, that Borrower shall promptly deliver to Agent the original of any Notice of Conversion of Loan Type initially delivered by telecopy. Agent shall promptly notify each Bank of the contents of each Notice of Conversion of Loan Type. 2.1.7 Prepayments. (a) Terms of All Prepayments. Upon the prepayment of any Loan (whether such prepayment is an optional prepayment under Section 2.1.7(b) or a Mandatory Prepayment), Borrower shall pay to Agent for the account of the Bank which made such Loan and/or Hedge Bank, as applicable, (i) all accrued interest to the date of such prepayment on the amount prepaid, (ii) all accrued fees to the date of such prepayment of the amount being prepaid, (iii) to the extent required by the terms of the applicable Interest Rate Agreement, all Hedge Breaking Fees owed by Borrower to such Bank or Hedge Bank as a result of such prepayment, and (iv) if such prepayment is the prepayment of a LIBOR Loan on a day other than the last day of an Interest Period for such LIBOR Loan, all Liquidation Costs incurred by such Bank as a result of such prepayment. All Mandatory Prepayments of Term Loans shall be applied to reduce the remaining payments required under Section 2.1.2(d) in inverse order of maturity. All optional 7 20 prepayments of the Term Loans shall be applied ratably to the Amortization Schedule for the Term Loans to reduce the remaining payments required under Section 2.1.2(d). Borrower may not reborrow the principal amount of any Construction Loan or Term Loan which is prepaid. Borrower shall terminate or partially terminate Hedge Transactions such that at no time shall the notional amount under all of the Hedge Transactions combined exceed the principal amount of Loans outstanding at such time. (b) Optional Prepayments. Subject to Section 2.1.7(a), Borrower may, at its option and without penalty, upon five Banking Days' notice to Agent, prepay (i) the entire outstanding amount of all Construction Loans in whole or (ii) any Term Loans in whole or in part in minimum incremental amounts of $100,000; provided, however, that as a condition to Borrower's right to make any prepayment of the Construction Loans, Borrower shall have terminated and repaid all other Commitments hereunder. (c) Mandatory Prepayments. Borrower shall prepay (or cause to be prepaid) Loans to the extent required by Section 5.18, 7.1.4, 7.2.5, 7.11, 7.12, or 7.13 of this Agreement, or any other provision of this Agreement which requires prepayment of Loans (such prepayment, "Mandatory Prepayment"). 2.2 Total Commitments. 2.2.1 Loan Commitment Amounts. (a) The aggregate principal amount of all Construction Loans made by the Banks shall not exceed $151,750,000. Notwithstanding the foregoing, such amount shall be reduced by the amount of Base Equity and the amount of Subordinated Debt applied to pay Project Costs; provided, however, such amount shall be reinstated by an amount equal to the stated amount of any Equity Support Letter of Credit. Such amount shall be further reduced by the amount elected by Borrower pursuant to Section 2.2.2. The amount of Construction Loans as determined pursuant to Section 2.2.1(a) shall be referred to herein as the "Total Construction Loan Commitment"). (b) Notwithstanding anything that may be construed to the contrary in this Agreement, the aggregate principal amount of all Term Loans outstanding at any time shall in no event exceed the lesser of (i) $98,637,500 and (ii) sixty-five percent (65%) of the Final Project Cost, or, in either case, if such amount is reduced by Borrower to a lower amount pursuant to Section 2.2.2 (by virtue of a reduction of the Total Construction Loan Commitment) or by virtue of any optional prepayment or Mandatory Prepayment, such lower amount (such amount, so reduced from time to time, the "Total Term Loan Commitment"). 2.2.2 Reductions and Cancellations. Borrower may, from time to time upon five Banking Days written notice to Agent, permanently reduce, by an amount of $1,000,000 or an integral multiple of $100,000 in excess thereof or cancel in its entirety the Total Construction Loan Commitment. Notwithstanding the foregoing, Borrower may not reduce or 8 21 cancel the Total Construction Loan Commitment if, after giving effect to such reduction or cancellation, (a) the aggregate principal amount of all Construction Loans then outstanding would exceed the Total Construction Loan Commitment, (b) the Available Construction Funds would not, in the reasonable judgment of Agent and the Independent Engineer, be equal to or exceed remaining Project Costs, or (c) such reduction or cancellation would cause a violation of any other provision of this Agreement or the other Credit Documents. Borrower shall pay to Agent any Commitment Fees then due upon any cancellation and, from the effective date of any reduction, the Commitment Fees shall be computed on the basis of the Available Construction Loan Commitment as reduced as a result of such reduction of the Total Construction Loan Commitment. Once reduced or cancelled, the Total Construction Loan Commitment may not be increased or reinstated. Any reductions of the Total Construction Loan Commitment shall cause a corresponding pro rata reduction in the Total Term Loan Commitment. Any reductions pursuant to this Section 2.2.2 shall be applied ratably to each Bank's respective Commitments in accordance with Section 2.5.1. 2.3 Fees. 2.3.1 Advisory Fee; Syndication Fee. Borrower shall pay to Agent solely for Agent's account the advisory fee and the syndication fee described in that certain letter from Borrower to Agent dated the Closing Date. 2.3.2 Annual Agency Fee. Borrower shall pay to Agent solely for Agent's account an annual agency fee (the "Agency Fee") payable in advance on the Closing Date and on each anniversary thereof on which any Loans are outstanding, in an amount equal to the product of (a)(i) for years beginning prior to Term-Conversion, $175,000 per year, and (ii) for years beginning after Term-Conversion, $100,000 per year, times (b) the Inflation Factor. 2.3.3 Loan Commitment Fees. On the last Banking Day in each calendar quarter (where all or any portion of such calendar quarter occurs on or after the Closing Date and prior to the Construction Loan Maturity Date) and on the Construction Loan Maturity Date (or, if the Total Construction Loan Commitment is cancelled prior to such date, on the date of such cancellation), Borrower shall pay to Agent, for the benefit of the Banks, accruing from the Closing Date or the first day of such quarter, as the case may be, a commitment fee (the "Commitment Fee") for such quarter (or portion thereof) then ending equal to the product of (a) 0.375% times (b) the daily average Available Construction Loan Commitment for such quarter (or portion thereof) times (c) a fraction, the numerator of which is the number of days in such quarter (or portion thereof) and the denominator of which is the number of days in that calendar year (365 or 366, as the case may be). 2.4 Other Payment Terms. 2.4.1 Place and Manner. Borrower shall make all payments due to each Bank or Agent hereunder to Agent, for the account of such Bank, to Chase Manhattan Bank; Swift: CHASUS33; Fed. Ref.: 021000021; Account Name: ING (U.S.) Capital Corporation; 9 22 Account Number: 9301035763, in lawful money of the United States and in immediately available funds not later than 12:00 noon on the date on which such payment is due. Any payment made after such time on any day shall be deemed received on the Banking Day after such payment is received. Agent shall disburse to each Bank each such payment received by Agent for such Bank, such disbursement to occur on the day such payment is received if received by 12:00 noon or if otherwise reasonably possible, otherwise on the next Banking Day. 2.4.2 Date. Whenever any payment due hereunder shall fall due on a day other than a Banking Day, such payment shall be made on the next succeeding Banking Day, and such extension of time shall be included in the computation of interest or fees, as the case may be. 2.4.3 Late Payments. If any amounts required to be paid by Borrower under this Agreement or the other Credit Documents (including principal or interest payable on any Loan, and any fees or other amounts otherwise payable to Agent or any Bank) remain unpaid after such amounts are due, Borrower shall pay interest on the aggregate, unpaid balance of such amounts from the date due until those amounts are paid in full at a per annum rate equal to the Default Rate. 2.4.4 Net of Taxes, Etc. (a) Taxes. Subject to each Bank's compliance with Section 2.4.7, any and all payments to or for the benefit of Agent or any Bank by Borrower hereunder or under any other Credit Document shall be made free and clear of and without deduction, setoff or counterclaim of any kind whatsoever and in such amounts as may be necessary in order that all such payments, after deduction for or on account of any present or future taxes, levies, imposts, deductions, charges or withholdings, and all liabilities with respect thereto (excluding income and franchise taxes, which include taxes imposed on or measured by the net income or capital of Agent or such Bank by any jurisdiction or any political subdivision or taxing authority thereof or therein solely as a result of a connection between such Bank and such jurisdiction or political subdivision, other than a connection resulting solely from executing, delivering or performing its obligations or receiving a payment under, or enforcing, this Agreement or any Note) (all such non-excluded taxes, levies, imposts, deductions, charges, withholdings and liabilities being hereinafter referred to as "Taxes"), shall be equal to the amounts otherwise specified to be paid under this Agreement and the other Credit Documents. If Borrower shall be required by law to withhold or deduct any Taxes from or in respect of any sum payable hereunder or under any other Credit Document to Agent or any Bank, (i) the sum payable shall be increased as may be necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 2.4.4, Agent or such Bank receives an amount equal to the sum it would have received had no such deductions been made, (ii) Borrower shall make such deductions and (iii) Borrower shall pay the full amount deducted to the relevant taxation authority or other authority in accordance with applicable law. If Borrower shall make any payment under this Section 2.4.4 to or for the benefit of Agent or any Bank with respect to Taxes and if Agent or such Bank shall claim any credit or deduction for such Taxes against any other taxes payable by Agent or such Bank to any taxing jurisdiction then Agent 10 23 or such Bank shall pay to Borrower an amount equal to the amount by which such other taxes are actually reduced; provided that the aggregate amount payable by Agent or such Bank pursuant to this sentence shall not exceed the aggregate amount previously paid by Borrower with respect to such Taxes. In addition, Borrower agrees to pay any present or future stamp, recording or documentary taxes and any other excise or property taxes, charges or similar levies (not including income or franchise taxes) that arise under the laws of the United States of America, the State of New York or the State of Texas from any payment made hereunder or under any other Credit Document or from the execution or delivery or otherwise with respect to this Agreement or any other Credit Document (hereinafter referred to as "Other Taxes"). (b) Indemnity. Borrower shall indemnify each Bank for the full amount of Taxes and Other Taxes (including any Taxes or Other Taxes imposed by any jurisdiction on amounts payable under this Section 2.4.4 paid by any Bank, or any liability (including penalties, interest and expenses) arising therefrom or with respect thereto, whether or not such Taxes or Other Taxes were correctly or legally asserted; provided that Borrower shall not be obligated to indemnify any Bank for any penalties, interest or expenses relating to Taxes or Other Taxes arising from the indemnitee's gross negligence or willful misconduct. Each Bank agrees to give written notice to Borrower of the assertion of any claim against such Bank relating to such Taxes or Other Taxes as promptly as is practicable after being notified of such assertion, and in no event later than one hundred eighty (180) days after the principal officer of such Bank responsible for administering this Agreement obtains knowledge thereof; provided that any Bank's failure to notify Borrower of such assertion within such one hundred eighty (180) days period shall not relieve Borrower of its obligation under this Section 2.4.4 with respect to Taxes or Other Taxes arising prior to the end of such period, but shall relieve Borrower of its obligations under this Section 2.4.4 with respect to Taxes or Other Taxes between the end of such period and such time as Borrower receives notice from such Bank as provided herein. Payments by Borrower pursuant to this indemnification shall be made within 30 days from the date such Bank makes written demand therefor (submitted through Agent), which demand shall be accompanied by a certificate describing in reasonable detail the basis thereof. Each Bank agrees to repay to Borrower any refund (including that portion of any interest that was included as part of such refund with respect to Taxes or Other Taxes paid by Borrower pursuant to this Section 2.4.4) received by such Bank for Taxes or Other Taxes that were paid by Borrower pursuant to this Section 2.4.4 and to contest, with the approval and participation of and at the expense of Borrower, any such Taxes or Other Taxes which such Bank or Borrower reasonably believes not to have been properly assessed. (c) Notice. Within 30 days after the date of any payment of Taxes by Borrower, Borrower shall furnish to Agent, at its address referred to in Section 12.1, the original or a certified copy of a receipt evidencing payment thereof. Borrower shall compensate each Bank for all reasonable losses and expenses sustained by such Bank as a result of any failure by Borrower to so furnish such copy of such receipt. 11 24 (d) Survival of Obligations. The obligations of Borrower under this Section 2.4.4 shall survive the termination of this Agreement and the repayment of the Obligations. 2.4.5 Application of Payments. Payments made under this Agreement or the other Credit Documents and other amounts received by Agent and the Banks under this Agreement or the other Credit Documents shall first be applied to any fees, costs, charges or expenses payable to Agent or the other Banks hereunder or under the other Credit Documents, next to any accrued but unpaid interest then due and owing, and then to outstanding principal then due and owing or otherwise to be prepaid. 2.4.6 Failure to Pay Agent. Unless Agent shall have received notice from Borrower at least two Banking Days prior to the date on which any payment is due to the Banks hereunder that Borrower will not make such payment in full, Agent may assume that Borrower has made such payment in full to Agent on such date and Agent may, in reliance upon such assumption, cause to be distributed to each Bank on such due date an amount equal to the amount then due such Bank. If and to the extent Borrower shall not have so made such payment in full to Agent, such Bank shall repay to Agent forthwith upon demand such amount distributed to such Bank, together with interest thereon, for each day from the date such amount is distributed to such Bank until the date such Bank repays such amount to Agent, at the Federal Funds Rate for the first five days after such date, and subsequent thereto at the Base Rate. A certificate of Agent submitted to any Bank with respect to any amounts owing by such Bank under this Section 2.4.6 shall be conclusive in the absence of manifest error. 2.4.7 Withholding Exemption Certificates. Agent on the Closing Date and each Bank upon becoming a Bank hereunder including any entity to which any Bank grants a participation, or otherwise transfers its interest in this Agreement, agree that they will deliver to Borrower and Agent (and Agent agrees that it will deliver to Borrower) either (a) a statement that it is incorporated under the laws of the United States of America or a state thereof or (b) if it is not so incorporated, a letter in the form of Exhibit J-1 or Exhibit J-2, as appropriate, and two duly completed copies of United States Internal Revenue Service Form 1001 or 4224 or successor applicable form, as the case may be, certifying in each case that such Bank is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes. Each Bank which delivers to Borrower and Agent a Form 1001 or 4224 pursuant to the preceding sentence further undertakes to deliver to Borrower and Agent further copies of the said letter and Form 1001 or 4224, or successor applicable forms, or other manner of certification or procedure, as the case may be, on or before the date that any such letter or form expires or becomes obsolete or within a reasonable time after gaining knowledge of the occurrence of any event requiring a change in the most recent letter and forms previously delivered by it to Borrower, and such extensions or renewals thereof as may reasonably be requested by Borrower, certifying in the case of a Form 1001 or 4224 that such Bank is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, unless in any such cases an event (including any change in treaty, law or regulation) has occurred prior to the date on which any such delivery would otherwise be required which renders all such forms 12 25 inapplicable or which would prevent a Bank from duly completing and delivering any such letter or form with respect to it and such Bank advises Borrower that it is not capable of receiving payments without any deduction or withholding of United States federal income tax, and in the case of Form W-8 or W-9, establishing an exemption from United States backup withholding tax. The Borrower shall not be obligated, however, to pay any additional amounts in respect of United States Federal income tax pursuant to Section 2.4.4 (or make an indemnification payment pursuant to Section 2.4.4) to any Bank (including any entity to which any Bank sells, assigns, grants a participation in, or otherwise transfers its rights under this Agreement) if the obligation to pay such additional amounts (or such indemnification) would not have arisen but for a failure of such Bank to comply with its obligations under this Section 2.4.7. 2.5 Pro Rata Treatment. 2.5.1 Borrowings, Commitment Reductions, Etc. Except as otherwise provided herein, (a) each Borrowing consisting of Construction Loans and Term Loans and each reduction of the Total Construction Loan Commitment shall be made or allocated among the Banks pro rata according to their respective Proportionate Shares of such Loans, (b) each payment of principal of and interest on Construction Loans and Term Loans shall be made or shared among the Banks holding such Loans pro rata according to the respective unpaid principal amounts of such Loans held by such Banks and (c) each payment of Commitment Fees shall be shared among the Banks pro rata according to (i) their respective Proportionate Shares of the Loans to which such fees apply and (ii) in the case of each Bank which becomes a Bank hereunder after the date hereof, the date upon which such Bank so became a Bank. 2.5.2 Sharing of Payments, Etc. If any Bank shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of setoff, or otherwise) on account of Loans owed to it, in excess of its ratable share of payments on account of such Loans obtained by all Banks entitled to such payments, such Bank shall forthwith purchase from the other Banks such participation in the Loans, as the case may be, as shall be necessary to cause such purchasing Bank to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Bank, such purchase from such Bank shall be rescinded and each other Bank shall repay to the purchasing Bank the purchase price to the extent of such recovery together with an amount equal to such other Bank's ratable share (according to the proportion of (a) the amount of such other Bank's required repayment to (b) the total amount so recovered from the purchasing Bank) of any interest or other amount paid or payable by the purchasing Bank in respect of the total amount so recovered. Borrower agrees that any Bank so purchasing a participation from another Bank pursuant to this Section 2.5.2 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of setoff) with respect to such participation as fully as if such Bank were the direct creditor of Borrower in the amount of such participation. 2.6 Change of Circumstances. 13 26 2.6.1 Inability to Determine Rates. If, on or before the first day of any Interest Period for any LIBOR Loans, (a) Agent determines that the LIBO Rate for such Interest Period cannot be adequately and reasonably determined due to the unavailability of funds in or other circumstances affecting the London interbank market, or (b) Banks holding aggregate Proportionate Shares of 33-1/3% or more shall advise Agent that (i) the rates of interest for such LIBOR Loans do not adequately and fairly reflect the cost to such Banks of making or maintaining such Loans or (ii) deposits in Dollars in the London interbank market are not available to such Banks (as conclusively certified by each such Bank in good faith in writing to Agent and to Borrower) in the ordinary course of business in sufficient amounts to make and/or maintain their LIBOR Loans, Agent shall immediately give notice of such condition to Borrower. After the giving of any such notice and until Agent shall otherwise notify Borrower that the circumstances giving rise to such condition no longer exist, Borrower's right to request the making of or conversion to, and the Banks' obligations to make or convert to LIBOR Loans shall be suspended. Any LIBOR Loans outstanding at the commencement of any such suspension shall be converted at the end of the then current Interest Period for such Loans into Base Rate Loans unless such suspension has then ended. 2.6.2 Illegality. If, after the date of this Agreement, the adoption of any Governmental Rule, any change in any Governmental Rule or the application or requirements thereof (whether such change occurs in accordance with the terms of such Governmental Rule as enacted, as a result of amendment, or otherwise), any change in the interpretation or administration of any Governmental Rule by any Governmental Authority, or compliance by any Bank or Borrower with any request or directive (whether or not having the force of law) of any Governmental Authority (a "Change of Law") shall make it unlawful or impossible for any Bank to make or maintain any LIBOR Loan, such Bank shall immediately notify Agent and Borrower of such Change of Law. Upon receipt of such notice, (a) Borrower's right to request the making of or conversion to, and the Bank's obligations to make or convert to, LIBOR Loans shall be suspended for so long as such condition shall exist, and (b) Borrower shall, at the request of such Bank, either (i) pursuant to Section 2.1.6, convert any then outstanding LIBOR Loans into Base Rate Loans at the end of the current Interest Periods for such Loans, or (ii) immediately repay pursuant to Section 2.1.7 or convert LIBOR Loans of the affected Type into Base Rate Loans if such Bank shall notify Borrower that such Bank may not lawfully continue to fund and maintain such Loans. Any conversion or prepayment of LIBOR Loans made pursuant to the preceding sentence prior to the last day of an Interest Period for such Loans shall be deemed a prepayment thereof for purposes of Section 2.7. 2.6.3 Increased Costs. If, after the date of this Agreement, any Change of Law: (a) Shall subject any Bank to any tax, duty or other charge with respect to any LIBOR Loan or Commitment, or shall change the basis of taxation of payments by Borrower to any Bank on such a Loan or with respect to any Commitment (except for Taxes, Other Taxes or changes in the rate of taxation on the overall net income of any Bank); or 14 27 (b) Shall impose, modify or hold applicable any reserve, special deposit or similar requirement (without duplication of any reserve requirement included within the applicable Interest Rate through the definition of "Reserve Requirement") against assets held by, deposits or other liabilities in or for the account of, advances or loans by, or any other acquisition of funds by any Bank for any LIBOR Loan; or (c) Shall impose on any Bank any other condition directly related to any LIBOR Loan or Commitment; and the effect of any of the foregoing is to increase the cost to such Bank of making, issuing, creating, renewing, participating in (subject to the limitations in Section 10.13) or maintaining any such LIBOR Loan or Commitment or to reduce any amount receivable by such Bank hereunder; then Borrower shall from time to time, upon demand by such Bank, pay to such Bank additional amounts sufficient to reimburse such Bank for such increased costs or to compensate such Bank for such reduced amounts. A certificate setting forth in reasonable detail the amount of such increased costs or reduced amounts and the basis for determination of such amount, submitted by such Bank to Borrower, shall, in the absence of manifest error, be conclusive and binding on Borrower for purposes of this Agreement. 2.6.4 Capital Requirements. If any Bank determines that (a) any Change of Law after the date of this Agreement increases the amount of capital required or expected to be maintained by such Bank (or the Lending Office of such Bank) or any Person controlling such Bank (a "Capital Adequacy Requirement") and (b) the amount of capital maintained by such Bank or such Person which is attributable to or based upon the Loans, the Commitments or this Agreement must be increased as a result of such Capital Adequacy Requirement (taking into account such Bank's or such Person's policies with respect to capital adequacy), Borrower shall pay to Agent on behalf of such Bank or such Person, upon demand of Agent on behalf of such Bank or such Person, such amounts as such Bank or such Person shall reasonably determine are necessary to compensate such Bank or such Person for the increased costs to such Bank or such Person of such increased capital. A certificate of such Bank or such Person, setting forth in reasonable detail the computation of any such increased costs, delivered to Borrower by Agent on behalf of such Bank or such Person shall, in the absence of manifest error, be conclusive and binding on Borrower for purposes of this Agreement. 2.6.5 Notice; Participating Banks' Rights. Each Bank will notify Borrower of any event occurring after the date of this Agreement that will entitle such Bank to compensation pursuant to this Section 2.6, as promptly as practicable, and in no event later than 90 days after the principal officer of such Bank responsible for administering this Agreement obtains knowledge thereof; provided that any Bank's failure to notify Borrower within such 90 day period shall not relieve Borrower of its obligation under this Section 2.6.5 with respect to claims arising prior to the end of such period, but shall relieve Borrower of its obligations under this Section 2.6.5 with respect to the time between the end of such period and such time as Borrower receives notice from the indemnitee as provided herein. No Person purchasing from a Bank a participation in any Commitment (as opposed to an assignment) shall be entitled to any payment from or on behalf of 15 28 Borrower pursuant to Section 2.6.3 or Section 2.6.4 which would be in excess of the applicable proportionate amount (based on the portion of the Commitment in which such Person is participating) which would then be payable to such Bank if such Bank had not sold a participation in that portion of the Commitment. 2.7 Funding Losses. If Borrower shall (a) repay or prepay any LIBOR Loans on any day other than the last day of an Interest Period for such Loans (whether an optional prepayment or a Mandatory Prepayment), (b) fail to borrow any LIBOR Loans in accordance with a Notice of Borrowing delivered to Agent (whether as a result of the failure to satisfy any applicable conditions or otherwise), (c) fail to convert any Loans into LIBOR Loans in accordance with a Notice of Conversion of Loan Type delivered to Agent (whether as a result of the failure to satisfy any applicable conditions or otherwise), or (d) fail to make any prepayment in accordance with any notice of prepayment delivered to Agent; Borrower shall, upon demand by any Bank, reimburse such Bank for all costs and losses incurred by such Bank as a result of such repayment, prepayment or failure ("Liquidation Costs"). Borrower understands that such costs and losses may include losses incurred by a Bank as a result of funding and other contracts entered into by such Bank to fund LIBOR Loans. Each Bank demanding payment under this Section 2.7 shall deliver to Borrower a certificate setting forth in reasonable detail the basis for and the amount of costs and losses for which demand is made. Such a certificate so delivered to Borrower shall, in the absence of manifest error, be conclusive and binding as to the amount of such loss for purposes of this Agreement. 2.8 Alternate Office; Minimization of Costs. 2.8.1 To the extent reasonably possible, each Bank shall designate an alternative Lending Office with respect to its LIBOR Loans and otherwise take any reasonable actions to reduce any liability of Borrower to any Bank under Section 2.4.4, 2.6.3 or 2.6.4, or to avoid the unavailability of any Type of Loans under Section 2.6.2 so long as such Bank, in its sole discretion, does not determine that such designation is disadvantageous to such Bank. 2.8.2 If and with respect to each occasion that a Bank either makes a demand for compensation pursuant to Section 2.4.4, 2.4.7, 2.6.3 or 2.6.4 or is unable for a period of three consecutive months to fund LIBOR Loans pursuant to Section 2.6.2 or such Bank wrongfully fails to fund a Loan, Borrower may, upon at least five Banking Days' prior irrevocable written notice to each of such Bank and Agent, in whole permanently replace the Commitment of such Bank; provided that Borrower shall replace such Commitment with the Commitment of a commercial bank reasonably satisfactory to the Agent. Such replacement Bank shall upon the effective date of replacement purchase the Obligations owed to such replaced Bank for the aggregate amount thereof and shall thereupon for all purposes become a "Bank" hereunder. Such notice from Borrower shall specify an effective date for the replacement of such Bank's Commitment, which date shall not be later than the tenth day after the day such notice is given. On the effective date of any replacement of such Bank's Commitment pursuant to this Section 2.8.2, Borrower shall pay to Agent for the account of such Bank (a) any fees due to such Bank to the date of such replacement; (b) accrued interest on the principal amount of outstanding Loans 16 29 held by such Bank to the date of such replacement, and (c) the amount or amounts requested by such Bank pursuant to each of Sections 2.4.4, 2.4.7, 2.6.3 and 2.6.4, as applicable. Borrower will remain liable to such replaced Bank for any Liquidation Costs that such Bank may sustain or incur as a consequence of repayment of such Bank's Loans (unless such Bank has defaulted on its obligation to fund a Loan hereunder). Upon the effective date of repayment of any Bank's Loans and termination of such Bank's Commitment pursuant to this Section 2.8.2, such Bank shall cease to be a Bank hereunder. No such termination of any such Bank's Commitment and the purchase of such Bank's Loans pursuant to this Section 2.8.2 shall affect (i) any liability or obligation of Borrower or any other Bank to such terminated Bank which accrued on or prior to the date of such termination or (ii) such terminated Bank's rights hereunder in respect of any such liability or obligation. 2.8.3 Any Bank may designate a Lending Office other than that set forth on Exhibit H and may assign all of its interests under the Credit Documents, and its Notes, to such Lending Office; provided that such designation and assignment do not at the time of such designation and assignment increase the reasonably foreseeable liability of Borrower under Sections 2.4.4, 2.6.3, or 2.6.4 or make an Interest Rate option unavailable pursuant to Section 2.6.2. ARTICLE 3 - CONDITIONS PRECEDENT 3.1 Conditions Precedent to the Closing Date. The obligation of the Banks to make the initial Construction Loans is subject to the prior satisfaction of each of the following conditions (unless waived in writing by Agent with the consent of the Banks): 3.1.1 Resolutions. Delivery to Agent of a copy of one or more resolutions or other authorizations of Borrower and each of the Partners, Shareholders, Construction Manager, Project Manager, Operator and each Equity Party, certified by the appropriate officers of each such entity as being in full force and effect on the Closing Date, authorizing, as applicable, the Borrowings herein provided for and the execution, delivery and performance of this Agreement and the other Operative Documents and any instruments or agreements required hereunder or thereunder to which such entity is a party. 3.1.2 Incumbency. Delivery to Agent of a certificate satisfactory in form and substance to Agent, from the Managing Partner of Borrower and from each of the Partners, Shareholders, Construction Manager, Project Manager, Operator and each Equity Party, signed by the appropriate authorized officer of each such entity and dated the Closing Date, as to the incumbency of the natural persons authorized to execute and deliver this Agreement and the other Operative Documents and any instruments or agreements required hereunder or thereunder to which such entity is a party. 3.1.3 Formation Documents. Delivery to Agent of (a) a copy of the Partnership Agreement, certified by the secretary or an assistant secretary of the Managing Partner as being true, current and complete on the Closing Date, and any related agreements or certificates 17 30 filed in accordance with applicable state law, and (b) copies of the articles of incorporation or certificate of incorporation or charter of each Major Project Participant other than Borrower (or any Equity LC Issuer), certified, if requested by the Agent, by the secretary of state of the state of incorporation, and (c) copies of the Bylaws of each of the Partners and Shareholders, Construction Manager, Project Manager, Operator and each Equity Party, certified by its secretary or an assistant secretary. 3.1.4 Good Standing Certificates. Delivery to Agent of certificates issued by the Secretary of State of Texas and, if other than such state, the state of formation of each Major Project Participant other than any Equity LC Issuer certifying that such Major Project Participant is in good standing and is qualified to do business in, and has paid all franchise taxes or similar taxes due to, Texas (if applicable) and its state of formation. 3.1.5 Satisfactory Proceedings. All corporate, partnership and legal proceedings and all instruments in connection with the transactions contemplated by this Agreement shall be satisfactory in form and substance to Agent, and Agent shall have received all information and copies of all documents, including records of corporate or partnership proceedings and copies of any approval by any Governmental Authority required in connection with any transaction herein contemplated, which Agent may reasonably have requested in connection herewith, such documents where appropriate to be certified by proper corporate or partnership officers or Governmental Authorities. 3.1.6 Operative Documents. Delivery to Agent of executed originals of each Credit Document (other than any Equity Support Letter of Credit, Debt Service Reserve Letter of Credit, Fuel Supply Reserve Letter of Credit or Emissions Offsets Reserve Letter of Credit) and a certified list of and true and correct copies of, each Project Document then in effect, any supplements or amendments thereto, all of which shall be in form and substance satisfactory to Agent, shall have been duly authorized, executed and delivered by the parties thereto, and all of which Project Documents shall be certified by a Responsible Officer of Borrower as being true, complete and correct and in full force and effect on the Closing Date pursuant to the certificate delivered as provided in the following paragraph, which certificate shall state that neither Borrower nor, to Borrower's knowledge, any other party to any Project Document is or, but for the passage of time or giving of notice or both will be, in breach of any material obligation thereunder, and that all conditions precedent to the performance of the parties under the Project Documents then required to have been performed have been satisfied. 3.1.7 Certificate of Borrower. Agent shall have received a certificate, dated as of the Closing Date, signed by a Responsible Officer of Borrower, in substantially the form of Exhibit F-1. 3.1.8 Legal Opinions. Delivery to Agent of legal opinions of counsel to each Major Project Participant (other than any Equity LC Issuer), in form and substance satisfactory to the Agent. 18 31 3.1.9 Certificate of Insurance Consultant. Delivery to Agent of the Insurance Consultant's certificate, in substantially the form of Exhibit F-2, with the Insurance Consultant's report, in form and substance satisfactory to Agent, attached thereto. 3.1.10 Insurance. Insurance complying with Exhibit K shall be in full force and effect and Agent shall have received (a) a certificate from Borrower's insurance broker(s), dated as of the Closing Date and identifying underwriters, type of insurance, insurance limits and policy terms, listing the special provisions required as set forth in Exhibit K, describing the insurance obtained and stating that such insurance is in full force and effect and that all premiums due thereon through the Construction Loan Maturity Date have been paid and that, in the opinion of such broker(s), such insurance complies with Exhibit K, and (b) certified copies of all policies evidencing such insurance (or a binder, commitment or certificates signed by the insurer or a broker authorized to bind the insurer), in form and substance satisfactory to Agent. 3.1.11 Certificate of the Independent Engineer. Delivery to Agent of the Independent Engineer's certificate, in substantially the form of Exhibit F-3, with the Independent Engineer's report, in form and substance satisfactory to Agent, attached thereto. 3.1.12 Reports of the Borrower's Environmental Consultant. Delivery to Agent of the Borrower's Environmental Consultant's reports along with the corresponding reliance letters, each in form and substance satisfactory to Agent. 3.1.13 Certificate of the Fuel Consultant. Delivery to Agent of the Fuel Consultant's certificate, in substantially the form of Exhibit F-4, with the Fuel Consultant's report, in form and substance satisfactory to Agent, attached thereto. 3.1.14 Certificate of Power Marketing Consultant. Delivery to Agent of the Power Marketing Consultant's certificate, in substantially the form of Exhibit F-5, with the Power Marketing Consultant's report, in form and substance satisfactory to Agent, attached thereto. 3.1.15 Power Marketing Plan. Delivery to Agent of a plan with respect to power marketing setting forth Borrower's good faith assessment of Borrower's projected sales of power within ERCOT, which plan shall not in any way be construed to modify or limit Borrower's rights and obligations set forth herein, substantially in the form of Exhibit G-2 (the "Power Marketing Plan"). 3.1.16 Schedule of Applicable Permits and Applicable Third Party Permits. Delivery to Agent of Exhibit G-3, the schedule of Permits required to construct and operate the Project or required to be obtained by any Person (other than Borrower) that is party to any Project Document in order to perform its obligations thereunder, satisfactory in form and substance to Agent, together with copies of each Applicable Permit and Applicable Third Party Permit listed on Parts I(A) and I(B) of Exhibit G-3, each satisfactory in form and substance to Agent. Except as disclosed in Exhibit G-3, Borrower shall have duly obtained or been assigned and there shall 19 32 be in full force and effect in Borrower's name, and not subject to any current legal proceeding or to any unsatisfied condition that could reasonably be expected to allow material modification or revocation of, and all applicable appeal periods shall have expired with respect to, the Applicable Permits for the Project set forth on Parts I(A) and I(B) of Exhibit G-3, constituting in Agent's reasonable opinion all of the Applicable Permits as of the Closing Date. Except as disclosed on Exhibit G-3, each Major Project Participant with respect to which responsibility for an Applicable Third Party Permit is indicated in Part I(B) of Exhibit G-3 shall have duly obtained or been assigned such Applicable Third Party Permit and there shall be in full force and effect in such Person's name, and not subject to any current legal proceeding or to any unsatisfied condition that could reasonably be expected to allow material modification or revocation of, and all applicable appeal periods shall have expired with respect to, each Applicable Third Party Permit set forth on Part I(B) of Exhibit G-3, constituting in Agent's reasonable opinion all of the Applicable Third Party Permits as of the Closing Date. Part II(A) of Exhibit G-3 shall list all other Permits required by Borrower to construct and operate the Project as contemplated by the Operative Documents. Part II(B) of Exhibit G-3 shall list all other material Permits required by any other Major Project Participant to perform its obligations under the Operative Documents to which it is a party. The Permits listed in Parts II(A) and II(B) of Exhibit G-3 shall, in Agent's reasonable opinion, be timely obtainable without material difficulty, expense or delay by Borrower or the applicable other Major Project Participant, respectively. Except as disclosed in Exhibit G-3 the Permits listed in Part I(A) and I(B) of Exhibit G-3 shall not be subject to any restriction, condition, limitation or other provision that could reasonably be expected to have a Material Adverse Effect. 3.1.17 No Change in Tax Laws. No change shall have occurred, since the date upon which this Agreement was executed and delivered, in any law or regulation or interpretation thereof that would subject any Bank to any material unreimbursed Tax or Other Tax. 3.1.18 Absence of Litigation. (a) No action, suit, proceeding or investigation shall have been instituted or threatened against Borrower and (b) no order, judgment or decree shall have been issued or proposed to be issued by any Governmental Authority that, as a result of the construction, ownership, leasing or operation of the Project, the sale of electricity or steam therefrom or the entering into of any Operative Document or any transaction contemplated hereby or thereby, would cause or deem the Banks, Borrower or any Affiliate of any of them to be subject to, or not exempted from, regulation under the FPA or PUHCA or under state laws and regulations respecting the rates or the financial or organizational regulation of electric utilities. 3.1.19 Payment of Filing Fees. All amounts required to be paid to or deposited with Agent, and all taxes, fees and other costs payable in connection with the execution, delivery, recordation and filing of the documents and instruments referred to in this Section 3.1, shall have been paid in full or, as approved by Agent, provided for. 3.1.20 Financial Statements. Agent shall have received the most recent annual financial statements (audited if available) or Form 10-K and most recent quarterly financial 20 33 statements or Form 10-Q from Borrower and each other Major Project Participant (other than the Partners) (or, in the case of the Fuel Supplier and HL&P, their respective parent corporations) other than any Equity LC Issuer, together (in the case of Borrower and its Affiliates who are Major Project Participants) with certificates from the appropriate Responsible Officer thereof, stating that no material adverse change in the consolidated assets, liabilities, operations or financial condition of such Person has occurred from those set forth in the most recent financial statements or the balance sheet, as the case may be, provided to Agent. 3.1.21 UCC Reports. Agent shall have received a UCC report of a date reasonably close to the Closing Date for each of the jurisdictions in which the UCC-1 financing statements, are intended to be filed in respect of the Collateral, showing that upon due filing (assuming such filing or recordation occurred on the date of such respective reports), the security interests created under such Collateral Documents will be prior to all other financing statements, or other security documents wherein the security interest is perfected by filing in respect of the Collateral. 3.1.22 Project Budget. Borrower shall have furnished Agent a budget in substantially the form of Exhibit G-4 (the "Project Budget") for all anticipated costs to be incurred in connection with the construction and start-up of the Project, including in such budget all construction and non-construction costs, and including all interest, taxes and other carrying costs, and such other information as Agent may require, together with a balanced statement of sources and uses of proceeds (and any other funds necessary to complete the Project), broken down as to separate construction phases and components, which Project Budget shall be satisfactory to Agent. 3.1.23 Base Case Project Projections. Borrower shall have furnished to Agent the Base Case Project Projections of operating expenses and cash flow for the Project showing a minimum projected annual Debt Service Coverage Ratio of 2.11 and an average projected annual Debt Service Coverage Ratio of 2.41 over the term of the Term Loans and otherwise in substantially the form of Exhibit G-5 and in form and substance satisfactory to Agent. 3.1.24 No Material Adverse Change. Since April 22, 1996, in the reasonable judgment of Agent, there shall not have occurred any material adverse change in the Project Budget, Project Schedule or Base Case Project Projections, in the economics or feasibility of constructing and/or operating the Project, or in the financial condition, business, prospects or property of any Major Project Participant, which could reasonably be expected to have a Material Adverse Effect. 3.1.25 A.L.T.A. Surveys. Agent shall have received A.L.T.A. surveys of the Site and the Easements, satisfactory in form and substance to Agent and the Title Insurer, reasonably current and certified to Agent by Weisser Engineering Co. or another licensed surveyor satisfactory to Agent, showing (a) as to the Site, the exact location and dimensions thereof, including the location of all means of access thereto and all easements relating thereto and showing the perimeter within which all foundations are or are to be located; (b) as to the Easements, the exact location and dimensions thereof, including the location of all means of access thereto, and 21 34 all improvements or other encroachments in or on the Easements; (c) the existing utility facilities servicing the Project (including water, electricity, gas, telephone, sanitary sewer and storm water distribution and detention facilities); (d) that such existing improvements do not encroach or interfere with adjacent property or existing easements or other rights (whether on, above or below ground), and that there are no gaps, gores, projections, protrusions or other survey defects; (e) whether the Site or any portion thereof is located in a special earthquake or flood hazard zone; and (f) that there are no other matters that could reasonably be expected to be disclosed by a survey constituting a defect in title other than Permitted Encumbrances. 3.1.26 Title Policy. Borrower shall have delivered to Agent a lender's A.L.T.A. policy of title insurance, together with such endorsements as are required by Agent, or a commitment to issue such a policy (such policy and endorsements or commitment being hereinafter referred to as the "Title Policy"), in the amount of $151,750,000 with such reinsurance as is satisfactory to Agent, issued by the Title Insurer in form and substance satisfactory to Agent, insuring (or agreeing to insure) that: (a) Borrower has a good, marketable and insurable title to or right to control, occupy and use the Site and the Easements, free and clear of liens, encumbrances or other exceptions to title except those exceptions specified on Exhibit D-10 ("Permitted Encumbrances"); and (b) the Deed of Trust is (or will be when recorded) a valid first lien on the Mortgaged Property, free and clear of all liens, encumbrances and exceptions to title whatsoever, other than Permitted Encumbrances. 3.1.27 Qualifying Facility Status. The Project shall have complied with the requirements of 18 C.F.R. Section 209.207 required to be complied with as of the Closing Date and delivered to Agent a certificate of FERC certifying the Project as a Qualifying Facility. 3.1.28 Notice to Proceed. Each Contractor shall have been given an unconditional notice to proceed or otherwise been unconditionally directed to begin performance under the Construction Contract to which it is a party, and shall have acknowledged receipt thereof, on or prior to the Closing Date. 3.1.29 Establishment of Accounts. The Accounts required under Article 7 shall have been established to the satisfaction of the Agent. 3.1.30 Representations and Warranties of Partners and Borrower. Each representation and warranty of the Partners under the Credit Documents and each representation and warranty of Borrower under the Credit Documents shall be true and correct. 3.1.31 Utilities. Agent has received evidence acceptable to Agent in its sole discretion that all necessary utility services are either contracted for, or readily available on reasonable economic terms, at the Project. 22 35 3.1.32 Interest Rate Hedges. Borrower shall have entered into the Interest Rate Agreement and that certain letter agreement described in Section 5.22. 3.1.33 Key Personnel. Construction Manager shall have retained and is engaging, for the performance of its obligations under the Construction Management Agreement, key management personnel which includes the key personnel that were engaged in connection with the development of the Sumas project or which are otherwise acceptable to Agent and Independent Engineer. Such personnel shall include without limitation, Angelo Urbani, as the home office construction manager, and Bill Small, as the project site manager or such other personnel as are reasonably acceptable to Agent. 3.1.34 Project Schedule. Borrower shall have furnished the Project Schedule in substantially the form of Exhibit G-6. 3.1.35 Reports of Borrower's Tax Consultants. Delivery to Agent of sales tax and real property tax reports along with corresponding reliance letters from Arthur Andersen, LLP, each in form and substance satisfactory to Agent. 3.1.36 Reports of Borrower's HCC Evaluation Consultant. Delivery to Agent of an HCC evaluation and assessment report along with a corresponding reliance letter from Pace Consultants, each in form and substance satisfactory to Agent. 3.1.37 Phillips Documents. Phillips shall have provided to Agent (a) a letter confirming the environmental condition of the properties subject to the Easements granted to Borrower pursuant to the Lease and (b) a letter confirming that Phillips has not entered into any agreement nor has otherwise subjected HCC to any noise ordinance or regulation or other noise restrictions, each in form and substance satisfactory to Agent. 3.1.38 Mechanics' Lien Indemnity. Calpine shall have executed and delivered an indemnity in favor of the Banks with respect to mechanics' liens which could gain priority over the Deed of Trust. 3.1.39 Port Authority License. The Port Authority shall have delivered a letter to Agent, stating (i) the Port Authority has authorized the execution and delivery of a license in favor of Borrower relating to certain transmission lines for the Project, (ii) the Authority will execute and deliver such license promptly after preparation thereof, and (iii) the Port Authority will, concurrently with such execution, execute and deliver consent to assignment of such license to Agent, in the form attached to such letter as an exhibit. 3.1.40 Phillips License. Phillips shall have delivered a letter to Agent stating that Phillips has applied or will promptly apply for an amendment to the Oil, Gas, etc. Pipeline License (Railroad Right-of-Way) dated April 1, 1990 between the Port and Phillips 66 Company, as predecessor in interest to Phillips so as to permit Borrower to construct within the 23 36 area described in Exhibit A to the license the improvements contemplated in the Development and Construction Agreement. 3.2 Conditions Precedent to Each Construction Credit Event. The obligation of the Banks to make each Construction Loan (including the first Construction Loan and the final Construction Loan) and to disburse non-Loan proceeds from the Construction Account (each of the foregoing, a "Construction Credit Event"), is subject to the prior satisfaction of each of the following conditions: 3.2.1 Credit Event Conditions Satisfied. The conditions set forth in Section 3.4 shall have been satisfied and Agent shall have received a certificate from Borrower dated the date such Construction Credit Event is proposed to occur, certifying to the matters set forth in Section 3.4. 3.2.2 Monthly Drawdown Frequency. Construction Loans shall be made no more frequently than one time per month. 3.2.3 Notice of Borrowing. Borrower shall have delivered a Notice of Borrowing to Agent in accordance with the procedures specified in Section 2.1. 3.2.4 Drawdown Certificate and Engineer's Certificate. (i) At least ten (10) Banking Days prior to each Construction Credit Event, Borrower shall have provided Agent with a certificate, dated the date of the proposed occurrence of such Construction Credit Event and signed by Borrower, substantially in the form of Exhibit C-5, and (ii) at least four (4) Banking Days prior to each Construction Credit Event, the Independent Engineer shall have provided Agent with a certificate of the Independent Engineer, substantially in the form of Exhibit C-6. 3.2.5 Amount. Construction Loans shall be in such amounts as shall ensure that uncommitted funds remaining in the Construction Account shall be disbursed to the greatest extent possible, given the requirements of Section 2.1.1(b)(ii). 3.2.6 Title Policy Endorsement. Borrower shall provide, or Agent shall be adequately assured that the Title Insurer is committed at the time of each Construction Credit Event to issue, to Agent a date-down endorsement of the Title Policy to the date of such Construction Credit Event, insuring the continuing first priority of the Deed of Trust (subject only to Permitted Encumbrances) and otherwise in form and substance reasonably satisfactory to Agent. 3.2.7 Lien Releases. If requested by Agent and subject to Borrower's right to contest liens as described in the definition of "Permitted Liens," Borrower shall have delivered to Agent duly executed acknowledgments of payments and releases of mechanics' and materialmen's liens, in form satisfactory to Agent, from each Contractor for all work, services and materials, including equipment and fixtures of all kinds, done, previously performed or furnished for the construction of the Project, and in respect of which Borrower has requested payment; provided, however, that such releases may be conditioned upon receipt of payment with 24 37 respect to work, services and materials to be paid for with the proceeds of the requested Construction Loan or other Borrowing. 3.2.8 Applicable Permits. Except as disclosed in Exhibit G-3, all Applicable Permits and Applicable Third Party Permits with respect to the construction and operation of the Project required to have been obtained by Borrower or any Major Project Participant by the date of such Construction Credit Event from any Governmental Authority shall have been issued and be in full force and effect and not subject to current legal proceedings or to any unsatisfied conditions that could reasonably be expect to allow material modification or revocation, and all applicable appeal periods with respect thereto shall have expired. With respect to any of the Permits not yet obtained and listed in Part II(A) or II(B) of Exhibit G-3, no facts or circumstances exist which indicate that any such Permit will not be timely obtainable without material difficulty, expense or delay by Borrower or the applicable Major Project Participant, respectively, prior to the time that it becomes an Applicable Permit or Applicable Third Party Permit, as applicable. Except as disclosed in Exhibit G-3, the Permits which have been obtained by the Borrower or any Major Project Participant shall not be subject to any restriction, condition, limitation or other provision that could reasonably be expected to have a Material Adverse Effect. 3.2.9 Equity Contributions. Borrower shall be in compliance with Section 5.18. 3.2.10 Additional Documentation. With respect to Additional Project Documents and Applicable Permits entered into or obtained, transferred or required (whether because of the status of the construction or operation of the Project or otherwise) since the date of the most recent Construction Credit Event, there shall be redelivery of such matters as are described in Sections 3.1.1 through 3.1.4 and 3.1.6 to the extent applicable to such Additional Project Documents or Applicable Permits and, if reasonably requested by Agent, Sections 3.1.8 and 3.1.20 from the counterparty to such Additional Project Document. 3.2.11 Acceptable Work; No Liens. All work that has been done on the Project shall have been done in a good and workmanlike manner and in accordance with the Construction Contracts and Prudent Utility Practices and there shall not have been filed with or served upon Borrower with respect to the Project or any part thereof notice of any Lien, claim of Lien or attachment upon or claim affecting the right to receive payment of any of the moneys payable to any of the Persons named on such request which has not been released by payment or bonding or otherwise or which will not be released with the payment of such obligation out of such Construction Loan or other Borrowing, other than Permitted Liens. 3.2.12 Casualty. If at the time of any Construction Credit Event, the Project shall have been materially injured or damaged by flood, fire or other casualty, Agent shall have received insurance proceeds or money or other assurances sufficient in the reasonable judgment of Agent and the Independent Engineer to assure restoration and Completion prior to the Construction Loan Maturity Date and each of the conditions set forth in Section 7.11.3 has been satisfied. 25 38 3.2.13 Absence of Litigation. No action, suit, proceeding or investigation shall have been instituted against Borrower, any Partner or the Project which could reasonably be expected to have a Material Adverse Effect, except as approved by Agent with the consent of the Majority Banks. 3.2.14 Insurance. Insurance complying with the requirements of Section 5.19 shall be in effect, and upon the request of Agent evidence thereof shall be provided to Agent. 3.2.15 Key Personnel. The condition set forth in Section 3.1.33 continues to be satisfied as of the date of the Construction Credit Event. 3.2.16 Available Construction Funds. Available Construction Funds shall not be less than the aggregate unpaid amount required to cause the Completion Date to occur in accordance with all Legal Requirements, the Construction Contracts and the Phillips Documents, prior to the Date Certain and to pay or provide for all anticipated non-construction costs, all as set forth in the Project Budget. 3.3 Conditions Precedent to Term-Conversion. No Construction Loans shall Term-Convert unless the following conditions shall have been satisfied: 3.3.1 Payment of Obligations. Borrower shall have paid to Agent the principal amount of the Construction Loans outstanding which will not be Term-Converted to Term Loans as provided in Section 2.1.2(a) plus all interest due and owing on the Construction Loans and all other Obligations of Borrower due and owing to Agent and the Banks hereunder or under the other Credit Documents. 3.3.2 Final Drawing. Immediately prior to Term-Conversion, Borrower shall have requested (in accordance with the terms of this Article 3) a Construction Loan (the "Final Drawing") to be applied in accordance with Section 7.1.4, in the amount, if any, of the remaining Total Construction Loan Commitment up to the sum of (a) an amount sufficient for completion of the Punch List and payment of other Project Costs through Final Completion, determined by Borrower and approved by Agent in consultation with Independent Engineer, (b) the amount required to be funded into the Emissions Offsets Reserve Account at Term-Conversion, (c) the amounts required to be funded into the Fuel Supply Reserve Account at Term-Conversion and (d) the amount required to be funded into the Debt Service Reserve Account at Term-Conversion. 3.3.3 Certificates of Occupancy. Delivery to Agent, in form and substance satisfactory to Agent, of: (a) Evidence that all work requiring inspection by municipal and other Governmental Authorities having jurisdiction has been duly inspected and approved by such authorities, that a final certificate of occupancy or a certificate of final completion has been issued for the Project, that Borrower has duly recorded a notice of completion for the Project, that all 26 39 parties performing such work have been or will be paid for such work, and that no mechanics' and/or materialmen's liens or application therefor have been filed and all applicable filing periods for any such mechanics' and/or materialmen's liens have expired; provided, however, that in the event Borrower delivers to agent either (i) a policy of title insurance or endorsement thereto, in form and substance satisfactory to Agent, insuring against loss arising by reason of any mechanics' or materialmen's lien gaining priority over the Deed of Trust or (ii) a bond, in form and substance satisfactory to Agent, in the amount of all payments owed to any contractor, subcontractor or any other person as to whom the filing periods for mechanics' and materialmen's liens have not expired, and covering Borrower's liability to such contractors, subcontractors or other persons, Agent shall waive the applicable filing periods referred to herein; and (b) A certification by Construction Manager and by Borrower and the Independent Engineer that Completion has been achieved and that an appropriate "Permit to Operate" and "Certificate of Occupancy" for the Project have been issued to Borrower or that Borrower and Agent know of no reason why such certificates will not be issued when and as needed. 3.3.4 Completion. Completion shall have occurred. 3.3.5 Equity Contributions. Borrower shall be in compliance with Section 5.18. 3.3.6 Annual Budget. Agent shall have received the initial Annual Operating Budget as required under Section 5.15.2. 3.3.7 Insurance. Insurance complying with the requirements of Section 5.19 shall be in effect, and upon the request of Agent evidence thereof shall be provided to Agent. 3.3.8 Reserve Accounts. Borrower shall have deposited into (a) the Emissions Offsets Reserve Account, all funds required under Section 7.4, (b) the Fuel Supply Reserve Account, all funds required under Section 7.5 and (c) the Debt Service Reserve Account, all funds required under Section 7.6. 3.3.9 Power Marketing Security Agreement. Borrower shall have entered a security agreement with Power Marketer substantially in the form of Exhibit D-4, with such changes to the description of collateral therein as is necessary to provide Borrower with a first priority lien in the Power Marketing Depository Account and such other changes as may be approved by Agent (the "Power Marketing Security Agreement"). 3.4 Conditions Precedent to Each Credit Event. The obligation of the Banks to effect or permit each Credit Event is subject to the further conditions that, on the date such Credit Event is to occur, the following shall be true and correct: 27 40 3.4.1 Representations and Warranties True and Correct. Each representation and warranty set forth in Article 4 is true and correct as if made on such date, unless such representation or warranty expressly relates solely to another time. 3.4.2 No Event of Default or Inchoate Default. No Event of Default or Inchoate Default has occurred and is continuing or will result from such Credit Event. 3.4.3 Operative Documents, Applicable Permits and Applicable Third Party Permits in Effect. Each Credit Document, Project Document, Additional Project Document, Applicable Permit and Applicable Third Party Permit remains in full force and effect and no material defaults have occurred thereunder. 3.4.4 No Material Adverse Effect. No event or circumstance having a Material Adverse Effect has occurred since the Closing Date (except as is no longer continuing). 3.5 Conditions Precedent to Initial Distribution. Borrower's right to effect the initial distribution as provided in Waterfall Level 11 is subject to the prior satisfaction of each of the following conditions (unless waived in writing by Agent with the consent of the Required Banks): 3.5.1 Term-Conversion. Term-Conversion shall have occurred. 3.5.2 Revised Base Case Projections. Borrower shall have delivered to Agent a current set of Adjusted Base Case Projections if so requested under Section 5.16. 3.5.3 Delivery of Documents. Delivery to Agent on or after the date of Term-Conversion, in form and substance satisfactory to Agent, of such date-down opinions, resolutions, certificates and other evidence as Agent may reasonably request to insure Agent's satisfaction on such date with the matters covered in Sections 3.1.8 (with respect solely to Borrower), 3.1.6, 3.1.10, 3.1.17 and 3.1.19. 3.5.4 Applicable Permits and Applicable Third Party Permits. Borrower shall have obtained or caused to be obtained and delivered to Agent all Applicable Permits, satisfactory in form and substance to Agent, together with copies of each such Applicable Permit and a certificate of an authorized officer of Borrower certifying that all such Permits have been obtained. Each Major Project Participant shall have obtained or caused to be obtained all Applicable Third Party Permits applicable to such Person, satisfactory in form and substance to Borrower and Agent, and Borrower shall deliver or cause to be delivered to Agent copies or other evidence of each such Applicable Third Party Permit and a certificate of an authorized officer of Borrower certifying that all such Applicable Third Party Permits have been obtained. Except as disclosed in Exhibit G-3, all Applicable Permits and Applicable Third Party Permits shall be in full force and effect, not subject to any then current legal proceeding or to any unsatisfied condition that could reasonably be expected to allow material modification or revocation, and all applicable appeal periods with respect thereto shall have expired. 28 41 3.5.5 A.L.T.A. Surveys. Agent shall have received as-built A.L.T.A. surveys of the Site and the Easements, reasonably satisfactory in form and substance to Agent and the Title Insurer, certified to Agent as to completeness and accuracy as of not more than four weeks prior to Term-Conversion by Weisser Engineering Co. or another licensed surveyor reasonably satisfactory to Agent, showing (a) as to the Site, the exact location and dimensions thereof, including the location of all means of access thereto and all easements relating thereto and showing the perimeter within which all foundations are located; (b) as to the Easements, the exact location and dimensions thereof, including the location of all means of access thereto, and all improvements or other encroachments in or on the Easements; (c) the location and dimensions of all improvements, fences or encroachments located in or on the Site or the Easements; (d) that the location of the Project does not encroach on or interfere with adjacent property or existing easements or other rights (whether on, above or below ground), and that there are no gaps, gores, projections, protrusions or other survey defects; (e) whether the Site or any portion thereof is located in a special earthquake or flood hazard zone; and (f) that there are no other matters that could reasonably be expected to be disclosed by a survey constituting a defect in title other than Permitted Encumbrances. 3.5.6 Term Loan Title Policy. Agent shall have received (a) a lender's A.L.T.A. policy of title insurance, together with such endorsements as are reasonably required by Agent and are obtainable in the State of Texas at reasonable costs, in the amount of the aggregate principal amount of the Total Term Loan Commitment at the Conversion Date, issued by the Title Insurer, in form and substance and with such reinsurance as is reasonably satisfactory to Agent, and insuring Agent as to all matters described in Section 3.1.26, the continued first priority of the Lien on the Mortgaged Property evidenced by the Deed of Trust and as to such other matters as Agent may reasonably request, and containing only Permitted Encumbrances, such Permitted Liens as are junior and subordinate to the Deed of Trust and any other exceptions relating to the boundaries of the Site, encroachments and matters disclosed or discoverable by a survey or inspection as are acceptable to Agent in its sole discretion or (b) an endorsement to the A.L.T.A. Policy delivered to Agent pursuant to Section 3.1.26 hereof reasonably satisfactory to Agent reflecting the items referred to above (such policy and endorsements, or endorsement, being referred to as the "Term Loan Title Policy"). 3.5.7 Power Marketing. Either of the following has occurred: (i) Borrower has entered into one or more Distribution Threshold Power Sales Agreements, covering, in the aggregate, at least 75 MW of firm energy and capacity or (ii) the Project's Four-Quarter Average Debt Service Coverage Ratio has equaled or exceeded, for five (5) consecutive calendar quarters, 90% of the annual Debt Service Coverage Ratios for the year of calculation set forth in the Base Case Project Projections in effect as of the Closing Date for such five (5) consecutive calendar quarters. 3.6 No Approval of Work. The making of any Loan hereunder shall not be deemed an approval or acceptance by Agent or the Banks of any work, labor, supplies, materials or equipment furnished or supplied with respect to the Project. 29 42 3.7 Waiver of Funding; Adjustment of Drawdown Requests. Notwithstanding the foregoing, the Required Banks, without waiving any of the Banks' rights hereunder, shall have the right to effect a Credit Event hereunder without full compliance by Borrower with the conditions described in this Article 3. In the event Agent determines that an item or items listed in a Drawdown Certificate as a Project Cost is not properly included in such Drawdown Certificate, Agent may in its reasonable discretion cause to be made a Loan or Loans in the amount requested in such Drawdown Certificate less the amount of such item or items or may reduce the amount of Loans made pursuant to any subsequent Drawdown Certificate. In the event that Borrower prevails in any dispute as to whether such Project Costs were properly included in such Drawdown Certificate, Loans in the amount requested but not initially made shall forthwith be made. ARTICLE 4 - REPRESENTATIONS AND WARRANTIES Borrower makes the following representations and warranties to and in favor of Agent and the Banks as of the Closing Date and as of the date of each Credit Event. All of these representations and warranties shall survive the Closing Date and the making of the Loans: 4.1 Organization. 4.1.1 Borrower (a) is a limited partnership duly constituted, validly existing and in good standing under the laws of the State of Delaware and (b) is duly qualified, authorized to do business and in good standing in the States of California and Texas and in each other jurisdiction where the character of its properties or the nature of its activities makes such qualification necessary. Borrower has all requisite partnership power and authority to own or hold under lease and operate the property it purports to own or hold under lease and to carry on its business as now being conducted and as now proposed to be conducted in respect of the Project. On the Closing Date, (i) CPC is the sole general partner of Borrower and CTC is the sole limited partner of Borrower and (ii) the sole direct owners of the Partners are the specific Persons identified by name under the definition of "Shareholders". 4.1.2 CPC (a) is a corporation duly organized and validly existing and in good standing under the laws of the State of Delaware with all requisite corporate power and authority under the laws of the State of Delaware to enter into the Partnership Agreement and as the general partner of Borrower to perform its obligations thereunder and to consummate the transactions contemplated thereby, (b) is duly qualified, authorized to do business and in good standing in the State of Texas and each other jurisdiction where the character of its properties or the nature of its activities makes such qualification necessary, (c) has the corporate power (i) to carry on its business as now being conducted and as proposed to be conducted by it, (ii) to execute, deliver and perform each Operative Document to which it is a party, in its individual capacity, (iii) to take all action as may be necessary to consummate the transactions contemplated thereunder and (iv) to grant the liens and security interest provided for in the Pledge and Security Agreement to which it is a party and (d) has the power and authority under the Partnership 30 43 Agreement to execute and deliver, on behalf of Borrower, each Operative document to which Borrower is a party. 4.2 Authorization; No Conflict. Borrower has duly authorized, executed and delivered each Operative Document to which Borrower is a party and neither Borrower's execution and delivery thereof nor its consummation of the transactions contemplated thereby nor its compliance with the terms thereof (a) does or will contravene the Partnership Agreement, the Articles or Certificate of Incorporation or bylaws of any Partner or any other Legal Requirement applicable to or binding on Borrower or any of its properties, (b) does or will contravene or result in any breach of or constitute any default under, or result in or require the creation of any Lien (other than Permitted Liens) upon any of its property under, any agreement or instrument to which it is a party or by which it or any of its properties may be bound or affected or (c) does or will require the consent or approval of any Person which has not already been obtained. 4.3 Enforceability. Each of the Operative Documents to which Borrower is a party is a legal, valid and binding obligation of Borrower enforceable against Borrower, in accordance with its terms, except to the extent that enforceability may be limited by applicable bankruptcy, insolvency, moratorium, reorganization or other similar laws affecting the enforcement of creditors' rights or by the effect of general equitable principles. None of the Operative Documents to which Borrower is a party has been amended or modified except in accordance with this Agreement. 4.4 Compliance with Law. There are no violations by Borrower, any Partner or, to Borrower's knowledge, any Shareholder of any Legal Requirement which could reasonably be expected to have a Material Adverse Effect. Except as otherwise have been delivered to Agent, no notices of violation of any Legal Requirement relating to the Project or the Site have been issued, entered or received by Borrower, any Partner or, to Borrower's knowledge, any Shareholder. 4.5 Business, Debt, Contracts, Joint Ventures Etc. 4.5.1 Neither any Partner nor Borrower has conducted any business other than the business contemplated by the Operative Documents, has any outstanding Debt or other material liabilities other than pursuant to or allowed by the Operative Documents, and is not a party to or bound by any material contract other than the Operative Documents to which it is a party. 4.5.2 Borrower is not a general partner or a limited partner in any general or limited partnership or a joint venturer in any joint venture. 4.5.3 Neither Borrower nor any Partner thereof has any subsidiaries. 4.6 Adverse Change. To the best of Borrower's knowledge, there has occurred no material adverse change in the Project Budget, Project Schedule or Base Case Project 31 44 Projections, in the economics or feasibility of constructing and/or operating the Project, or in the financial condition, business or property of any Major Project Participant, or any other event or circumstance which is reasonably likely to have a Material Adverse Effect (a) as of the Closing Date, since April 22, 1996 and (b) after the Closing Date, except as disclosed to Agent in writing at the time the representation in this Section 4.6 is being made, since the Closing Date. 4.7 Investment Company Act, Etc. Neither Borrower nor any Partner is an investment company or a company controlled by an investment company, within the meaning of the Investment Company Act of 1940, and neither Borrower nor any Partner is or has been determined by the Securities and Exchange Commission or any other Governmental Authority to be subject to, or not exempt from, regulation under PUHCA or the FPA (other than as provided by PURPA). 4.8 ERISA. Either (a) there are no ERISA Plans for Borrower or any member of the Controlled Group or (b) Borrower and each member of the Controlled Group have fulfilled their obligations (if any) under the minimum funding standards of ERISA and the Code for each ERISA Plan in compliance in all material respects with the currently applicable provisions of ERISA and the Code and have not incurred any liability to the PBGC or an ERISA Plan under Title IV of ERISA (other than liability for premiums due in the ordinary course). Assuming that the credit extended hereunder does not involve the assets of any employee benefit plan subject to ERISA, neither the execution of this Agreement nor the consummation of the transactions contemplated hereby will involve a "prohibited transaction" within the meaning of Section 406 of ERISA or Section 4975 of the Code which is not exempt under Section 408 of ERISA or under Section 4975(d) of the Code. 4.9 Permits. 4.9.1 There are no Permits under existing law as the Project is currently designed that are or will become Applicable Permits other than the Applicable Permits described in Exhibit G-3 hereto. Each Applicable Permit listed in Part I(A) of Exhibit G-3 is in full force and effect, and except as disclosed therein, is not subject to any current legal proceeding or to any unsatisfied condition that could reasonably be expected to have a Material Adverse Effect, and all applicable appeal periods with respect thereto have expired. Each Permit listed in Part II(A) of Exhibit G-3 is of a type that is routinely granted upon application and that would not normally be obtained before contemplated by Borrower. No fact or circumstance exists, to Borrower's knowledge, which indicates that any Permit identified in Part II(A) of Exhibit G-3 shall not be timely obtainable without material difficulty, expense or delay by Borrower before it becomes an Applicable Permit. Borrower is in compliance in all material respects with all Applicable Permits. 4.9.2 There are no Permits under existing law as the Project is currently designed that are or will become an Applicable Third Party Permits other than the Applicable Third Party Permits described in Exhibit G-3 hereto (other than those, the failure of which to obtain could not reasonably be expected to have a Material Adverse Effect). Each Applicable Third Party Permit listed in Part I(B) of Exhibit G-3 is in full force and effect, and except as 32 45 disclosed therein, is not subject to current legal proceeding or to any unsatisfied condition that could reasonably be expected to have a Material Adverse Effect, and all applicable appeal periods with respect thereto have expired. No fact or circumstance exists, to Borrower's knowledge, which indicates that any Permit identified in Part II(B) of Exhibit G-3 shall not be timely obtainable without material difficulty, expense or delay by the applicable Major Project Participant before it becomes an Applicable Third Party Permit. To the best knowledge of Borrower, each Major Project Participant is in compliance in all material respects with its respective Applicable Third Party Permits, each other Major Project Participant possesses all licenses, franchises, patents, copyrights, trademarks and trade names, or rights thereto necessary to perform its duties under the Operative Documents to which it is a party, and such Person is not in violation of any valid rights of others with respect to any of the foregoing which could reasonably be expected to have a Material Adverse Effect. 4.10 Qualifying Facility. The Project qualifies as, and, upon and following the Completion Date, is a Qualifying Facility. 4.11 Hazardous Substance. 4.11.1 Borrower has previously delivered to Agent the Environmental Reports and Agent acknowledges receipt thereof. Except as set forth in Exhibit G-8: (a) neither Borrower nor any Partner nor any Shareholder (the "Subject Companies"), with respect to the Site, Improvements or other Mortgaged Property, is or has in the past been in violation of any Hazardous Substance Law which violation could reasonably be expected to result in a material liability to any of the Subject Companies or their respective properties and assets or in an inability of Borrower to perform its obligations under the Operative Documents; (b) none of the Subject Companies nor, to the best knowledge of the Partners and Borrower, any third party has used, released, discharged, generated, manufactured, produced, stored, or disposed of in, on, under, or about the Site, Improvements or other Mortgaged Property, or transported thereto or therefrom, any Hazardous Substances that could reasonably be expected to subject the Banks to liability or the Subject Companies to liability, under any Hazardous Substance Law; (c) there are no underground tanks, whether operative or temporarily or permanently closed, located on the Site, Improvements or other Mortgaged Property; (d) there are no Hazardous Substances used, stored or present at, on or, to the best knowledge of Borrower and the Partners after due inquiry, near the Site, Improvements or other Mortgaged Property, except in compliance with Hazardous Substance Laws and other Legal Requirements or as disclosed in the Environmental Reports; and (e) to the best knowledge of Borrower and the Partners after due inquiry, there neither is nor has been any condition, circumstance, action, activity or event that could reasonably be expected to be a material violation by the Subject Companies of any Hazardous Substance Law, or to result in liability to the Banks or material liability to the Subject Companies under any Hazardous Substance Law. 4.11.2 Except as set forth on Exhibit G-7 or Exhibit G-8, there is no pending or, to the best knowledge of Borrower, threatened, action or proceeding by any Governmental Authority (including, without limitation, the Texas Natural Resource Conservation 33 46 Commission and the U.S. Environmental Protection Agency) or any non-governmental third party with respect to the presence or Release of Hazardous Substances in, on, from or to the Site, Improvements or other Mortgaged Property. 4.11.3 Neither Borrower nor any Partner nor Shareholder has knowledge of any past or existing violations of any Hazardous Substances Laws by any Person relating in any way to the Site, Improvements or other Mortgaged Property. 4.12 Litigation. Except as set forth on Exhibit G-7, there are no pending or, to the best knowledge of Borrower, threatened actions or proceedings of any kind, including actions or proceedings of or before any Governmental Authority, to which Borrower, any Partner, any Shareholder, or, to the best knowledge of Borrower, any other Major Project Participant or the Project is a party or is subject, or by which any of them or any of their properties or the Project are bound, which if adversely determined to or against Borrower, any other Major Project Participant or the Project could reasonably be expected to have a Material Adverse Effect. 4.13 Labor Disputes and Acts of God. Neither the business nor the properties of Borrower, any Partner, any Shareholder, or, to the best knowledge of Borrower, any other Major Project Participant are affected by any fire, explosion, accident, strike, lockout or other labor dispute, drought, storm, hail, earthquake, embargo, act of God or of the public enemy, or other casualty (whether or not covered by insurance), which could reasonably be expected to have a Material Adverse Effect. 4.14 Project Documents. 4.14.1 Copies of all of the Project Documents in effect as of such date have been delivered to Agent by Borrower. Except as has been previously disclosed in writing to Agent, as of the Closing Date none of the Project Documents has been amended, modified or terminated. 4.14.2 To Borrower's knowledge, the representations and warranties of the Major Project Participants contained in the Operative Documents other than this Agreement are true and correct. 4.15 Disclosure. Neither this Agreement nor any certificate or other documentation furnished to Agent, or to any consultant submitting a report to Agent, by or, to the knowledge of Borrower, on behalf of Borrower in connection with the transactions contemplated by this Agreement, the other Project Documents or the design, description, testing or operation of the Project, contains any untrue statement of a material fact or omits to state a material fact necessary in order to make the statements contained herein or therein not misleading under the circumstances in which they were made at the time such statements are made. As of the Closing Date, there is no fact known to Borrower which has had or could reasonably be expected to have a Material Adverse Effect which has not been set forth in this Agreement or in the other documents, certificates and written statements furnished to Agent and/or the Independent 34 47 Engineer, by or on behalf of Borrower prior to the Closing Date in connection with the transactions contemplated hereby. The documentation furnished to Agent and to the Independent Engineer on or prior to the Closing Date, as the case may be, taken as a whole, including without limitation written updated or supplemented information, is true and correct in all material respects and all such documentation does not omit to state any fact which would have a Material Adverse Effect. 4.16 Private Offering by Borrower. Assuming that the Banks are acquiring the Notes for investment purposes only, and not for purposes of resale or distribution thereof except for assignments or participations as provided in Sections 10.13 and 10.14, no registration of the Notes under the Securities Act of 1933, as amended, or under the securities laws of the State of Texas or New York is required in connection with the offering, issuance and sale of the Notes hereunder. Neither Borrower nor anyone acting on its behalf has taken, or will take, any action which would subject the issuance or sale of the Notes to Section 5 of the Securities Act of 1933, as amended. 4.17 Taxes. Borrower and each Partner has filed all federal, state and local tax returns that it is required to file, has paid all taxes it is required to pay to the extent due (other than those taxes that it is contesting in good faith and by appropriate proceedings, with adequate, segregated reserves or other security reasonably acceptable to Agent established for such taxes) and, to the extent such taxes are not due, has established reserves that are adequate for the payment thereof and are required by GAAP. For federal income tax purposes, Borrower is a partnership and not an association taxed as a corporation. 4.18 Governmental Regulation. None of Borrower, any Partner, Agent, or the Banks, nor any Affiliate of any of them will, solely as a result of the construction, ownership, leasing or operation of the Project, the sale of electricity therefrom or the entering into any Operative Document or any transaction contemplated hereby or thereby, be subject to, or not exempt from, regulation under the FPA or PUHCA or under state laws and regulations respecting the rates or the financial or organizational regulation of electric utilities. Borrower is not subject to regulation under any Governmental Rule as to securities, rates or financial or organizational matters that would preclude any Loans, or the incurrence by Borrower of any of the Obligations or the execution, delivery and performance by Borrower of the Operative Documents. Borrower will not be deemed by any Governmental Authority having jurisdiction to be subject to financial, organizational or rate regulation as an "electric utility," "electric corporation," "electrical company," "public utility," "public utility holding company" or any similar entity under any existing law, rule or regulation of any Governmental Authority. 4.19 Regulation U, Etc. Borrower is not engaged principally, or as one of its principal activities, in the business of extending credit for the purpose of purchasing or carrying margin stock (as defined in Regulations G, T, U or X of the Federal Reserve Board), and no part of the proceeds of the Loans or the Project Revenues will be used by Borrower to purchase or carry any such margin stock or to extend credit to others for the purpose of purchasing or carrying any such margin stock. 35 48 4.20 Project Budget; Projections; Commercial Operation Date. Borrower has prepared the Project Budget and the Base Case Project Projections and is responsible for developing the assumptions on which the Project Budget and the Base Case Project Projections are based; and the Project Budget and the Base Case Project Projections (a) are based on reasonable assumptions as to all legal and factual matters material to the estimates set forth therein, (b) as of the Closing Date are consistent with the provisions of the Project Documents and (c) indicate that the estimated Project Costs will not exceed funds available to pay Project Costs. In the reasonable opinion of Borrower, as of the Closing Date the textual material accompanying the Base Case Project Projections discloses all information reasonably necessary for an understanding of the Base Case Project Projections, and does not contain any material misstatements or omit any information which, in conjunction with other information given, would be necessary to make such information not materially misleading. 4.21 Financial Statements. The financial statements of Borrower, the Partners, Calpine, and Power Marketer delivered pursuant to Section 3.1.20 and Section 5.5 are true, complete and correct and fairly present the financial condition of each such Person as of the date thereof. Such financial statements have been prepared in accordance with GAAP. Neither Borrower, the Partners, Calpine, or Power Marketer has any material liabilities, direct or contingent, except as has been disclosed in such financial statements. 4.22 Existing Defaults. Borrower is not in default under any material term of any Operative Document or any agreement relating to any obligation of Borrower for or with respect to borrowed money, and to the best of Borrower's knowledge, no other party to any Project Document is in default thereunder. 4.23 No Default. No Event of Default or Inchoate Default has occurred or is existing. 4.24 Offices, Location of Collateral. 4.24.1 The chief executive office or chief place of business (as such term is used in Article 9 of the Uniform Commercial Code as in effect in the State of Texas from time to time) of Borrower is located at San Jose, California. Borrower's federal employer identification number is 77-0444630. 4.24.2 All of the Collateral (other than the Accounts and general intangibles), including the Mortgaged Property is, or when installed pursuant to the Project Documents will be, located on the Site or the Easements or at the address set forth in Section 4.24.1. 4.24.3 Borrower's books of accounts and records are located at 50 West San Fernando Street, San Jose, California 95113. 36 49 4.25 Title and Liens. Borrower has good, marketable and insurable title to the Project, and all of the Collateral relating to the Project, and good, marketable and insurable title to, or as applicable, a leasehold estate in, the Site and the Easements (except that title to certain of the Easements which are licenses may not be insurable), in each case free and clear of all Liens, encumbrances or other exceptions to title other than Permitted Liens. The Lien of the Collateral Documents constitutes a valid and subsisting first priority lien of record on all the Mortgaged Property described in the Deed of Trust and a first priority perfected security interest in all the personal property described in the Collateral Documents, subject to no Liens except Permitted Encumbrances. 4.26 Trademarks. Borrower owns or has the right to use all patents, trademarks, service marks, trade names, copyrights, licenses and other rights, which are necessary for the operation of its business. Nothing has come to the attention of Borrower to the effect that (a) any material product, process, method, substance, part or other material presently contemplated to be sold by or employed by Borrower in connection with its business will infringe any patent, trademark, service mark, trade name, copyright, license or other right owned by any other Person, (b) there is pending or threatened any claim or litigation against or affecting Borrower contesting its right to sell or use any such product, process, method, substance, part or other material or (c) there is, or there is pending or proposed, any patent, invention, device, application or principle or any statute, law, rule, regulation, standard or code relating to the use of technology or intellectual property by Borrower which could reasonably have a Material Adverse Effect. 4.27 Collateral. The security interests granted to Agent pursuant to the Collateral Documents in the Collateral (a) constitute as to personal property included in the Collateral and, with respect to subsequently acquired personal property included in the Collateral, will constitute, a perfected security interest under the UCC to the extent a security interest can be perfected by filing or, in the case of the Accounts, by possession by or on behalf of the secured party and (b) are, and, with respect to such subsequently acquired property, will be, as to Collateral perfected under the UCC as aforesaid, superior and prior to the rights of all third Persons now existing or hereafter arising whether by way of mortgage, lien, security interests, encumbrance, assignment or otherwise except for Phillips' rights under the Ground Lease with respect to the Development and Construction Easements upon the Commercial Operation Date or earlier termination of the Ground Lease and with respect to the Project upon Phillips' exercise of the Project Purchase Option or upon surrender or termination of the Ground Lease. Except to the extent possession of portions of the Collateral is required for perfection, all such action as is necessary has been taken to establish and perfect Agent's rights in and to the Collateral to the extent Agent's security interest can be perfected by filing, including any recording, filing, registration, giving of notice or other similar action. As of the Closing Date, no filing, recordation, re- filing or re-recording other than those listed on Exhibit D-11 hereto is necessary to perfect and maintain the perfection of the interest, title or Liens of the Collateral Documents, and on the Closing Date all such filings or recordings will have been made to the extent Agent's security interest can be perfected by filing. Borrower has properly delivered or caused to be delivered to Agent all Collateral that requires perfection of the Lien and security interest described above by possession. 37 50 4.28 Sufficiency of Project Documents. 4.28.1 Other than those that can be reasonably expected to be commercially available when and as required, the services to be performed, the materials to be supplied and the real property interests, the Easements and other rights granted pursuant to the Project Documents: (a) comprise all of the property interests necessary to secure any right material to the acquisition, leasing, development, construction, installation, completion, operation and maintenance of the Project in accordance with all Legal Requirements and in accordance with the Project Schedule, all without reference to any proprietary information not owned by Borrower; (b) are sufficient to enable the Project to be located, constructed and operated on the Site and the Easements; and (c) provide adequate ingress and egress from the Site for any reasonable purpose in connection with the construction and operation of the Project. 4.28.2 There are no services, materials or rights required for the construction or operation of the Project in accordance with the Construction Contracts and the Base Case Project Projections other than those that can reasonably be expected to be commercially available at the Site on commercially reasonable terms consistent with the Project Budget and the Base Case Project Projections. 4.29 Utilities. All utility services necessary for the construction and the operation of the Project for its intended purposes are available at the Project or will be so available as and when required upon commercially reasonable terms consistent with the Project Budget, Project Schedule and the Base Case Project Projections. 4.30 Roads/Transmission Line. 4.30.1 All roads necessary for the construction and full utilization of the Project for its intended purposes have either been completed or the necessary rights of way therefor have been acquired. 4.30.2 All necessary easements, rights of way, licenses, agreements and other rights for the construction, interconnection and utilization of (a) the interconnection facilities (including the interconnection to the HL&P grid) and (b) the Steam Line have been acquired. 4.31 Proper Subdivision. The Site has been properly subdivided or entitled to exception therefrom, and for all purposes the Site may be mortgaged, conveyed and otherwise dealt with as separate legal lots or parcels. 38 51 4.32 Flood Zone Disclosure. None of the Collateral includes improved real property that is or will be located in an area that has been identified by the Director of the Federal Emergency Management Agency as an area having special flood hazards and in which flood insurance has been made available under the National Flood Insurance Act of 1968, as amended. ARTICLE 5 - COVENANTS OF THE BORROWER Borrower covenants and agrees that so long as this Agreement is in effect, it will: 5.1 Use of Proceeds and Project Revenues. 5.1.1 Proceeds. Unless otherwise applied by Agent pursuant to this Agreement, deposit the proceeds of the Construction Loans in the Construction Account, hold such proceeds as a trust fund for the payment of Project Costs, and use them solely to pay Project Costs. 5.1.2 Revenues. Unless otherwise applied by Agent pursuant to Articles 7 and 8, deposit all Project Revenues other than Insurance Proceeds, Eminent Domain Proceeds and damage payments described in Section 7.13 received prior to Term-Conversion in the Construction Account for application toward Project Costs and otherwise for application as set forth in Section 7.1, deposit all Project Revenues other than Insurance Proceeds, Eminent Domain Proceeds and damage payments described in Section 7.13 received after Term-Conversion in the Revenue Account for application solely for the purposes and in the order and manner provided in Section 7.2, and deposit all Insurance Proceeds, Eminent Domain, proceeds and damage payments described in Section 7.13 received at any time in the Loss Proceeds Account for application solely for the purposes, and in the order and manner, provided in Section 7.7. 5.2 Payment. 5.2.1 Credit Documents. Pay all sums due under this Agreement and the other Credit Documents according to the terms hereof and thereof. 5.2.2 Project Documents. Pay all obligations due under the Project Documents, howsoever arising, as and when due and payable, except (a) such as may be contested in good faith or as to which a bona fide dispute may exist, provided that Agent is satisfied in its reasonable discretion that non-payment of such obligation pending the resolution of such contest or dispute will not in any way endanger or materially adversely affect the Project, the Banks' Liens in the Collateral or Borrower or that provision is made to the satisfaction of Agent in its reasonable discretion for the posting of security (other than the Collateral) for or the bonding of such obligations or the prompt payment thereof in the event that such obligation is payable and (b) Borrower's trade payables which shall be paid in the ordinary course of business. 5.3 Warranty of Title. Maintain (a) good, marketable and insurable leasehold title to the Site and related Easements, subject only to Permitted Liens, and (b) good, marketable 39 52 and insurable title to all of its other respective properties and assets (other than properties and assets disposed of in the ordinary course of business). 5.4 Notices. Promptly, upon acquiring notice or giving notice, as the case may be, or obtaining knowledge thereof, give written notice (with copies of any such underlying notices) to Agent of: 5.4.1 Any litigation pending or, to the knowledge of Borrower, threatened against Borrower involving claims against Borrower or the Project in excess of $100,000 in the aggregate per calendar year or involving any injunctive, declaratory or other equitable relief, such notice to include, if requested by Agent, copies of all papers filed in such litigation and to be given monthly if any such papers have been filed since the last notice given; 5.4.2 Any dispute or disputes which may exist between Borrower and any Governmental Authority and which involve (a) claims against Borrower which exceed $100,000 individually or $250,000 in the aggregate per calendar year, (b) injunctive or declaratory relief, (c) revocation, modification, failure to renew or the like of any Applicable Permit or Applicable Third Party Permit or imposition of additional material conditions with respect thereto, or (d) any Liens for taxes due but not paid; 5.4.3 Any Event of Default or Inchoate Default; 5.4.4 Any casualty, damage or loss, whether or not insured, through fire, theft, other hazard or casualty, or any act or omission of Borrower, its employees, agents, contractors, consultants or representatives, or of any other Person if such casualty, damage or loss affects Borrower or the Project, in excess of $100,000 for any one casualty or loss or in the aggregate in any policy period; 5.4.5 Any cancellation or material change in the terms, coverage or amounts of any insurance described in Exhibit K; 5.4.6 Any matter which has had, or, in Borrower's reasonable judgment, could reasonably be expected to have, a Material Adverse Effect, including any PUC or FERC proceedings affecting the Project which if adversely determined, reasonably could be expected to have a Material Adverse Effect; 5.4.7 Any contractual obligations incurred by Borrower exceeding $100,000 per year in the aggregate for the Project, not including any obligations incurred pursuant to the Credit Documents or the Project Documents (excluding Additional Project Documents and the Partnership Agreement) or any obligation contemplated in the approved Annual Operating Budget; 40 53 5.4.8 Any act by Borrower to become a surety, guarantor, endorser or accommodation endorser for a third party other than endorsement of negotiable instruments for collection purposes; 5.4.9 Any intentional withholding of compensation to any Contractor, any engineer or Operator or any other Person under any Construction Contract, or the O&M Agreement, or any other construction or operating contract relating to the Project, other than retention provided by the express terms of any such contracts; 5.4.10 Any termination or material default or notice thereof (including any notice of default) under any Project Document; 5.4.11 Any events of force majeure or change orders under any Construction Contract or other Project Documents and, to the extent requested by Agent, copies of invoices or statements which are reasonably available to Borrower under such Construction Contract, certified by an authorized representative of Borrower, together with a copy of any supporting documentation, schedule, data or affidavit delivered under the Construction Contract or such other Project Document; 5.4.12 No later than the date upon which the Independent Engineer is entitled to receive notice pursuant to any Construction Contract of the proposed conduct of the initial Performance Tests under such Construction Contract, promptly prior to the proposed conduct of any subsequent Performance Tests pursuant to each such Construction Contract and promptly prior to the conduct of any performance tests required under any other Project Document, written notice of such proposed test; 5.4.13 Any (a) fact, circumstance, condition or occurrence at, on, or arising from, the Site, Improvements, or other Mortgaged Property that results in material noncompliance with any Hazardous Substance Law or any Release of Hazardous Substances on or from the Site, Improvements or other Mortgaged Property that has resulted or could reasonably be expected to result in personal injury or material property damage or to have a Material Adverse Effect, and (b) pending or, to Borrower's knowledge, threatened, Environmental Claim against Borrower or to Borrower's knowledge any of its Affiliates, contractors, lessees or any other Persons, arising in connection with their occupying or conducting operations on or at the Project, the Site, the Improvements or the other Mortgaged Property; 5.4.14 Promptly, but in no event later than 30 days if consent of Agent or the Bank is required, and 15 days otherwise, prior to the time any Person will become a partner of Borrower or the occurrence of any other change in or transfer of ownership interests in Borrower or the Project, notice thereof, which notice shall identify such partner and such partner's interest in Borrower or shall describe, in reasonable detail, such other change or transfer; 5.4.15 Any material notices delivered to or received from, the parties to the Project Documents, including any Pricing Notices; 41 54 5.4.16 Initiation of any condemnation proceedings involving the Project or the Site or any portion thereof; and 5.4.17 Promptly, but in no event later than 15 days after Borrower has knowledge of the execution and delivery thereof, a copy of each Additional Project Document. 5.4.18 Promptly, but in no event later than 30 days after the receipt thereof by Borrower, copies of (a) all Applicable Permits obtained by Borrower or any Partner after the Closing Date, (b) any amendment, supplement or other modification to any Applicable Permits received by Borrower after the closing Date and (c) all material notices relating to the Project received by Borrower from any Governmental Authority. 5.5 Financial Statements. 5.5.1 Unless Agent otherwise consents, deliver or cause to be delivered to Agent, in form and detail reasonably satisfactory to Agent: (a) As soon as practicable and in any event within 45 days after the end of the first, second and third quarterly accounting periods of its fiscal year (commencing with the quarter ending March 31, 1997), an unaudited balance sheet of Borrower, the Partners, the Shareholders, Calpine, Power Marketer, Fuel Supplier (or its parent corporation) and HL&P (or its parent corporation) and Phillips as of the last day of such quarterly period and the related statements of income, cash flows, and partners' capital (where applicable) for such quarterly period and (in the case of second and third quarterly periods) for the portion of the fiscal year ending with the last day of such quarterly period, setting forth in each case in comparative form corresponding unaudited figures from the preceding fiscal year (such requirement may be satisfied with respect to Phillips, Shareholder, Calpine, Fuel Supplier and HL&P (or Fuel Supplier's and HL&P's respective parent corporations) by delivery of the appropriate Form 10-Q filed with the Securities and Exchange Commission); and (b) As soon as available but no later than 120 days after the close of each applicable fiscal year, audited financial statements of Borrower, the Partners, the Shareholders, Calpine, Power Marketer, Phillips, and, to the extent reasonably available, the Fuel Supplier and HL&P (or their respective parent corporations), including a statement of equity, a balance sheet as of the close of such year, an income and expense statement, reconciliation of capital accounts and a statement of sources and uses of funds, all prepared in accordance with GAAP and in the case of audited financial statements, certified by an independent certified public accountant selected by the Person whose financial statements are being prepared and satisfactory to Agent. Such certificate for Borrower, each Partner, each Shareholder, Calpine, Power Marketer, Phillips, the Fuel Supplier and HL&P (or their respective parent corporations) shall not be qualified or limited because of restricted or limited examination by such accountant of any material portion of the records of the applicable Person. Such requirement may be satisfied with respect to Phillips, Shareholder, Calpine, Fuel Supplier and HL&P, (or Fuel Supplier's and 42 55 HL&P's respective parent corporations) by delivery of the appropriate Form 10-K filed with the Securities and Exchange Commission. 5.5.2 Each time the financial statements are delivered under Section 5.5.1(a) above for Borrower, the Partners, the Shareholders, Calpine, Power Marketer (if an Affiliate of Borrower), cause to be delivered, along with such financial statements, a certificate signed by a Responsible Officer of such Person, certifying that such officer has made or caused to be made a review of the transactions and financial condition of such Person during the relevant fiscal period and that such review has not, to the best of such Responsible Officer's knowledge, disclosed the existence of any event or condition which constitutes an Event of Default or Inchoate Default, or if any such event or condition existed or exists, the nature thereof and the corrective actions that such Person has taken or proposes to take with respect thereto, and also certifying that such Person is in compliance with all applicable material provisions of each Credit Document to which such Person is a party or, if such is not the case, stating the nature of such non-compliance and the corrective actions which such Person has taken or proposes to take with respect thereto. 5.6 Books, Records, Access. Maintain adequate books, accounts and records with respect to Borrower and the Project and prepare all financial statements required hereunder in accordance with GAAP and in compliance with the regulations of any Governmental Authority having jurisdiction thereof, and, subject to requirements of Governmental Rules and safety requirements, after pre-scheduling with the Operator, permit employees or agents of Agent and Independent Engineer at any reasonable times and upon reasonable prior notice to inspect all of Borrower's properties, including the Site, to examine or audit all of Borrower's books, accounts and records and make copies and memoranda thereof and to witness the Performance Tests. 5.7 Compliance with Laws, Instruments, Etc. Promptly comply, or cause compliance, in all material respects, with all Legal Requirements, including Legal Requirements relating to pollution control, environmental protection, equal employment opportunity or employee benefit plans, ERISA Plans and employee safety, with respect to Borrower or the Project, and make such alterations to the Project and the Site as may be required for such compliance. 5.8 Reports. 5.8.1 Deliver to Agent on the last Banking Day of each month prior to Final Completion in which no Loan is made (if any) a certificate of an authorized officer of Borrower as to the matters required by Section 3.2.4, substantially in the form of the Drawdown Certificate. 5.8.2 Deliver to Agent at such times as Agent may reasonably request (but not more frequently than monthly) a report describing in reasonable detail the progress of the construction of the Project since the last prior report hereunder. 43 56 5.8.3 Within 30 days following the completion of the major foundations for the Project, provide to Agent a foundation survey showing (a) the exact location and dimensions of such foundations, (b) that such foundations comply with all applicable building and zoning codes and set-back lines, and (c) that such foundations do not encroach or interfere with existing property rights. 5.8.4 Deliver to Agent within 30 days of the end of each month after Term-Conversion, a summary operating report which shall include, with respect to the month most recently ended, (a) a monthly and year-to-date numerical and narrative assessment of (i) the Project's compliance with each material category in the Annual Operating Budget, (ii) electrical and steam production and delivery, (iii) fuel deliveries and use, including heat rate, (iv) plant and unit availability, including trips and scheduled and unscheduled outages, (v) cash receipts and disbursements and cash balances, including distributions to the Partners, debt service payments and balances in the Accounts, (vi) maintenance activity, (vii) staffing changes with respect to project or construction managers, (viii) casualty losses of value in excess of $100,000, (ix) replacement of equipment of value in excess of $100,000 and (x) material disputes with contractors, materialmen, suppliers or others and any related claims against Borrower; (b) statistical data and reasonably detailed commentary thereon; and (c) a comparison of year-to-date figures to corresponding figures provided in the prior year. 5.8.5 Deliver to Agent within 60 days of the end of each year a report setting forth a narrative summary describing and assessing the Project's compliance with all Applicable Permits and Legal Requirements. 5.8.6 Provide to Agent promptly upon request such reports, statements, lists of property, accounts, budgets, forecasts and other information concerning the Project and, to the extent reasonably available, the Major Project Participants and at such times as Agent shall reasonably require, including such reports and information as are reasonably required by the Independent Consultants. 5.8.7 Provide to Agent promptly upon receipt by Borrower any material notices, information or reports provided by (a) Phillips under the Energy Sales Agreement, (b) HL&P under the HL&P Agreements, (c) Power Marketer under any Power Marketing Project Document or (d) any other purchaser under a Power Purchase Document. 5.8.8 Within 30 days of the end of each fiscal year, deliver to Agent a certificate, substantially in the Form of Exhibit L hereto, and otherwise in form and substance satisfactory to Agent in consultation with the Insurance Consultant, certifying that the insurance requirements of Exhibit K have been implemented and are being complied with in all material respects. 5.9 Existence, Conduct of Business, Properties, Etc. Except as otherwise expressly permitted under this Agreement, (a) maintain and preserve its existence as a Delaware limited partnership and all material rights, privileges and franchises necessary or desirable in the 44 57 normal conduct of its business, (b) perform (to the extent not excused by force majeure events or the nonperformance of the other party and not subject to a good faith dispute) all of its contractual obligations under the Operative Documents to which it is party or by which it is bound, (c) maintain all necessary Permits and licenses, including all Applicable Permits, with respect to its business and the Project and cause all Major Project Participants to maintain all Applicable Third-Party Permits, (d) at or before the time that any Permit becomes an Applicable Permit, obtain such Permit, (e) at or before the time that any Permit required to be obtained by a Major Project Participant becomes an Applicable Third-Party Permit, cause the relevant third party to obtain such Permit and (f) engage only in the business contemplated by the Operative Documents. 5.10 Debt Service Coverage Ratios. As promptly as practicable, but in no event later than ten Banking Days after each Repayment Date, calculate and deliver to Agent the Four-Quarter Average Debt Service Coverage Ratio and the Projected Four-Quarter Average Debt Service Coverage Ratio. Agent shall notify Borrower in writing of any suggested corrections, changes or adjustments which should be made to such Debt Service Coverage Ratio calculations within 20 days after receipt. Borrower shall incorporate all such corrections, changes or adjustment as Agent reasonably deems appropriate. The calculations of Debt Service Coverage Ratios hereunder shall be used in determining the application and distribution of funds from the Accounts pursuant to Section 7.2.1 and Section 7.2.5, the distribution of funds to Borrower pursuant to Section 6.6 and the applicable interest rate for Term Loans under Section 2.1.2(c). 5.11 Indemnification. 5.11.1 Indemnify, defend and hold harmless Agent and each Bank, and in their capacities as such, their respective officers, directors, shareholders, controlling persons, employees, agents and servants (collectively, the "Indemnitees") from and against and reimburse the Indemnitees for: (a) any and all claims, obligations, liabilities, losses, damages, injuries (to person, property, or natural resources), penalties, stamp or other similar taxes, actions, suits, judgments, costs and expenses (including reasonable attorney's fees) of whatever kind or nature, whether or not well founded, meritorious or unmeritorious, demanded, asserted or claimed against any such Indemnitee (collectively, "Subject Claims") in any way relating to, or arising out of or in connection with this Agreement, the other Operative Documents, or the Project, except for claims by Borrower against an Indemnitee; (b) any and all Subject Claims arising in connection with the release or presence of any Hazardous Substances at the Project, whether foreseeable or unforeseeable, including all costs of removal and disposal of such Hazardous Substances, all reasonable costs required to be incurred in (i) determining whether the Project is in compliance and (ii) causing the Project to be in compliance, with all applicable Legal Requirements, all reasonable costs associated with claims for damages to persons or property, and reasonable attorneys' and consultants' fees and court costs; and 45 58 (c) any and all Subject Claims in any way relating to, or arising out of or in connection with any claims, suits, liabilities against Borrower, any Partner or any of their Affiliates. 5.11.2 The foregoing indemnities shall not apply with respect to an Indemnitee, to the extent arising as a result of the gross negligence or willful misconduct of such Indemnitee, but shall continue to apply to other Indemnitees. 5.11.3 The provisions of this Section 5.11 shall survive foreclosure of the Collateral Documents and satisfaction or discharge of Borrower's obligations hereunder, and shall be in addition to any other rights and remedies of the Banks. 5.11.4 In case any action, suit or proceeding shall be brought against any Indemnitee, such Indemnitee shall notify Borrower of the commencement thereof, and Borrower shall be entitled, at its expense, acting through counsel reasonably acceptable to such Indemnitee, to participate in, and, to the extent that Borrower desires, to assume and control the defense thereof. Such Indemnitee shall be entitled, at its expense, to participate in any action, suit or proceeding the defense of which has been assumed by Borrower. Notwithstanding the foregoing, Borrower shall not be entitled to assume and control the defenses of any such action, suit or proceedings if and to the extent that, in the reasonable opinion of such Indemnitee and its counsel, such action, suit or proceeding involves the potential imposition of criminal liability upon such Indemnitee or a conflict of interest between such Indemnitee and Borrower or between such Indemnitee and another Indemnitee (unless such conflict of interest is waived in writing by the affected Indemnitees), and in such event (other than with respect to disputes between such Indemnitee and another Indemnitee) Borrower shall pay the reasonable expenses of such Indemnitee in such defense. 5.11.5 Borrower shall report to such Indemnitee on the status of such action, suit or proceeding as material developments shall occur and from time to time as requested by such Indemnitee (but not more frequently than every sixty (60) days). Borrower shall deliver to such Indemnitee a copy of each document filed or served on any party in such action, suit or proceeding, and each material document which Borrower possesses relating to such action, suit or proceeding. 5.11.6 (a) Notwithstanding Borrower's rights hereunder to control certain actions, suits or proceedings, if any Indemnitee reasonably determines that failure to compromise or settle any Subject Claim made against such Indemnitee is reasonably likely to have an imminent and Material Adverse Effect on such Indemnitee, such Indemnitee shall be entitled to compromise or settle such Subject Claim. (b) Notwithstanding Borrower's rights hereunder to control certain actions, suits or proceedings, if the Required Banks reasonably determine that failure to compromise or settle any Subject Claim made against such Indemnitee is reasonably likely to have an imminent and Material Adverse Effect on Borrower or the Project, such Indemnitee or the 46 59 Required Banks, as the case may be, shall provide Borrower with written notice of a proposed compromise or settlement of such claim specifying in detail the nature and amount of such proposed settlement or compromise. Borrower shall be deemed to have approved such proposed compromise or settlement unless, within thirty (30) days after the date Borrower receives such notice of intended compromise or settlement, Borrower provides such Indemnitee or the Required Banks, as the case may be, with (i) a written legal analysis from counsel reasonably acceptable to such Indemnitee or Required Banks, as the case may be, reasonably concluding that, based on the magnitude of the Subject Claim, the legal basis for such Subject Claim, and/or the cost of defending such Subject Claim, the amount of such proposed settlement or compromise is not within a reasonable range of settlements or compromises for such Subject Claim, and indicating, based on such factors, such counsel's view as to the appropriate amount of a reasonable settlement or compromise for such Subject Claim (the "Settlement Amount"). If the Indemnitee or the Required Banks, as the case may be, receives such legal analysis required by this Section within such thirty (30)-day period, the Indemnitee or the Required Banks, as the case may be, may elect to settle or compromise such Subject Claim and Borrower shall be responsible for the payment of all amounts of such compromise or settlement up to one hundred twenty-five percent (125%) of the Settlement Amount, such Indemnitee shall be responsible for payment of all amounts of such compromise or settlement in excess of such one hundred twenty-five percent (125%) limit and such compromise or settlement shall be binding upon Borrower. If Borrower does not provide such legal analysis within such period, or if such legal analysis is not reasonable, in the reasonable determination of such Indemnitee or the Required Banks, as the case may be, such Indemnitee may settle or compromise such Subject Claim and shall be fully indemnified by Borrower therefor. Such Indemnitee or the Required Banks, as the case may be, shall not otherwise settle or compromise any such Subject Claim other than at its own expense. 5.11.7 Upon payment of any Subject Claim by Borrower pursuant to this Section 5.11 or other similar indemnity provisions contained herein to or on behalf of an Indemnitee, Borrower, without any further action, shall be subrogated to any and all claims that such Indemnitee may have relating thereto, and such Indemnitee shall cooperate with Borrower and give such further assurances as are necessary or advisable to enable Borrower vigorously to pursue such claims. 5.11.8 Any amounts payable by Borrower pursuant to this Section 5.11 shall be regularly payable within 30 days after Borrower receives an invoice for such amounts from any applicable Indemnitee, and if not paid within such 30-day period shall bear interest at the Default Rate. 5.11.9 Notwithstanding anything to the contrary set forth herein, the Borrower shall not, in connection with any one legal proceeding or claim, or separate but related proceedings or claims arising out of the same general allegations or circumstances, in which the interests of the Indemnitees do not materially differ, be liable to the Indemnitees (or any of them) under any of the provisions set forth in this Section 5.11 for the fees and expenses of more than one separate firm of attorneys (which firm shall be selected by the affected Indemnitees, or upon failure to so select, by the Agent). 47 60 5.12 Qualifying Facility. Take or cause to be taken all necessary or appropriate actions (a) so that the Project will be a Qualifying Facility upon the Completion Date and at all times thereafter until all Obligations due the Banks under the Credit Documents have been paid in full unless the Project's failure to be a Qualifying Facility could not reasonably be expected to have a Material Adverse Effect, and (b) to maintain Borrower's and the Project's exemptions from regulation under the FPA (unless failure to so maintain such exemptions could not reasonably be expected to have a Material Adverse Effect) and PUHCA (except regulations specifically applicable to a Qualifying Facility) or, if Calpine or its successor becomes a registered holding company under PUHCA, as a subsidiary of such registered holding company. 5.13 Construction of Project. Cause the Project to be constructed and equipped substantially in accordance with the Plans and Specifications, the Construction Contracts, the other Project Documents, the Project Budget and the Project Schedule as the same may be amended from time to time pursuant to Section 6.13. 5.14 Completion. Achieve Completion and Final Completion in a timely and diligent manner in accordance with the Project Schedule, the Project Budget, the Construction Contracts and the Plans and Specifications as the same may be extended and, in the case of Completion, in no event later than the Construction Loan Maturity Date. 5.15 Operation of Project and Annual Operating Budget. 5.15.1 (a) Keep the Project, or cause the same to be kept, in good operating condition consistent with Prudent Utility Practices, all Applicable Permits (and, if applicable, Applicable Third Party Permits), Legal Requirements and the Operative Documents, and make or cause to be made all repairs (structural and non-structural, extraordinary or ordinary) necessary to keep the Project in such condition; and (b) operate the Project, or cause the same to be operated, in a manner consistent with Prudent Utility Practices and in compliance with the terms of the Power Purchase Documents so as to assure, to the extent reasonably possible, the maximum generation of net revenue for the Project consistent with the Power Purchase Documents. 5.15.2 On or before ninety (90) days prior to the earlier of the anticipated date of Term-Conversion and the Construction Loan Maturity Date, adopt an operating plan and a budget, detailed by month, of anticipated revenues, anticipated expenditures under all Waterfall Levels set forth in Section 7.2.1, and anticipated expenditures from the Major Maintenance Reserve Account, such budget to include debt service, proposed partnership distributions, maintenance, repair and operation expenses (including reasonable allowance for contingencies), Major Maintenance, reserves and all other anticipated O&M Costs for the Project for the period from the anticipated Commercial Operation Date to the conclusion of the first full fiscal year thereafter and, in the case of Major Maintenance in accordance with Section 5.15.3, to the conclusion of the second full fiscal year thereafter ("Annual Operating Budget"). Such Annual Operating Budget shall be subject to the reasonable approval of Agent and the Independent Engineer. No less than ninety (90) days in advance of the beginning of each fiscal year thereafter, Borrower will similarly adopt a draft Annual Operating Budget for the ensuing fiscal year. Copies 48 61 of the draft Annual Operating Budget shall be promptly furnished to Agent for its review and reasonable approval. Failure by Agent to approve or disapprove such draft Annual Operating Budget within ninety (90) days after receipt thereof shall be deemed to be an approval by Agent of such draft. Borrower shall incorporate Agent's suggestions into a final Annual Operating Budget, which, subject to the provisions of the last sentence of this Section 5.15.2, shall be prepared no less than forty-five (45) days in advance of each fiscal year. The O&M Costs in each such Annual Operating Budget which are subject to escalation limitations in the Project Documents shall not, absent extraordinary circumstances, be increased by more than the amounts provided in such Project Documents. Borrower shall continue to operate and maintain the Project, or cause the Project to be operated and maintained, within amounts not to exceed (a) with respect to any Major Budget Category, 105% (on a year-to-date basis) of the amounts budgeted therefor and (b) with respect to any Budget Category, 110% (on a year-to-date basis) of the amounts budgeted therefor, each as set forth in the then current Annual Operating Budget as approved by Agent and the Independent Engineer; provided, however, that so long as Borrower is in compliance with Section 6.25.1(b), the costs for fuel shall not be limited by the Annual Operating Budget (but shall be paid in accordance with Section 7.2). Pending approval of any Annual Operating Budget in accordance with the terms of this Section 5.15.2, Borrower shall continue to operate and maintain the Project, or cause the Project to be operated and maintained, within the Annual Operating Budget then in effect; provided that the amounts specified therein shall be increased by the amounts specified in the Project Documents. 5.15.3 Borrower shall include in each Annual Operating Budget a re-assessment of (a) the anticipated scheduling and probable cost of each item of Major Maintenance and (b) the anticipated amounts which will be on deposit in the Major Maintenance Reserve Account during the applicable fiscal year and the following fiscal year in accordance with the then-applicable Major Maintenance Reserve Requirement. From time to time, to the extent that Agent, in consultation with Borrower and the Independent Engineer, reasonably determines that the anticipated cost of Major Maintenance during the ensuing two fiscal years of Borrower is higher than that reflected in the approved Annual Operating Budget, the amounts specified in the Annual Operating Budget with respect to Major Maintenance may be modified by Agent. The Major Maintenance Reserve Requirement shall be modified accordingly. 5.15.4 Replace the Operator if such Operator is not operating the Project in accordance with the provisions hereof or the O&M Agreement, the Power Purchase Documents, the Lease or any other agreement or instrument under which Borrower holds title, an easement or a leasehold to the Site, the Easements or the Collateral, and such failure could reasonably be expected to have a Material Adverse Effect, upon receipt of notice from Agent (after consultation with the Borrower) to the effect that, in the opinion of the Required Banks and the Independent Engineer, said Operator has failed to perform any material obligations set forth above; provided, however, that the Operator may have 30 days from Borrower's receipt of notice to cure said failure (or to establish to the satisfaction of the Required Banks that a failure does not exist); provided, further, that if such failure cannot be corrected within such 30 days, the Required Banks will not unreasonably withhold their consent to an extension of such time if corrective 49 62 action is promptly instituted by such Operator within the 30-day period and thereafter diligently pursued until the failure is corrected and such extension shall not have a Material Adverse Effect. 5.16 Adjustments to Project Projections. Each year at the time Borrower prepares the Annual Operating Budget, at any time that the Annual Operating Budget is amended, not earlier than ninety (90) days but not later than forty-five (45) days prior to the Extension Determination Date, and also from time to time following an event or circumstance which will materially affect the Base Case Project Projections or the Adjusted Base Case Project Projections, at the reasonable request of Agent, revise the Base Case Project Projections or Adjusted Base Case Project Projections, as the case may be, including the assumptions thereto, if appropriate, to show Borrower's reasonable good faith estimates as of the date of preparation, for each year through the full remaining term of the initial Base Case Project Projections, of anticipated Project Revenues, Project Operating Revenues, O&M Costs (including projected dates of performance of Major Maintenance), Debt Service Coverage Ratios (on an annual basis) payments of principal, interest, fees and other amounts payable under the Credit Documents, payments to fund required reserves, subordinated payments and other appropriate sources and uses of funds, as well as other data and assumptions which Borrower reasonably considers appropriate ("Adjusted Base Case Project Projections"). The Adjusted Base Case Project Projections shall be subject to the same approval procedures as the Annual Operating Budget, as described in Section 5.15.2; provided, however, that notwithstanding the foregoing, in connection with determining whether the Extension Requirements have been satisfied, if: (a) Borrower's proposed Adjusted Base Case Project Projections satisfy clause (c) of the Extension Requirements; and (b) Agent's proposed Adjusted Base Case Project Projections do not satisfy clause (c) of the Extension Requirements; and (c) Borrower's proposed Adjusted Base Case Project Projections project an average of the annual (based on a calendar year) Debt Service Coverage Ratios for each calendar year through the fifteenth (15th) anniversary of Term- Conversion that exceeds Agent's proposed Adjusted Base Case Project Projections' forecast of such average of such annual Debt Service Coverage Ratios by more than .25 for each calendar year through the fifteenth (15th) anniversary of Term- Conversion; and (d) either (i) Borrower's annual Debt Service Coverage Ratio for each calendar year that ended since the immediately preceding Extension Determination Date (or, in the case of the first Extension Determination Date, since the date of Term-Conversion) has equaled or exceeded ninety percent (90%) of the corresponding annual (based on a calendar year) Debt Service Coverage Ratios set forth in the Base Case Project Projections as in effect on the Closing Date or (ii)(A) Borrower's annual Debt Service Coverage Ratio for each calendar year but one that ended since the immediately preceding Extension Determination Date (or, in the case of the first Extension Determination Date, since the date of Term- Conversion) has equaled or exceeded ninety percent (90%) of the 50 63 corresponding annual (based on a calendar year) Debt Service Coverage Ratios set forth in the Base Case Project Projections as in effect on the Closing Date and (B) the average of Borrower's Debt Service Coverage Ratios for each of the calendar years that ended since the immediately preceding Extension Determination Date (or, in the case of the first Extension Determination Date, since the date of Term-Conversion) equal or exceeds the average of the Debt Service Coverage Ratios for such calendar years set forth in the Base Case Project Projections as in effect on the Closing Date; then, the Base Case Project Projections or Adjusted Base Case Project Projections shall be determined using the following procedure: (A) Negotiation. The parties will attempt in good faith to mutually agree on the Adjusted Base Case Project Projections by negotiations. In order to implement such negotiations, each party shall be entitled to give the other party written notice of such dispute (a "Dispute Notice"). Within twenty (20) days after receipt of the Dispute Notice, the receiving party shall submit to the other a written response. Each of the Dispute Notice and response shall include (i) a statement of the position of the party providing such notice or response and a summary of the evidence and arguments supporting its position, and (ii) the name and title of the representative of such party. The representatives shall meet at a mutually acceptable time and place within fifteen (15) days after the date of the response of the receiving party to the Dispute Notice and thereafter as often as they reasonably deem necessary to exchange relevant information and to attempt to agree upon the Adjusted Base Case Project Projections. (B) Arbitration. In the event that the parties are unable to agree upon the Adjusted Base Case Project Projections using the negotiation procedures set forth in clause (A) above within thirty (30) days after delivery of a Dispute Notice, then each of the parties shall be entitled to have the dispute settled by arbitration using the procedures set forth in Exhibit M. 5.17 Preservation of Rights; Further Assurances. 5.17.1 Preserve, protect and defend the rights of Borrower under each and every Project Document, including prosecution of suits to enforce any right of Borrower thereunder and enforcement of any claims with respect thereto; provided, however, that upon the occurrence and during the continuance of an Event of Default if Agent requests that certain actions be taken and Borrower fails to take the requested actions within five Banking Days and such failure reasonably could be expected to have a Material Adverse Effect, Agent may enforce in its own name or in Borrower's name, such rights of Borrower. 5.17.2 From time to time, execute, acknowledge, record, register, deliver and/or file all such notices, statements, instruments and other documents (including any memorandum of lease or other agreement, financing statement, continuation statement, certificate of title or estoppel certificate), relating to the Loans stating the interest and charges then due and any known defaults, and take such other steps as may be necessary or advisable to render fully valid and enforceable under all applicable laws the rights, liens and priorities of the Banks with 51 64 respect to all Collateral and other security from time to time furnished under this Agreement and the other Credit Documents or intended to be so furnished, in each case in such form and at such times as shall be satisfactory to Agent, and pay all fees and expenses (including reasonable attorneys' fees) incident to compliance with this Section 5.17.2. 5.17.3 If Borrower shall at any time acquire any real property or leasehold or other interest in real property not covered by the Deed of Trust, promptly upon such acquisition (or on the Closing Date if such acquisition occurred prior thereto) execute, deliver and record a supplement to the Deed of Trust, satisfactory in form and substance to Agent, subjecting the real property or leasehold or other interests to the lien and security interest created by the Deed of Trust. If requested by Agent, Borrower shall obtain an appropriate endorsement or supplement to the Title Policy insuring the Lien of the Banks in such additional property, subject only to Permitted Liens and other exceptions to title approved by the Agent. 5.17.4 Perform, upon the request of Agent, such reasonable acts as may be necessary to carry out the intent of this Agreement and the other Credit Documents. 5.18 Project Equity. 5.18.1 On the Closing Date, deliver or cause to be delivered to the Depositary Agent cash equal to $53,112,500 (the "Base Equity"). The Depositary Agent shall deposit the Base Equity into the Equity Account at the Depositary Agent's New York office pursuant to the Depositary Agreement. From time to time following the Closing Date, Borrower shall have the right to request that Agent cause the Depositary Agent to transfer amounts from the Equity Account to the Construction Account to pay Project Costs then due as described in a Drawdown Certificate, dated the date of the proposed transfer and signed by Borrower. Upon the satisfaction of the conditions set forth in Sections 3.2 (other than Section 3.2.6) and 3.4, Agent shall cause the Depositary Agent to so transfer such amounts and such amounts shall be applied in accordance with Section 7.1. 5.18.2 At such time, if ever, as there remain no Available Construction Funds other than Additional Borrower Equity and there remain Project Costs to be incurred or paid to achieve Final Completion, then Borrower shall deposit or cause to be deposited with Agent, in cash, equity funds in an amount equal to all such further Project Costs, such deposit to be made on or before the date such Project Costs are due to be paid ("Additional Borrower Equity"). All such Additional Borrower Equity proceeds shall be deposited in the Construction Account established pursuant to Section 7.1 hereof and applied, after satisfaction of the conditions set forth in Section 3.2, to pay Project Costs. 5.18.3 Unless an Event of Default has occurred and is continuing, have the right at any time prior to Term-Conversion to replace cash in the Equity Account with Subordinated Debt in amount up to fifty percent (50%) of the total Base Equity, or, provided Borrower delivers an Equity Commitment Guaranty, with an Equity Support Letter of Credit in an amount up to one hundred percent (100%) of the Base Equity. 52 65 5.18.4 If Borrower elects to replace such cash with Subordinated Debt, such Subordinated Debt shall be applied as follows: (a) first, to Borrower in an amount equal to the lesser of the amount of such Subordinated Debt and the amount of Base Equity previously applied to pay Project Costs and (b) second, for deposit into the Equity Account, any remaining Subordinated Debt to replace cash therein, in which case an amount in the Equity Account equal to the principal amount of Subordinated Debt deposited into the Equity Account shall promptly be delivered by the Depositary Agent to Borrower. 5.18.5 If Borrower elects to replace such cash with an Equity Support Letter of Credit, upon Agent's receipt of the Equity Support Letter of Credit, receipt of the Equity Commitment Guaranty and receipt of an executed Notice of Construction Loan Borrowing delivered in accordance with Section 2.1.1, the Banks shall make a Construction Loan in accordance with Section 2.1.5 in an amount equal to the lesser of (x) the Project Costs previously paid with cash representing Base Equity, and (y) the stated amount of the Equity Support Letter of Credit. The proceeds of such Construction Loan shall be paid to Borrower. If the stated amount of the Equity Support Letter of Credit is greater than the amount of the Project Costs previously paid with such cash, on such date of receipt, Agent also shall instruct the Depositary Agent to promptly withdraw an amount from the Equity Account equal to the excess of such stated amount over such amount of Project Costs previously paid and deliver such excess to Borrower. 5.18.6 In the event Borrower replaces Base Equity with an Equity Support Letter of Credit, pay Agent when due any interest accruing on Construction Loans that is not reflected in the Project Budget delivered to Agent on the Closing Date and that has accrued as a result of such replacement. 5.18.7 If an Event of Default shall have occurred prior to Term-Conversion, transfer all remaining amounts in the Equity Account to the Construction Account and promptly pay to Agent an amount equal to the undrawn stated amount of any Equity Support Letter of Credit. If Borrower fails to so pay or cause to be paid such amount, Agent shall have the right to make a draw upon the Equity Support Letter of Credit in an amount equal to such undrawn amount. Agent shall deposit the funds so received from or on behalf of Borrower into the Construction Account for application in accordance with Section 7.1. 5.18.8 Immediately prior to Term-Conversion, Borrower and Agent will take the following actions. First, Agent shall calculate, applying the respective formulas set forth in the Construction Contracts, the total amount of "performance" liquidated damages that would be payable under such Construction Contracts if such contracts had no individual limitations on liability for such performance liquidated damages obligations (the "Maximum TheoreticalDamages"). Next, Agent shall calculate the difference between (x) the lesser of (A) the Maximum Theoretical Damages and (B) $20,000,000 and (y) the aggregate amount of "performance" liquidated damages and "excess delay" liquidated damages under the Construction Contracts applied pursuant to Section 7.13.1 and 7.1.4, respectively, to prepay Construction Loans (the "Actual Paid Performance Damages"). 53 66 5.18.9 If the Actual Paid Performance Damages equals or exceeds the lesser of (A) the Maximum Theoretical Damages and (B) $20,000,000, then Borrower shall have no further obligation regarding the payment of Project Costs and Agent shall perform the calculation set forth in Section 5.18.11. 5.18.10 If the Actual Paid Performance Damages is less than the lesser of (A) the Maximum Theoretical Damages and (B) $20,000,000, then, if the Final Project Cost is less than the Budgeted Project Cost, Agent shall adjust the Final Project Cost by increasing the Final Project Cost by the difference between (i) the lesser of (A) the Maximum Theoretical Damages and (B) $20,000,000 and (ii) the Actual Paid Performance Damages. Agent shall then use the lesser of (x) such adjusted Final Project Cost and (y) the Budgeted Project Cost in making the calculations set forth in Section 5.18.11. If the Actual Paid Performance Damages are less than the lesser of (A) the Maximum Theoretical Damages and (B) $20,000,000 and if the Final Project Cost, as adjusted pursuant to this Section 5.18.10 is equal to or greater than the Budgeted Project Cost, then Borrower shall pay or cause to be paid to Agent an amount equal to the difference between (i) the lesser of (A) the Maximum Theoretical Damages and (B) $20,000,000 and (ii) the Actual Paid Performance Damages and such amount shall be applied by Agent to the prepayment of Construction Loans. 5.18.11 Next, Agent shall compare (i) the sum of cash as Base Equity, Subordinated Debt and draws under any Equity Support Letter of Credit previously applied to pay Project Costs to (ii) thirty-five percent (35%) of the Final Project Cost, as adjusted if necessary pursuant to Section 5.18.10. In the event that such sum exceeds thirty-five percent (35%) of the adjusted Final Project Cost (the difference between such amounts, the "Excess Equity Amount"), Borrower shall have the right to request a Construction Loan in accordance with Section 2.1.1, and the Banks shall make a Construction Loan to Borrower in accordance with Section 2.1.5, in an amount equal to the Excess Equity Amount. In the event such sum is less than thirty-five percent (35%) of the adjusted Final Project Cost (the difference between such amounts, the "Shortfall Amount"), Borrower shall pay or cause to be paid to Agent, in immediately available funds, an amount equal to the Shortfall Amount. If Borrower fails to so pay or cause to be paid the Shortfall Amount, Agent shall have the right to withdraw from the Equity Account and/or make a draw upon the Equity Support Letter of Credit in an aggregate amount equal to the Shortfall Amount. Agent shall deposit the funds so received from or on behalf of Borrower into the Construction Account for application in accordance with Section 7.1. 5.18.12 Upon Term-Conversion, pay or cause to be paid to any holders of any Subordinated Debt, in immediately available funds, such amounts as are necessary so that the amount of Subordinated Debt outstanding immediately after Term-Conversion does not exceed seventeen and one-half percent (17 1/2%) of the Final Project Cost. 5.18.13 Notwithstanding anything to the contrary in this Agreement, in no event shall the outstanding Term Loans at Term-Conversion exceed sixty-five (65%) of the lesser of the Final Project Cost and the Budgeted Project Cost. 54 67 5.19 Maintenance of Insurance. Borrower shall, without cost to the Banks, maintain or cause to be maintained on its behalf in effect at all times the types of insurance required pursuant to Exhibit K, in the amounts and on the terms and conditions specified therein, with insurance companies rated "A-" or better, with a minimum size rating of "VIII," by Best's Insurance Guide and Key Ratings, (or an equivalent rating by another nationally recognized insurance rating agency of similar standing if Best's Insurance Guide and Key Ratings shall no longer be published) or other insurance companies of recognized responsibility satisfactory to Agent. 5.20 Taxes, Other Government Charges and Utility Charges. Pay, or cause to be paid, as and when due and prior to delinquency, all taxes, assessments and governmental charges of any kind that may at any time be lawfully assessed or levied against or with respect to Borrower or the Project, including sales and use taxes and real estate taxes, all utility and other charges incurred in the operation, maintenance, use, occupancy and upkeep of the Project, and all assessments and charges lawfully made by any Governmental Authority for public improvements that may be secured by a lien on the Project. In furtherance of the foregoing, Borrower shall engage a qualified Person or Persons to confirm Borrower's compliance with all tax laws and regulations and to implement any required programs and procedures to ensure continued compliance with the same. Borrower may contest in good faith any such taxes, assessments and other charges and, in such event, may permit the taxes, assessments or other charges so contested to remain unpaid during any period, including appeals, when Borrower is in good faith contesting the same, so long as (a) reserves reasonably satisfactory to Agent have been established in an amount sufficient to pay any such taxes, assessments or other charges, accrued interest thereon and potential penalties or other costs relating thereto, or other adequate provision for the payment thereof shall have been made, (b) enforcement of the contested tax, assessment or other charge is effectively stayed for the entire duration of such contest, and (c) any tax, assessment or other charge determined to be due, together with any interest or penalties thereon, is immediately paid after resolution of such contest. 5.21 Event of Eminent Domain. If an Event of Eminent Domain shall occur with respect to any Collateral, (a) promptly upon discovery or receipt of notice of any such occurrence, provide written notice of either to Agent, (b) diligently pursue all its rights to compensation against the relevant Governmental Authority in respect of such Event of Eminent Domain, (c) not, without the written consent of Agent and the Majority Banks, which consent shall not be unreasonably withheld, compromise or settle any claim against such Governmental Authority, (d) pay or apply all Eminent Domain Proceeds in accordance with Section 7.10. Borrower consents to the participation of Agent in any eminent domain proceedings, and Borrower shall from time to time deliver to Agent all documents and instruments requested by it to permit such participation. 5.22 Interest Rate Protection. 5.22.1 Interest Rate Agreements. On or prior to the sixtieth (60th) day following the Closing Date, enter into with Agent (or an Affiliate thereof) one or more Hedge 55 68 Transactions, with an aggregate notional amount equal to Seventy-Five Million Dollars ($75,000,000) as more particularly described in and in accordance with the methodology set forth in that certain letter agreement, dated of even date herewith, between Agent and Borrower. 5.22.2 Hedge Breaking Fees. To the extent required pursuant to the terms of the Hedge Transactions, pay all reasonable costs, fees and expenses incurred by the Borrower in connection with any unwinding, breach or termination of such Hedge Transactions ("Hedge Breaking Fees"), all as calculated pursuant to the applicable Interest Rate Agreements. 5.22.3 Security. Each Interest Rate Agreement provided by Agent (or an Affiliate thereof) hereunder, including all Hedge Transactions thereunder entered into in accordance with the terms of this Agreement and all Hedge Breaking Fees shall be and are hereby secured by the Collateral Documents, pari passu with the Loans. No Interest Rate Agreement (and Hedge Transactions thereunder) not provided by Agent (or an Affiliate thereof) hereunder may be secured by the Collateral Documents. The parties hereto agree that, for purposes of any sharing of Collateral under the Collateral Documents, Agent or any Affiliate thereof, in its capacity as a counterparty or intermediary to the Interest Rate Agreements shall be deemed to have made a Loan to Borrower in an amount equal to the unpaid amount of any Hedge Breaking Fees owed by Borrower to Agent or such Affiliate, under any such Hedge Transaction on the date that a "Early Termination Date" (as defined in the applicable Interest Rate Agreement) occurs. For purposes of any such Collateral sharing, and for purposes of voting on matters under this Agreement to the extent specified in the definition of "Proportionate Share," Agent or any of such Affiliates shall be deemed a Bank under the Collateral Documents to the extent of such Loan. 5.22.4 Bank Participation. At the election of Agent, the Banks may participate in the Interest Rate Agreements and Hedge Transactions thereunder in proportion to their respective Proportionate Shares by means of a risk sharing agreement in form and substance satisfactory to such Banks, provided, that if any such Bank's Lending office is in the State of New York, such Bank may designate another branch to enter into such risk sharing agreement. 5.23 Alternative Thermal Host Action Plan. Upon receipt by Borrower of an HCC Shutdown Notice, promptly deliver to Agent, for Agent's review and approval, a proposed plan of action (as approved pursuant to this Section 5.23, the "Alternative Thermal Host Action Plan") to procure a new steam host. The Alternative Thermal Host Action Plan shall set forth in reasonable detail the various alternatives considered by Borrower, the anticipated cost to implement each such alternative and the time frame within which each such alternative reasonably can be completed. Agent shall have thirty (30) days following receipt of such proposed plan to approve or disapprove the proposed plan. Failure to disapprove such plan within such thirty (30)-day period shall be deemed as Agent's approval of such plan. If Agent disapproves such plan, Borrower and Agent shall promptly meet and negotiate in good faith to achieve a mutually acceptable plan. Upon such agreement, Borrower shall promptly implement the Alternative Thermal Host Action Plan. 56 69 5.24 Performance Bonds. Cause Westinghouse and Prime Contractor to deliver the bonds required under the respective Construction Contracts within forty-five (45) days after the Closing Date. 5.25 Power Marketing. 5.25.1 Replacement of Power Marketer. If any of the following events shall occur: (a) an Event of Default under Section 8.1.7(b) of this Agreement as a result of a breach or default by Power Marketer under a Project Document or Consent, (b) a breach, default or failure to perform by Power Marketer under any provision in any contract or agreement between Power Marketer and any other Person (other than Borrower) if such breach, default or failure to perform (i) materially interferes with or impairs Borrower's ability to sell energy and/or capacity generated by the Project and collect its revenues from such sales and (ii) is not cured within the time periods provided in such contracts or agreements (not to exceed ninety (90) days), or (c) the Project's Four-Quarter Average Debt Service Coverage Ratio calculated at the end of any four (4) consecutive calendar quarters is less than 2.00 to 1.00, then, if requested by Agent after consultation with Borrower and consideration of the facts and circumstances affecting the Project's performance and results, terminate all contracts and agreements with the then Power Marketer, including all Power Marketing Services Agreements, Power Marketing Brokering Agreements and ERCOT Power Purchase Agreements with the Power Marketer, and replace the Power Marketer with another Power Marketer that is satisfactory to Agent; provided, however, that any such termination shall be prospective only and shall not affect Borrower's obligations to supply energy and/or capacity with respect to transactions entered into or obligations incurred prior to the effective date of such termination. 5.25.2 Requests for Proposals. From and after the Closing and until the earlier to occur of (a) the fourth anniversary of Term-Conversion and (b) Borrower having entered into Bidding Threshold Power Sales Agreements covering, in the aggregate, at least 75 MW of "firm" energy and/or capacity, unless Agent otherwise consents, which consent shall not be unreasonably withheld, submit or cause Power Marketer to submit on its behalf, bona fide, good faith bids on all requests for proposal or similar offers which can then be supplied in whole or in part from the Project to enter into Bidding Threshold Power Sales Agreements and/or Pasadena Unit Power Sales Agreements meeting the requirements of a Bidding Threshold Power Sales Agreement. 57 70 5.25.3 Firm Sales to HL&P. In the event that, by April 15 (or such later date as Agent may agree) next preceding the anticipated Commercial Operation Date, there exists a shortfall between the aggregate amount of firm energy and/or capacity covered by all Distribution Threshold Power Sales Agreements entered into by Borrower and 75 MW at such time, then Borrower shall, on or before the May 1 next preceding the anticipated Commercial Operation Date, elect the "Firm Energy Option" under the HL&P Power Purchase Agreement and schedule at least the amount of such shortfall for the periods beginning on the June 1 next preceding the anticipated Commercial Operation Date and each June 1 thereafter, unless Agent otherwise consents (until such time as such shortfall has been eliminated or the fourth anniversary of Term-Conversion has occurred, whichever occurs earlier) and ending on the following May 1; provided, however, that such election may schedule zero firm energy for the period from the June 1 immediately preceding the anticipated Commercial Operation Date through the end of the month following the anticipated Commercial Operation Date. 5.25.4 Arrangements with Power Marketer. (a) Promptly after the Closing Date enter into (i) a power marketing brokering agreement with Power Marketer in form and substance reasonably acceptable to Agent (the "Power Marketing Brokering Agreement"), (ii) a power marketing services agreement with Power Marketer in form and substance reasonably acceptable to Agent (the "Power Marketing Services Agreement", and (iii) the Power Marketing Security Agreement. (b) Prior to entering into any ERCOT Power Purchase Agreements or selling any energy or capacity to or through Power Marketer, cause Power Marketer to (i) establish a depository account (the "Power Marketing Depository Account") with a depository agent satisfactory to Agent and (ii) grant to Borrower a first priority perfected security interest in such account and all funds and instruments deposited therein. (c) In connection with the establishment of the Power Marketing Depository Account as provided in Section 5.25.4(b) above and at all times thereafter, cause Power Marketer to maintain a minimum balance in the Power Marketing Depository Account equal to the Power Marketing Minimum Balance; provided, however, that: (A) During the ninety (90) days immediately following the first day on which Power Marketer sells, pursuant to a System Power Sales Agreement, energy and/or capacity generated and/or made available by the Project, Power Marketer may, in lieu of maintaining the Power Marketing Minimum Balance in the Power Marketing Depository Account, cause Calpine to guarantee to Borrower payment by Power Marketer of the shortfall, existing from time to time during such ninety (90) day period, between the amount of funds on deposit in the Power Marketing Depositary Account and the Power Marketing Minimum Balance. Such guarantee shall be in substantially the form of Exhibit D-2B. 58 71 (B) At any time, Power Marketer may, in lieu of maintaining the Power Marketing Minimum Balance in the Power Marketing Depositary Account, cause a Person that satisfies the Power Marketing Guaranty Requirements to guarantee to Borrower payment by Power Marketer of the amounts owed to Borrower under all Pasadena/CPSC System Supported Contracts, existing from time to time; provided, however, that such Person's liability under such guaranty shall be limited to an amount equal to the Power Marketing Minimum Balance in effect while such guaranty is in effect. Such guaranty shall be in substantially the form of Exhibit D-2B. If Agent shall, at any time, but not more frequently than once a year, reasonably believe that such guarantor is no longer rated at least BBB+ or the equivalent thereof by S&P or at least Baa1 or the equivalent thereof by Moody's, then Agent may request that such guarantor receive an indicative rating from such rating agencies. If in connection with such requested rating, or for any other reason, such guarantor shall at any time cease to satisfy any of the requirements set forth in the definition of "Power Marketing Guaranty Requirements," then Power Marketer shall promptly, but in no event more than fifteen (15) days after the failure of any of such requirements to be satisfied, restore the balance in the Power Marketing Depository Account to the Power Marketing Minimum Balance then in effect. (d) Cause Power Marketer to instruct all purchasers under Pasadena Unit Power Sales Agreements to make all payments due thereunder to Power Marketer directly into the Revenue Account. (e) Cause Power Marketer to (i) promptly upon execution thereof, collaterally assign to Borrower all of Power Marketer's rights and interests to all Pasadena Unit Power Sales Agreements and (ii) obtain consents to such collateral assignments from the purchasers thereunder as described in Section 6.25. 5.26 Auxiliary Boilers Contractor. In the event that ABCO, as the Contractor under the Auxiliary Boilers Purchase Contract, fails to achieve any of the milestones set forth on the "Contract Schedule" (as defined in the Auxiliary Boilers Purchase Contract) on or prior to seventy-five (75) days after the scheduled date for achieving such milestone, then upon request of Agent, as promptly as practicable terminate the Auxiliary Boilers Purchase Contract and engage a replacement contractor to supply to the Project auxiliary boilers conforming to the Project's plan and specification. 5.27 Construction Management Plan. On or before sixty (60) days after the Closing, adopt a draft construction plan (the "Construction Plan") setting forth a schedule, detailed by month, of the anticipated milestones to be accomplished in connection with the construction of the Project and describing the interfacing procedures among the various Contractors. The Construction Plan shall be subject to the reasonable approval of Agent. Failure by Agent to approve or disapprove the draft Construction Plan within thirty (30) days after receipt thereof shall be deemed to be an approval by Agent of such draft. Borrower shall incorporate Agent's reasonable suggestions into a final Construction Plan. 59 72 5.28 Operating Agreements. On or before January 31, 1998, (a) enter into with HL&P, or another entity providing "control area" services reasonably acceptable to Agent, an agreement whereby HL&P or such other entity will provide standby station electric service to the Project and (b) enter into, or cause Power Marketer to enter into on behalf of Borrower, an agreement with HL&P, or another entity providing "control area" services reasonably acceptable to Agent, whereby HL&P or such other entity will provide ancillary services, wheeling and transmission services to the Project, each in form and substance satisfactory to Agent. 5.29 Stand-Alone Easements. On or before thirty (30) days after the earliest to occur of the events specified in clauses (a), (b) and (c) of Section 3.3.6 of the Lease, make an election under Section 3.3.6 of the Lease to use the "Stand-Alone Easements" (as defined in the Lease) and thereby convert them into "Operating Easements" (as defined in the Lease). 5.30 Extension of Lease, Lease of Expansion Property. In the event that the "Initial Term" (as defined in the Lease) of the Lease is not extended pursuant to Section 4.2 or 4.3 of the Lease, and unless Phillips exercises the "Project Purchase Option" (as defined in the Lease), exercise its option as provided in Section 4.4 of the Lease to extend the Initial Term for the "Partnership Extension Term" (as defined in the Lease). If directed by Agent, Borrower shall exercise its option to lease the Expansion Property. 5.31 License from Port Authority. As promptly as practicable after the Closing Date, and in any event within ninety (90) days thereafter, deliver to Agent a license executed by the Port Authority in favor of Borrower relating to certain transmission lines for Project, and \a consent to assignment thereto executed by the Port Authority in favor of Agent, each in form and substance reasonably satisfactory to Agent. 5.32 Phillips License from Port Authority. As promptly as practicable after the Closing Date, and in any event within one hundred twenty (120) days thereafter, cause Phillips to amend that certain Oil, Gas, Etc. Pipeline License (Railroad Right-of-Way), dated April 1, 1990, between the Port and Phillips 66 Company, predecessor in interest to Phillips, to enable Borrower and its Contractors to construct such improvements in the area described in such License as are necessary for Borrower to comply with the Lease. 5.33 Conversion. Cause the conditions set forth in Section 3.3 (other than Section 3.3.4) to occur as promptly as practicable after Completion has occurred. 5.34 Option Title Insurance. To the extent permitted under Texas law, within sixty (60) days following the Closing Date, cause the Title Insurer to reissue the Title Policy or issue an endorsement to the Title Policy insuring the "Expansion Property" and the "QF Property" (as such terms are defined in the Lease) (or the validity of the options with respect thereto) to the same extent as the remainder of the Site. 60 73 ARTICLE 6 - NEGATIVE COVENANTS Borrower covenants and agrees that so long as this Agreement is in effect, it will not: 6.1 Contingent Liabilities. Except as provided in this Agreement, become liable as a surety, guarantor, accommodation endorser or otherwise, for or upon the obligation of any other Person; provided, however, that this Section 6.1 shall not be deemed to prohibit (a) the acquisition of goods, supplies or merchandise in the normal course of business or normal trade credit; (b) the endorsement of negotiable instruments received in the normal course of its business; or (c) contingent liabilities required under any Applicable Permit or Operative Document. 6.2 Limitations on Liens. Create, assume or suffer to exist any Lien, securing a charge or obligation on the Project or on any of the Collateral, real or personal, whether now owned or hereafter acquired, except Permitted Liens. 6.3 Indebtedness. Incur, create, assume or permit to exist any Debt except Permitted Debt. 6.4 Sale or Lease of Assets. Sell, lease, assign, transfer or otherwise dispose of assets, whether now owned or hereafter acquired (a) except in the ordinary course of its business as contemplated by the Operative Documents or (b) except to the extent that such property is worn out or no longer useful or usable in connection with the operation of the Project, and in each case at fair market value. 6.5 Changes. Change the nature of its business or expand its business beyond the business contemplated in the Operative Documents, including without limitation purchasing gas with the intention of reselling such gas. 6.6 Distributions. Directly or indirectly, make or declare any distribution (in cash, property or obligation) on, or other payment on account of, any interest in Borrower (including any transfers of any tax benefits): (a) until each of the conditions to the initial distribution set forth in Section 3.5 has been satisfied; and (b) unless (i) on a Calculation Date; (ii) Term-Conversion has occurred; (iii) no Event of Default or Inchoate Default has occurred and is continuing; (iv) the Four-Quarter Average Debt Service Coverage Ratio calculated as of the Repayment Date to which such Calculation Date relates is equal to or greater than 1.50 to 1.00; (v) the Projected Four-Quarter Average Debt Service Coverage Ratio calculated as of the Repayment Date to which such Calculation Date relates is equal to or greater than 1.50 to 1.00; (vi) such payment would not trigger an Inchoate Default or Event of Default and (vii) such distribution is made at Waterfall Level 11 or from the Distribution Suspense Account. 61 74 6.7 Investments. Make any investments (whether by purchase of stocks, bonds, notes or other securities, loan, extension of credit, advance or otherwise) other than Permitted Investments. 6.8 Transactions With Affiliates. Except for (a) the Equity Documents, the Project Documents and the transactions permitted thereby, (b) arms-length transactions in the ordinary course of business not to exceed in the aggregate $100,000 per calendar year, and (c) as otherwise expressly permitted by this Agreement and the other Credit Documents, directly or indirectly enter into any transaction or series of transactions with or for the benefit of an Affiliate without the prior written approval of Agent. 6.9 Regulations. Directly or indirectly apply any part of the proceeds of any Loan or other revenues to the purchasing or carrying of any margin stock within the meaning of Regulations G, T, U or X of the Federal Reserve Board, or any regulations, interpretations or rulings thereunder. 6.10 ERISA. Establish, maintain, contribute to or become obligated to contribute to any ERISA Plan or suffer or permit any member of the Controlled Group to do so. 6.11 Partnerships, etc. Become a general or limited partner in any partnership or a joint venturer in any joint venture or create and hold stock in any subsidiary. 6.12 Dissolution. Liquidate or dissolve, or sell or lease or otherwise transfer or dispose of all or any substantial part of its property, assets or business or combine, merge or consolidate with or into any other entity, or change its legal form, or purchase or otherwise acquire all or substantially all of the assets of any Person. 6.13 Amendments; Change Orders; Completion. 6.13.1 Directly or indirectly, amend, modify, supplement or waive, or permit or consent to the amendment, modification, supplement or waiver (including, without limitation, any waiver (or refund) of liquidated damages payable by any Contractor under any Construction Contract) of, any of the provisions of, or give any consent under, (a) any of the Project Documents without first submitting to Agent a copy of such proposed amendment, modification, supplement or waiver and if, in the reasonable judgment of the Agent, the amendment, modification, supplement or waiver could reasonably be expected to have a Material Adverse Effect, obtaining the prior written consent of the Majority Banks thereto, which consent shall not be unreasonably withheld or delayed or (b) the Energy Sales Agreement, the HL&P Power Purchase Agreement, the Lease or the Facility Services Agreement without obtaining the prior written consent of the Required Banks thereto or (c) the Power Marketing Services Agreement or the Power Marketing Brokering Agreement without obtaining the prior written consent of the Majority Banks thereto. 62 75 6.13.2 Without the prior written consent of Agent direct or consent to any change order under any of the Construction Contracts if such change order: (a) will, individually or together with all previous change orders, increase or decrease the Project Costs by more than $750,000 in the aggregate for the Project (exclusive of increases reimbursed by insurance awards, condemnation awards or contractual damage awards); (b) will materially delay Completion, or in any event is reasonably likely to delay Completion beyond the Construction Loan Maturity Date; (c) is reasonably likely to permit or result in any adverse modification or impair the enforceability of any warranty under any Construction Contract or the O&M Agreement; (d) is reasonably likely, in the opinion of the Independent Engineer, to impair or reduce the maximum capacity, value, efficiency, utility, output, performance, reliability, durability or availability of the Project, or increase O&M Costs, or decrease Project Revenues, in each case after accounting for other favorable or unfavorable circumstances which may have affected the Project; (e) is not permitted by any Project Document or would (i) diminish any obligation of any Major Project Participant or (ii) increase any obligation of Borrower thereunder; (f) is likely, in the reasonable opinion of Agent, to present a significant risk of the revocation or material modification of any Applicable Permit or Third Party Permit or jeopardize the Project's status as a Qualifying Facility; (g) may cause the Project not to comply or lessen the Project's ability to comply with Legal Requirements; or (h) relates to a Construction Contract between Borrower and an Affiliate of Borrower. 6.13.3 Declare "Completion," "Final Construction Completion", "Final Project Completion" "Mechanical Completion", (as such terms are defined in the Construction Contracts) of the Project under the Construction Contracts or declare that the "Acceptance Date" has occurred or approve the successful completion of the "Acceptance Tests" (as such terms are defined in the Construction Contracts) without the written approval of Agent, which approval, if given, shall not be unreasonably delayed, acting in consultation with the Independent Engineer. 6.13.4 Conduct any Performance Tests under and as defined in the Power Island Purchase Contract without the provision by Phillips of Off-Gas (as defined in the Facility 63 76 Services Agreement) in the quantities and qualities provided for in the Facility Services Agreement. 6.13.5 Agree on the Punch List without the written approval of Agent acting in consultation with the Independent Engineer. 6.13.6 Approve of the hiring by any Contractor of any Major Subcontractor not previously approved by Agent acting in consultation with the Independent Engineer. 6.13.7 Unless compliance hereof is waived in writing by Agent and the Majority Banks, direct or consent to any change order under the O&M Agreement if such aggregate. 6.13.8 Consent, without Agent's prior approval, to (a) any action taken by any Contractor to conform the equipment or services provided by such Contractor to the intellectual property rights of others if such action could reasonably be expected to materially and adversely affect Borrower's continued use of the Project or (b) to the settlement by any Contractor of any claim or proceeding which could reasonably be expected to adversely affect Borrower's rights. 6.13.9 Direct any Contractor to suspend the work being performed under any Construction Contract without Agent's prior consent. 6.13.10 Agent shall use good faith efforts to respond to each change order request as soon as possible and in all events within 30 days. No change order shall be deemed approved by Agent until expressly approved. 6.14 Compliance with Operative Documents. Do or permit (to the extent within its control) to be done in, upon or about the Project or any part thereof, or do or permit (to the extent within its control) to be done any act under the Operative Documents, or omit or refrain from any act under the Operative Documents, where such act done or permitted to be done, or such omission of or refraining from action, could reasonably be expected to have a Material Adverse Effect. 6.15 Name and Location; Fiscal Year. Unless waived in writing by Agent, change its name, the location of its principal place of business or its federal employer identification number without notice to Agent at least 45 days prior to such change, or change its fiscal year without Agent's consent. 6.16 Use of Project Site. Use, or permit to be used, the Site for any purpose other than for the construction, operation and maintenance of the Project as contemplated by the Operative Documents, without the prior written approval of Agent. 64 77 6.17 Assignment. Assign its rights hereunder or under any of the Operative Documents to any Person except as permitted under this Agreement and the other Credit Documents. 6.18 Abandonment of Project. Voluntarily cease or abandon the development, construction or operation of the Project. 6.19 Hazardous Substance. Release, emit or discharge into the environment any Hazardous Substances in violation of any Hazardous Substance Laws, Legal Requirements or Applicable Permits. 6.20 Additional Project Documents. Enter into or become a party to any Additional Project Document, except (a) with the prior written consent of Agent acting at the direction of the Majority Banks, and (b) if required by the Agent, upon delivery to the Agent of a Consent from such third party in substantially the form of Exhibit E-1; provided that the consent of the Agent and the Majority Banks shall not be required for Borrower to enter into Additional Project Documents (i) with Persons other than Affiliates of Borrower and (ii) pursuant to which Borrower will incur obligations or liabilities with a value of not more than $100,000 individually, or $200,000 in the aggregate, per year. 6.21 Project Budget Amendments. Directly or indirectly, amend, modify, allocate, re-allocate or supplement or permit or consent to the amendment, modification, allocation, re-allocation or supplement or, any of the provisions of the Project Budget, except that Borrower may: 6.21.1 allocate up to $1,000,000 in the aggregate of Unrestricted Owner's Contingency to any Budget Categories (other than any line items pertaining to a transaction with an Affiliate); 6.21.2 after obtaining the prior written consent of the Agent, allocate all or any portion of Unrestricted Owner's Contingency to any Budget Categories (other than any line items pertaining to a transaction with an Affiliate); 6.21.3 upon completion in full of the work or other activity to which any particular Budget Category relates, reallocate any amount remaining in such Budget Category to one or more other Budget Categories (other than any line items pertaining to a transaction with an Affiliate); 6.21.4 after obtaining the prior written consent of Agent, re-allocate to the Unrestricted Owner's Contingency amounts previously allocated to any Budget Category pursuant to Section 6.21.1 above, to the extent that Borrower reasonably determines that such amounts are no longer required to be allocated to such Budget Category; 65 78 6.21.5 after obtaining the prior written consent of Agent and the Majority Banks, allocate all or any portion of the Restricted Owner's Contingency to such Budget Categories as Borrower considers appropriate; and 6.21.6 make such other allocations and re-allocations with respect to the Project Budget which are approved in writing by Agent and the Majority Banks prior thereto. All allocations and re-allocations made in accordance with the terms hereof shall be prepared and computed using the same methodology and, upon each such allocation, re-allocation and restoration, (a) the Project Budget shall be deemed amended to reflect such allocation, re-allocation or restoration upon notice by Borrower to Agent of such allocation, re-allocation or restoration, and (b) Borrower shall promptly prepare and distribute to the Agent an appropriately revised Project Budget. Any increases to the Budget Category entitled Interest During Construction shall be made first from Unrestricted Owner's Contingency and, to the extent that the Unrestricted Owner's Contingency has been utilized in full, from Restricted Owner's Contingency, subject in all cases to the approval rights contained in this Section 6.21. 6.22 Loan Proceeds; Project Revenues. Use, pay, transfer, distribute or dispose of any Loan proceeds in any manner or for any purposes except as provided in Section 5.1.1 or of any Project Revenues in any manner or for any Purposes except as provided in Sections 5.1.2 and 7.2. 6.23 Commercial Operation Date. Declare or cause to occur the Commercial Operation Date under the Energy Sales Agreement without Agent's prior written consent, which consent may be withheld in Agent's sole discretion. 6.24 Suspension of Performance Under Gas Sales Agreement. Direct Fuel Supplier to suspend performance under the Gas Sales Agreement without Agent's prior written consent, which consent shall not be unreasonably withheld so long as Borrower has entered into or concurrently enters into alternative fuel supply contracts or other arrangements (i) which provide for all of the Project's fuel requirements, (ii) which provide for subordination of 10% of the cost of fuel in substantially the same manner as provided in Sections 7.2.1 and 7.2.3 and contain substantially the same provisions as are set forth in Section 8 of the Gas Sales Agreement or make alternative arrangements reasonably satisfactory to Agent which, based on the Adjusted Base Case Project Projections, would result in projected annual Debt Service Coverage Ratios that are equal to or greater than the projected annual Debt Service Coverage Ratios that would be achieved with such subordination, and (iii) are with fuel suppliers reasonably acceptable to Agent. 6.25 Power Marketing. 6.25.1 Power Sales Agreements. Without Agent's prior written consent, enter into an ERCOT Power Purchase Agreement, or allow Power Marketer to enter into any Power Marketer Power Sales Agreement which uses services from the Project which: 66 79 (a) except as otherwise permitted or required in Sections 5.25.2 and 5.25.3 of this Agreement, is not intended to maximize, in the long-term, the net revenues and profitability of the Project over the Term or results in a fluctuation in net revenues per kWh under such agreement of more than ten percent (10%) from the net revenues per kWh generated under such agreement in either the preceding or following year. (b) in the case of such agreements for 5 MW or more individually, or 20 MW or more in the aggregate, has a term of three years or more and whose variable pricing component is not indexed to the price of gas that Borrower pays under the Gas Sales Agreement; (c) in the case of such agreements of a term that exceeds one year, results when aggregated with existing ERCOT Power Purchase Agreements and Power Marketer Power Sales Agreements of a term that exceeds one year, on an annual basis over the life of such agreement, in per kWh gross revenues to the Project that are less than the per kWh gross revenues to the Project set forth in the Base Case Project Projections as in effect on the Closing Date; (d) in the case of agreements for the sale of firm energy of a term that exceed one year, are not with parties (i) listed in Appendix A to Borrower's Power Marketing Plan, (ii) whose credit rating is equal to or better than BB, as rated by S&P (or an equivalent rating), (iii) whose obligations under such agreements are guaranteed in form and substance acceptable to Agent by a party whose credit rating is equal to or greater than BB, as rated by S&P (or an equivalent rating) or (iv) whose obligations under such agreements are secured by a letter of credit, in form and substance acceptable to Agent and issued by a financial institution reasonably acceptable to Agent or other security reasonably acceptable to Agent. (e) provide for payment by the purchaser thereunder for energy or capacity more than sixty- five (65) days after the energy or capacity was delivered or made available, as the case may be; (f) do not (i) explicitly preclude any liability by Borrower for consequential, special and indirect damages including loss of revenues and (ii) if such agreement is entered into with Power Marketer, require Power Marketer to indemnify Borrower from and against any such potential liability sought to be imposed by third parties; or (g) require Borrower to provide collateral security to a third party for performance of Borrower's obligations under such agreement; provided, however, that nothing herein shall restrict or limit the right of any Affiliates of Borrower (other than the Partners) to provide any such collateral security. 6.25.2 Capacity Limitations. Sell any electrical capacity from the Project (a) pursuant to an agreement which does not permit the buyer of such capacity to request the delivery of energy in the amount of such capacity or (b) pursuant to any agreement unless such 67 80 capacity is supported by an equal amount of available uncommitted energy from the Project; provided, however, that nothing herein shall restrict Borrower's right or ability to sell interruptible or non-firm energy regardless of the amount of capacity sold or energy committed from the Project. 6.25.3 Power Marketing Affiliates. Permit Calpine or any of its Affiliates, individually or together with any other Person or Persons, to form or establish any power marketing entities (other than CPSC) that are qualified for or otherwise participate or operate in ERCOT; provided, however, that Calpine or CPSC may form a subsidiary to participate in ERCOT in which case such subsidiary shall be the only Affiliate of Borrower which is qualified for or otherwise participates or operates in ERCOT. 6.25.4 Collateral Assignment. Without Agent's consent, enter into any ERCOT Power Purchase Agreements which do not contain an acknowledgment and a consent to the collateral assignment of such agreements to the Banks which acknowledgment and consent shall be in a form reasonably acceptable to Agent. 6.26 Expansion Property. Without Agent's consent, exercise its option to lease the Expansion Property (as defined in the Lease) under Section 6.2 of the Lease or fail to enter into an extension or renewal of any of the Phillips Documents. ARTICLE 7 - APPLICATION OF FUNDS 7.1 Construction Account. 7.1.1 Establishment of Account. On or prior to the Closing Date, Borrower and Agent shall establish the Construction Account at the Depositary Agent's New York office. There shall be deposited into the Construction Account the proceeds of all Construction Loans made hereunder, all Project Operating Revenues earned prior to Term-Conversion (which shall be available for the payment of Project Costs pursuant to the terms of this Agreement), and all amounts required to be deposited in the Construction Account pursuant to Section 5.18. 7.1.2 Disbursements from Construction Account. Amounts shall be disbursed from the Construction Account from time to time subject to the satisfaction (or waiver) of the provisions of Section 3.2 and this Section 7.1. Borrower shall have the right to cause Agent to disburse amounts from the Construction Account to the accounts of each of the Contractors for amounts due and owing to such Contractors under the Construction Contracts, or to any other materialmen, subcontractors, the Agent or any other Person in payment of amounts due and owing to such parties from Borrower in accordance with a duly completed Drawdown Certificate. Borrower agrees that Agent may transfer any or all of a Construction Loan and other sums in the Construction Account directly into the account of any Contractor for amounts due and owing to such Contractor under the relevant Construction Contract, or any other materialmen or subcontractors in payment of amounts due and owing to such parties from Borrower without further authorization from Borrower; provided, however, that if Borrower has notified Agent that 68 81 it is contesting a claim for payment by a Contractor or a subcontractor or materialmen in accordance with the requirements of this Agreement and the definition of "Permitted Liens," Agent will not, except as described in the proviso to the next sentence, be entitled to pay any amount being contested. Borrower hereby constitutes and appoints Agent its true and lawful attorney-in-fact to make such direct payments and this power of attorney shall be deemed to be a power coupled with an interest and shall be irrevocable; provided that, except upon the occurrence and continuation of an Event of Default, Agent shall not exercise its rights under this power of attorney except to make payments (a) as directed by Borrower or (b) which Agent reasonably believes, if not promptly made, are reasonably likely to have a Material Adverse Effect. No further direction or authorization from Borrower shall be necessary to warrant or permit Agent to make such direct Construction Loans in accordance with the foregoing sentence, and all such direct Construction Loans shall satisfy pro tanto the obligations of Agent and the Banks hereunder, and shall be secured by the Collateral Documents as fully as if made directly to Borrower, regardless of the disposition thereof by any Contractor, or any other subcontractors, materialmen, laborers or other parties. 7.1.3 Rights of Agent. Agent will have the right, but not the obligation, to (a) supply any missing endorsements of Borrower, refuse any item for deposit except as required by the terms of this Agreement, and pay and charge items payable by Agent pursuant to Section 7.1.2 in any order convenient to Agent; (b) refuse to honor any check drawn on the Construction Account which is not consistent with this Agreement, or which has been improperly filled out or endorsed; (c) create and charge to the Construction Account overdrafts and all applicable charges; (d) remit copies of checks and other items with statements instead of the originals which may be retained by Agent; and (e) pay fees, interest and other charges owing by Borrower as provided herein. 7.1.4 Proceeds of the Final Drawing. Upon Term-Conversion, after deposit of all proceeds of the Final Drawing, if any, in the Construction Account, all amounts remaining in the Construction Account (if any) shall be applied as follows: (a) An amount sufficient for completion of the Punch List, and payment of other Project Costs through Final Completion, determined by Borrower and approved by Agent in consultation with the Independent Engineer, shall be retained in the Construction Account for application in accordance with Section 7.1.5; and (b) Any amounts representing delay damages under any Construction Contracts shall be applied to the prepayment of Construction Loans to the extent that performance liquidated damages under any Construction Contracts would have become payable under such Construction Contracts but for a limitation on the amount of such liquidated damages under the relevant Construction Contract. (c) All other amounts in the Construction Account shall be transferred (i) first, to the Emissions Offsets Reserve Account until the balance therein equals the EORA Minimum Balance, (ii) second, to the Fuel Supply Reserve Account until the balance 69 82 therein equals the FSRA Minimum Balance, and (iii) third, to the Debt Service Reserve Account in an amount equal to the DSRA Minimum Balance. To the extent excess amounts remain in the Construction Account after effecting the applications in the immediately preceding sentence, such excess funds shall be deposited in the Revenue Account and applied in accordance with Section 7.2.1. 7.1.5 Disbursements Following Term-Conversion. From and after Term-Conversion until Final Completion, amounts in the Construction Account shall be disbursed from time to time (but no more frequently than twice per month) to Borrower in accordance with this Section 7.1 after satisfaction (or waiver) of such conditions set forth in Section 3.2 as Agent in its reasonable discretion requires to be satisfied, to pay for completion of the Punch List and other items necessary to achieve Final Completion. Following achievement of Final Completion, amounts, if any, remaining in the Construction Account shall be transferred to the Revenue Account for application in accordance with the terms of Section 7.2.1. 7.2 Revenue Account. 7.2.1 Establishment of Account; Priority of Payments. On or prior to Term-Conversion, Borrower and Agent shall establish the Revenue Account at the Depositary Agent's New York office. There shall be deposited into the Revenue Account all Project Operating Revenues earned on or after Term-Conversion. So long as no Event of Default has occurred and is continuing, or will occur upon giving effect to the application described below, funds in the Revenue Account shall be applied at the following times and in the following order of priority by disbursement or internal account transfer by the Depositary Agent, (a) on Agent's volition with respect to Waterfall Levels 1 through 8 or if Agent reasonably believes that failure to make any such payment could reasonably be expected to have a Material Adverse Effect, or (b) pursuant to Borrower's disbursement requisition, directly to the Person entitled thereto, in each case at the following times, commencing on the date of Term-Conversion, and in the following order of priority (each, a "Waterfall Level"): (1) on the last Banking Day of each month, provided that the Agent has timely received and approved a Disbursement Requisition delivered pursuant to Section 7.2.2, to the Operating Account for payment of Senior O&M Costs in an amount determined pursuant to Section 7.2.2, below; (2) on the last Banking Day of each month, to the Accrual Sub-Account as required by Section 7.9; (3) from time to time in the priority indicated, as and when due under the terms of this Agreement, to the payment of all fees, costs, charges and any other amounts due and payable to Agent and the Banks in connection with this Agreement and the other Credit Documents, other than Commitment Fees and amounts described in another Waterfall Level; 70 83 (4) from time to time, on a pro rata basis among the Banks, to the payment of interest on the Term Loans, Commitment Fees and to payments due by Borrower pursuant to the Interest Rate Agreements (and the Hedge Transactions thereunder); (5) on Repayment Dates, on a pro rata basis among the Banks, to (a) the payment of principal due on the Term Loans in accordance with Exhibit I and (b) other principal amounts due hereunder; (6) on Repayment Dates, to the Major Maintenance Reserve Account as required by Section 7.3; (7) on Repayment Dates, to the Debt Service Reserve Account as required by Section 7.6 (the balance remaining in the Revenue Account after the application of the foregoing payments set forth in Waterfall Levels 1 through 7 is referred to herein as the "Available Cash"); (8) on Repayment Dates or Calculation Dates, as the case may be, and only in respect of amounts which were on deposit in the Revenue Account on the Repayment Date to which such Calculation Date relates, to Mandatory Prepayment of the Loans and other Obligations to the extent required under Section 7.2.5; (9) on Calculation Dates, and only in respect of amounts which were on deposit in the Revenue Account on the Repayment Date to which such Calculation Date relates, provided that Agent has timely received and approved a Disbursement Requisition delivered pursuant to Section 7.2.3, to the payment of Subordinated Fuel Costs in an amount determined pursuant to Section 7.2.3 below; (10) on Calculation Dates, and only in respect of amounts which were on deposit in the Revenue Account on the Repayment Date to which such Calculation Date relates, provided that Agent has timely received and approved a Disbursement Requisition delivered pursuant to Section 7.2.4, to the payment of Subordinated O&M Costs in an amount determined pursuant to Section 7.2.4 below; and (11) on Calculation Dates, and only in respect of amounts which were on deposit in the Revenue Account on the Repayment Date to which such Calculation Date relates, (i) in the event that the conditions to distributions set forth in Sections 6.6(a) and 6.6(b) have been satisfied, for payment to Borrower or distribution by Borrower as it may determine in its sole discretion, (ii) in the event that the conditions to distributions set forth in Section 6.6(b) are not satisfied, to the Distribution Suspense Account for application as provided in Section 7.10, and (iii) in the event that the conditions to distributions set forth in Section 6.6(b) are satisfied but those set forth in Section 6.6(a) are not satisfied, to the Initial Distribution Suspense Account for application as provided in Section 7.10. 71 84 7.2.2 O&M Costs. On or before the fifth Banking Day prior to the last Banking Day of each month during which Borrower desires to transfer sums to the Operating Account for the payment of Senior O&M Costs, Borrower shall submit to the Agent a certificate in the form of Exhibit C-7 detailing the amounts to be so transferred ("Disbursement Requisition"), which amounts shall not exceed the Senior O&M Costs which have become, or are anticipated to become, due and payable during such month, excluding Major Maintenance costs funded from the Major Maintenance Reserve Account. Agent shall review such Disbursement Requisition within five Banking Days following receipt thereof, and shall transfer the amounts specified therein to the Operating Account for application in accordance with Waterfall Level 1 to the extent that such expenditures are in accordance with the terms of the Annual Operating Budget and this Agreement, as such budget may be exceeded pursuant to the terms hereof. Notwithstanding anything in this Section 7.2.2 to the contrary, the transfers to, and expenditures from, the Revenue Account for Senior O&M Costs (other than fuel costs as provided in Section 5.15.2 and O&M Costs incurred in an emergency) payable pursuant to Waterfall Level 1 (a) with respect to any Major Budget Category, shall not without Agent's consent exceed on an annual year-to-date basis 105% of the amounts specified in such Major Budget Category and (b) with respect to any Budget Category, shall not without Agent's consent exceed on an annual year-to-date basis 110% of the amounts specified in such Budget Category, in each case, as set forth in the then-applicable Annual Operating Budget (net of amounts set forth therein for Subordinated O&M Costs and Subordinated Fuel Costs). Notwithstanding anything to the contrary in this Agreement, in no event shall the "Annual Base Fee" (as defined in the O&M Agreement) be greater than the amount specified therefor in the then-applicable Annual Operating Budget. Borrower shall promptly pay all Senior O&M Costs in excess of the amounts permitted under the preceding sentence from amounts, if any, of Available Cash, or by contribution of additional equity funds; provided, however, that if Agent subsequently approves a variation in such Annual Operating Budget which would have allowed the payment of such excess Senior O&M Costs, Borrower shall be entitled to recover any such Senior O&M Costs previously paid by the contribution of additional equity funds from Project Operating Revenues at Waterfall Level 1. Each Disbursement Requisition shall reflect a reduction in the Senior O&M Costs for which Borrower requests that funds be transferred to the Operating Account during such month for any amounts which remain, or are expected to remain, in the Operating Account at the end of any month as a result of a previous Disbursement Requisition. 7.2.3 Subordinated Fuel Costs. On or before the fifth Banking Day prior to each Repayment Date on which Borrower desires to make payments of Subordinated Fuel Costs, Borrower shall include in the Disbursement Requisition submitted pursuant to Section 7.2.2 on such date the amounts to be so paid, which amounts shall not exceed the Subordinated Fuel Costs which have become due and payable. Agent shall review such Disbursement Requisition within five Banking Days following receipt thereof, and, to the extent funds exist in the Revenue Account after application of amounts in such account to Waterfall Levels 1 through 8, make payment of the Subordinated Fuel Costs specified therein to the designated payee thereof to the extent that such expenditures are in accordance with the terms of the Annual Operating Budget. 72 85 7.2.4 Subordinated O&M Costs. On or before the fifth Banking Day prior to each Repayment Date on which Borrower desires to make payments of Subordinated O&M Costs, Borrower shall include in the Disbursement Requisition submitted pursuant to Section 7.2.2 on such date the amounts to be so paid, which amounts shall not exceed the Subordinated O&M Costs which have become due and payable. Agent shall review such Disbursement Requisition within five Banking Days following receipt thereof, and, to the extent funds exist in the Revenue Account after application of amounts in such account to Waterfall Levels 1 through 9, make payment of the Subordinated O&M Costs specified therein to the designated payee thereof to the extent that such expenditures are in accordance with the terms of the Annual Operating Budget. 7.2.5 Mandatory Prepayment. (a) If, on any Repayment Date, an Event of Default shall exist, Borrower shall use all Available Cash on such Repayment Date (i) to prepay the Loans in inverse order of maturity and (ii) upon repayment in full of the Loans, to repay all other Obligations of Borrower to the Banks, as designated by Agent and the Required Banks. (b) If, on any Extension Determination Date, the Extension Requirements are not met, Borrower shall, on each Repayment Date thereafter until the Extension Requirements have been satisfied, use all Available Cash on such Repayment Dates (i) to prepay the Loans in inverse order of maturity and (ii) upon repayment in full of the Loans, to repay all other Obligations of Borrower to the Banks, as designated by Agent and the Required Banks. (c) Subject to Sections 7.2.5(a) and 7.2.5(b), if on any Calculation Date during the Term Period the Four-Quarter Average Debt Service Coverage Ratio for the Repayment Date to which such Calculation Date relates shall be less than 1.75 to 1.00, Borrower shall use 50% of the Available Cash on such Calculation Date (i) to prepay the Loans in inverse order of maturity and (ii) upon repayment in full of the Loans, to repay all other Obligations of Borrower to the Banks, as designated by Agent and the Required Banks. (d) Subject to Sections 7.2.5(a) and 7.2.5(b), if on any Calculation Date during the Term Period the Four-Quarter Average Debt Service Coverage Ratio for the Repayment Date to which such Calculation Date relates shall be less than 2.00 to 1.00 but shall exceed or equal 1.75 to 1.00, Borrower shall use fifteen (15%) of the Available Cash on such Calculation Date (i) to prepay the Loans in inverse order of maturity and (ii) upon repayment in full of the Loans, to repay all other Obligations of Borrower to the Banks, as designated by Agent and the Required Banks. (e) Nothing in this Section 7.2.5 shall limit in any manner the rights and remedies of Agent and the Banks upon and during the continuation of an Event of Default under this Agreement. 7.3 Major Maintenance Reserve Account. 73 86 7.3.1 Establishment of Account. On or prior to Term-Conversion, Borrower and Agent shall establish the Major Maintenance Reserve Account at the Depositary Agent's New York office. 7.3.2 Funding. On each Repayment Date (other than Term-Conversion), Borrower shall cause all amounts then in the Revenue Account in excess of the amounts applied through Waterfall Level 5 to be deposited into the Major Maintenance Reserve Account, up to an amount equal to the sum of (a) the Major Maintenance Reserve Requirement plus (b) an amount (without duplication) up to the aggregate amount, if any, by which Borrower failed to fund the Major Maintenance Reserve Account on any prior Repayment Date as required under this Section 7.3.2. 7.3.3 Withdrawals. Borrower shall be entitled to submit a duly executed Reserve Account Disbursement Requisition in substantially the form of Exhibit C-8 (a "Reserve Account Disbursement Requisition") in order to withdraw amounts from the Major Maintenance Reserve Account to pay all fees, costs, charges and other amounts due in connection with any Major Maintenance in accordance with the projected Major Maintenance expenses contained in the Annual Operating Budget, or as otherwise approved by the Agent and the Independent Engineer. 7.3.4 Earnings. All earnings on monies in the Major Maintenance Reserve Account shall accrue to the Major Maintenance Reserve Account up to the amount required under Section 7.3.2 and shall thereafter be deposited in the Reserve Account. 7.4 Emissions Offsets Reserve Account. 7.4.1 Establishment of Account. On or prior to Term-Conversion, Borrower and Agent shall establish the Emissions Offsets Reserve Account at the Depositary Agent's New York office. On the date of Term-Conversion, Borrower shall deposit or cause to be deposited into the Emissions Offsets Reserve Account an amount equal to Eight Hundred Thousand Dollars ($800,000) which amount shall be obtained, to the extent funds are available, through a transfer from the Construction Account as provided in Section 7.1.4. 7.4.2 Withdrawals. Borrower shall be entitled to submit a duly executed Reserve Account Disbursement Requisition in substantially the form of Exhibit C-8 in order to withdraw amounts from the Emissions Offsets Reserve Account to pay all fees, costs, charges and other amounts incurred in connection with the acquisition of any required Emissions Offsets Credits. 7.4.3 Earnings. All earnings on monies in the Emissions Offsets Reserve Account shall accrue to the Emissions Offsets Reserve Account. 7.4.4 Letters of Credit. In lieu of depositing cash in the Emissions Offsets Reserve Account pursuant to Section 7.4.1, Borrower may provide an unconditional, irrevocable 74 87 direct-pay letter of credit (the "Emissions Offsets Reserve Letter of Credit") issued in a stated amount equal to the EORA Minimum Balance for the account of Borrower by a financial institution rated at least A or the equivalent thereof by S&P or at least A2 or the equivalent thereof by Moody's and otherwise approved by Agent, naming the Agent on behalf of the Banks as the beneficiary, and containing terms and provisions satisfactory to Agent in its sole discretion. Upon delivery of the Emissions Offsets Reserve Letter of Credit to Agent, all cash in the Emissions Offsets Reserve Account shall be released to Borrower. In addition to and without limiting the foregoing, the Emissions Offsets Reserve Letter of Credit (a) shall have an initial expiration date of at least one (1) year after the date of issuance and (b) shall not be secured by any of the Collateral. Further, the fees and reimbursement obligations in respect of the Emissions Offsets Reserve Letter of Credit shall not be recourse to Borrower or the Project. On each anniversary of the issuance of the Emissions Offsets Reserve Letter of Credit, Borrower shall cause the stated amount of the Emissions Offsets Reserve Letter of Credit to be increased to the EORA Minimum Balance as of such date. If no agreement for a renewal or replacement of the Emissions Offsets Reserve Letter of Credit has been made thirty (30) days prior to the expiration of the Emissions Offsets Reserve Letter of Credit, the Agent may draw the entire undrawn amount of the Emissions Offsets Reserve Letter of Credit and deposit such drawing in the Emissions Offsets Reserve Account or Borrower shall deposit cash in the Emissions Offsets Reserve Account in the amount of the Emissions Offsets Reserve Letter of Credit. Fees, costs, expenses and reimbursement obligations relating to any Emissions Offsets Reserve Letter of Credit shall be paid only out of any funds distributed to Borrower under Waterfall Level 11. 7.4.5 Release of Funds. Funds in the Emissions Offsets Reserve Account shall be transferred to the Revenue Account for application as provided in Section 7.2.1 upon the earlier of the following to occur: (a) Borrower has demonstrated to the reasonable satisfaction of the Majority Banks that Borrower owns, free and clear of any Liens, Emissions Offsets Credits, in final and nonappealable form, in compliance with all Legal Requirements and to the satisfaction of the Texas Natural Resource Conservation Commission (the "TNRCC") to enable the Project to be operated at 240 MW based on the availability factor set forth in the Base Case Project Projections; or (b) Borrower has demonstrated to the reasonable satisfaction of the Majority Banks (including an opinion of counsel) that Borrower is no longer subject to any Legal Requirements to obtain such Emissions Offsets Credits because (i) either (A) there is a final, nonappealable redesignation under the federal Clean Air Act of 1970, as amended in 1977 and 1990, 42 U.S.C. Section 7401 et seq., of the air quality control region within which the Project is located from a non- attainment area with respect to ozone to an attainment or unclassifiable area or (B) there is a final, nonappealable repeal, modification or permanent suspension of all Governmental Rules which require the Emission Offsets Credits, and (ii) there neither exists nor has there been proposed any other Legal Requirement that could reasonably be expected to require the Project to obtain such Emissions Offsets Credits. If, at such time as funds in the Emissions Offsets Reserve Account would be transferred to the Revenue Account pursuant to this Section 7.4.5, Borrower has provided Agent with an Emissions Offsets Reserve Letter of Credit, then, at such time, Agent shall draw the entire undrawn stated amount of the Emissions Offsets Reserve Letter of Credit and deposit the proceeds of such draw into the Revenue Account for application pursuant to Section 7.2.1. 75 88 7.5 Fuel Supply Reserve Account. 7.5.1 Establishment of Account. On or prior to Term-Conversion, Borrower and Agent shall establish the Fuel Supply Reserve Account at the Depositary Agent's New York office. On the date of Term-Conversion, Borrower shall deposit or cause to be deposited into the Fuel Supply Reserve Account an amount equal to the FSRA Minimum Balance, which amount shall be obtained, to the extent funds are available, through a transfer from the Construction Account as provided in Section 7.1.4. 7.5.2 Withdrawals. Amounts on deposit in the Fuel Supply Reserve Account shall be withdrawn as Agent and Borrower may agree. 7.5.3 Earnings. All earnings on monies in the Fuel Supply Reserve Account shall accrue to the Fuel Supply Reserve Account. 7.5.4 Letters of Credit. In lieu of depositing cash in the Fuel Supply Reserve Account pursuant to Section 7.5.1, Borrower may provide an unconditional, irrevocable direct-pay letter of credit (the "Fuel Supply Reserve Letter of Credit") issued in a stated amount equal to FSRA Minimum Balance for the account of Borrower by a financial institution rated at least A or the equivalent thereof by S&P or at least A2 or the equivalent thereof by Moody's and otherwise approved by Agent, naming the Agent on behalf of the Banks as the beneficiary, and containing terms and provisions satisfactory to Agent in its sole discretion. Upon delivery of the Fuel Supply Reserve Letter of Credit to Agent, all cash in the Fuel Supply Reserve Account shall be released to Borrower. In addition to and without limiting the foregoing, the Fuel Supply Reserve Letter of Credit (a) shall have an initial expiration date of at least one (1) year after the date of issuance and (b) shall not be secured by any of the Collateral. Further, the fees and reimbursement obligations in respect of the Fuel Supply Reserve Letter of Credit shall not be recourse to Borrower or the Project. On each anniversary of the issuance of the Fuel Supply Reserve Letter of Credit, Borrower shall cause the stated amount of the Fuel Supply Reserve Letter of Credit to be increased to the FSRA Minimum Balance as of such date. If no agreement for a renewal or replacement of the Fuel Supply Reserve Letter of Credit has been made thirty (30) days prior to the expiration of the Fuel Supply Reserve Letter of Credit, Agent may draw the entire undrawn amount of the Fuel Supply Reserve Letter of Credit and deposit such drawing in the Fuel Supply Reserve Account or Borrower shall deposit cash in the Fuel Supply Reserve Account in the amount of the Fuel Supply Reserve Letter of Credit. Fees, costs, expenses and reimbursement obligations relating to any Fuel Supply Reserve Letter of Credit shall be paid only out of any funds distributed to Borrower under Waterfall Level 11. 7.5.5 Release of Funds. Agent shall cause any funds remaining in the Fuel Supply Reserve Account on the tenth (10th) anniversary of the Commercial Operation Date promptly to be transferred to the Revenue Account and applied pursuant to Section 7.2.1. If, at such time as funds in the Fuel Supply Reserve Account would be transferred to the Revenue Account pursuant to this Section 7.5.5, Borrower has provided Agent with a Fuel Supply Reserve Letter of Credit, then, at such time, Agent shall draw the entire undrawn stated amount of the 76 89 Fuel Supply Reserve Letter of Credit and deposit the proceeds of such draw into the Revenue Account for application pursuant to Section 7.2.1. 7.6 Debt Service Reserve Account. 7.6.1 Establishment of Account. On or prior to Term-Conversion, Borrower and Agent shall establish the Debt Service Reserve Account at the Depositary Agent's New York office. On the date of Term-Conversion, Borrower shall deposit or cause to be deposited into the Debt Service Reserve Account an amount equal to the DSRA Minimum Balance, which amount shall be obtained, to the extent funds are available, through a transfer from the Construction Account as provided in Section 7.1.4. 7.6.2 Funding. After Term-Conversion, on each Repayment Date, if the balance in the Debt Service Reserve Account is not equal to or greater than the DSRA Minimum Balance, Borrower shall cause all amounts then in the Revenue Account on the applicable Repayment Date in excess of the amounts applied through Waterfall Level 6 to be deposited into the Debt Service Reserve Account until the amount deposited therein equals the DSRA Minimum Balance. 7.6.3 Replenishment of Account. In the event that on any Repayment Date the balance in the Debt Service Reserve Account is less than the DSRA Minimum Balance, then on each Repayment Date thereafter until the balance in the Debt Service Reserve Account is equal to the DSRA Minimum Balance, Borrower shall cause all amounts then in the Revenue Account on the applicable Repayment Date in excess of the amounts applied through Waterfall Level 6 to be deposited into the Debt Service Reserve Account. 7.6.4 Withdrawals. Agent shall withdraw amounts from the Debt Service Reserve Account to pay (a) fees, costs, charges and other amounts due to Agent and the Banks and to pay amounts of principal and interest due under the Loans in the event that amounts in the Revenue Account are insufficient therefor, and (b) if approved by the Majority Banks in their reasonable discretion, O&M Costs. 7.6.5 Earnings. All earnings on monies in the Debt Service Reserve Account shall accrue to the Debt Service Reserve Account until such time as the Debt Service Reserve Account has on deposit therein an amount equal to the DSRA Minimum Balance, whereupon all amounts in the Debt Service Reserve Account in excess of such amount shall be deposited in the Revenue Account as Project Operating Revenues on a monthly basis. 7.6.6 Letters of Credit. In lieu of depositing cash in the Debt Service Reserve Account pursuant to Section 7.6.1, 7.6.2 and 7.6.3, Borrower may provide an unconditional, irrevocable direct-pay letter of credit (the "Debt Service Reserve Letter of Credit") issued in a face amount equal from time to time to or, to the extent cash is deposited, less than, the DSRA Minimum Balance for the account of Borrower by a financial institution rated at least A or the equivalent thereof by S&P or at least A2 or the equivalent thereof by Moody's and 77 90 otherwise approved by Agent, naming the Agent on behalf of the Banks as the beneficiary, and containing terms and provisions satisfactory to Agent in its sole discretion. To the extent the stated amount of the Debt Service Reserve Letter of Credit plus amounts on deposit in the Debt Service Reserve Account exceed the DSRA Minimum Balance, cash in the Debt Service Reserve Account shall be released to Borrower. In addition to and without limiting the foregoing, the Debt Service Reserve Letter of Credit (a) shall have an initial expiration date of at least one (1) year after the date of issuance and (b) shall not be secured by any of the Collateral. Further, the fees and reimbursement obligations in respect of the Debt Service Reserve Letter of Credit shall not be recourse to Borrower or the Project. If no agreement for a renewal or replacement of the Debt Service Reserve Letter of Credit has been made thirty (30) days prior to the expiration of the Debt Service Reserve Letter of Credit, the Agent may draw the entire undrawn amount of the Debt Service Reserve Letter of Credit and deposit such drawing in the Debt Service Reserve Account or Borrower shall deposit cash in the Debt Service Reserve Account in the amount of the Debt Service Reserve Letter of Credit. Fees, costs, expenses and reimbursement obligations relating to any Debt Service Reserve Letter of Credit shall be paid only out of any funds distributed to Borrower under Waterfall Level 11. 7.7 Operating Account. 7.7.1 Establishment of Account. On or prior to Term-Conversion, Borrower and Agent shall establish at Union Bank of California an account entitled "Pasadena Project -- Operating Account" ("Operating Account"). 7.7.2 Funding. From time to time, in accordance with the provisions of Waterfall Levels 1 and 10, Borrower shall cause to be transferred to the Operating Account the amounts specified in Sections 7.2.1 and 7.2.2. 7.7.3 Withdrawals. Borrower shall be entitled to withdraw amounts from the Operating Account to pay Senior O&M Costs which have become due and payable in accordance with the Disbursement Requisition in which such Senior O&M Costs were described. Amounts transferred to the Operating Account which are not, for any reason, applied to payment of Senior O&M Costs in accordance with the Disbursement Requisition pursuant to which such amounts were transferred, shall be retained in the Operating Account for application to the following month's Senior O&M Costs in accordance with Section 7.2.2. 7.8 Loss Proceeds Account. On or prior to the Closing Date, Borrower and Agent shall establish at the Depository Agent's New York Office the Loss Proceeds Account. All Insurance Proceeds, Eminent Domain Proceeds and damage payments described in Section 7.13 shall be deposited in the Loss Proceeds Account and applied (a) as specified in Sections 7.11 through 7.13 and (b) if no such application is specified, to the prepayment of the Loans in inverse order of maturity, and thereafter to payment of all other Obligations of Borrower. 7.9 Accrual Sub-Account. 78 91 7.9.1 Establishment of Sub-Account. On or before Term-Conversion, Borrower shall establish the Accrual Sub-Account at the Depositary Agent's New York office. On the last Banking Day of each month following Term-Conversion, Borrower shall deposit or cause to be deposited into the Accrual Sub-Account from amounts available for application thereto, under the priority of payments set forth in Section 7.2.2, (a) the amount of any Senior O&M Costs, which, in accordance with the then applicable Annual Operating Budget, are to be accrued, and not paid, during the following month and (b) a prudent and sufficient level of working capital and reserves for the Project, taking into account projected levels of Project Revenues, O&M Costs and amounts on deposit in the Revenue Account for a period of approximately forty-five (45) days to pay any other amounts which will become due and payable during the ensuing Repayment Period. 7.9.2 Withdrawals. Amounts from the Accrual Sub-Account may be transferred from time to time at Borrower's request to the Revenue Account for payment of accrued Senior O&M Costs and other costs and expenses with respect to which amounts were deposited in the Accrual Sub-Account in accordance with Section 7.2.1. Amounts on deposit in the Accrual Sub-Account which were deposited in anticipation of accrued obligations which for any reason did not become payable when so scheduled to be paid shall be released into the Revenue Account on the Repayment Date immediately following the date upon which the anticipated accrued liability was expected to become due and payable. 7.9.3 Earnings. Investment income from Permitted Investments of amounts on deposit in the Accrual Sub- Account shall be deemed Project Operating Revenues for purposes of calculating Debt Service Coverage Ratios, and shall be transferred to the Revenue Account on a monthly basis. 7.10 Distribution Suspense Account; Initial Distribution Suspense Account. 7.10.1 Establishment of Account. On or prior to Term-Conversion, Borrower and Agent shall establish the Distribution Suspense Account and the Initial Distribution Suspense Account at the Depositary Agent's New York office. 7.10.2 Funding. From time to time, Agent shall cause to be transferred to the Distribution Suspense Account and the Initial Distribution Suspense Account, the amounts specified in Waterfall Level 11. 7.10.3 Withdrawals. (a) Distribution Suspense Account. (i) Until the funds in the Distribution Suspense Account have been applied as provided in Section 7.10.3(a)(ii), Agent shall withdraw amounts from the Distribution Suspense Account to pay all fees, charges, costs and other amounts specified in Waterfall Levels 1 through 8, in such order, to the extent that amounts in the Revenue Account are insufficient therefor. 79 92 (ii) Upon the satisfaction, on four consecutive Calculation Dates, of each of the conditions to distribution set forth in Section 6.6(b), all funds in the Distribution Suspense Account shall be paid to, or as directed by, Borrower as it may determine in its sole discretion; provided, however, that in the event that all such conditions have not been so satisfied, as of the fourth Repayment Date occurring after the deposit of funds in the Distribution Suspense Account, then such funds remaining in the Distribution Suspense Account (after any withdrawals made pursuant to Section 7.10.3(a)(i)) shall be used (x) to prepay the Loans in inverse order of maturity and (y) upon repayment in full of the Loans, to repay all other Obligations of Borrower to the Banks, as designated by Agent and the Required Banks. For purposes of determining whether four Repayment Dates have occurred since the deposit of any funds in the Distribution Suspense Account, all withdrawals made pursuant to Section 7.10.3(a)(i) shall be deemed to have been made on a first-in first-out basis. (b) Initial Distribution Suspense Account. (i) Until the funds in the Initial Distribution Suspense Account have been applied as provided in Section 7.10.3(b)(ii), Agent shall, upon Borrower's request, withdraw funds from the Initial Distribution Suspense Account to pay Subordinated Fuel Costs to the extent funds in the Revenue Account are insufficient therefor. (ii) Upon satisfaction of each of the conditions to distribution set forth in Section 6.6(a), all funds in the Initial Distribution Suspense Account shall be paid to, or as directed by, Borrower as it may determine in its sole discretion. 7.11 Application of Insurance Proceeds. 7.11.1 General. Borrower shall notify Agent of any casualty and keep Agent timely apprised of insurance claim proceedings. All amounts and proceeds (including instruments) in respect of the proceeds of any insurance policy required to be maintained by Borrower hereunder ("Insurance Proceeds") shall be applied as provided in this Section 7.11. All Insurance Proceeds shall be paid by the insurers directly to Agent (as loss payee or additional insured as provided in Exhibit K). If any Insurance Proceeds are paid directly to Borrower or Calpine with respect to Project by any insurer, such Insurance Proceeds shall be received only in trust for Agent, shall be segregated from other funds of Borrower or Calpine, as the case may be, and shall be forthwith paid over to Agent in the same form as received (with any necessary endorsement). To the fullest extent that it effectively may do so under applicable law, Agent shall apply all such Insurance Proceeds in accordance with the provisions of this Section 7.11. 7.11.2 Business Interruption Insurance. Any business interruption Insurance Proceeds received by Agent or Borrower shall be deposited into the Revenue Account for application in accordance with Section 7.2 (provided that Borrower may not apply such Insurance Proceeds toward payment of the items described in Waterfall Level 10 or 11 without the consent of the Majority Banks). 80 93 7.11.3 Applications; Mandatory Prepayments. All Insurance Proceeds (other than those described in Sections 7.11.2 and 7.11.4) and all Eminent Domain Proceeds shall be applied (a) to the prepayment of Loans in inverse order of maturity, and (b) to the payment of all other Obligations of Borrower, unless each of the following conditions are satisfied or waived by the Agent, or the Required Banks, as required pursuant to Section 7.11.5 or 7.11.6, in which event such amounts shall be applied to the repair or restoration of the Project in accordance with the terms of such subsections: (a) such damage or destruction does not constitute the destruction of all or substantially all of the man-made portion of the Project; (b) no Inchoate Default or Event of Default has occurred and is continuing and after giving effect to any proposed repair and restoration, such damage or destruction or proposed repair and restoration will not result in an Event of Default or an Inchoate Default; (c) Borrower and the Independent Engineer certify, and Agent (with, if applicable, the consent of the Required Banks) determines in its reasonable judgment, that repair or restoration of the Project is technically and economically feasible within a six-month period and that a sufficient amount of funds is or will be available to Borrower to make repairs and restorations; (d) Borrower and the Independent Engineer certify, and Agent (with, if applicable, the consent of the Required Banks) determines in its reasonable judgment, that a sufficient amount of funds is or will be available to Borrower and to make all payments of Debt Service which will become due during and following repair period and to maintain the Debt Service Coverage Ratios set forth in the Base Case Project Projections as in effect on the Closing Date, unless the Required Banks agree otherwise; (e) if such damage or destruction occurs during construction, such repair or restoration will not adversely affect, in the reasonable judgment of Agent in consultation with the Independent Engineer, achievement of Completion by the Construction Loan Maturity Date; (f) no Permit is necessary to proceed with the repair and restoration and no material amendment to the Project Documents, or, except with the consent of the Required Banks, this Agreement or any of the Credit Documents, and no other instrument is necessary for the purpose of effecting the repairs or restorations or subjecting the repairs or restorations to the Liens of the Collateral Documents and maintaining the priority of such Liens or, if any of the above is necessary, Borrower will be able to obtain the same as and when required; (g) Agent shall receive an opinion of counsel acceptable to Agent opining as to the Permits described in paragraph (f) above, and an opinion to the effect that such 81 94 repairs or restoration will be subject to the Liens of the Collateral Documents at the same level of priority as the other Collateral; and (h) Agent shall receive such additional title insurance, title insurance endorsements, mechanic's lien waivers, certificates, opinions or other matters as it may reasonably request as necessary or appropriate in connection with such repairs or restoration or to preserve or protect the Banks' interests hereunder and in the Collateral. 7.11.4 Proceeds Less than $1,000,000. If there shall occur any damage or destruction of the Project with respect to which Insurance Proceeds for any single loss not in excess of $1,000,000 are payable, such Insurance Proceeds shall be held by the Agent in the Loss Proceeds Account and released by Agent to the Borrower in accordance with Section 7.11.7. 7.11.5 Proceeds in Excess of $1,000,000, Not in Excess of $5,000,000. Provided that the conditions set forth in Section 7.11.3 have been waived by the Agent and the Independent Engineer, or have been acknowledged by such Persons as having been satisfied, if there shall occur any damage or destruction of the Project with respect to which Insurance Proceeds for any single loss in excess of $1,000,000, but not in excess of $5,000,000, are payable, such Insurance Proceeds shall be held by the Agent in the Loss Proceeds Account and released by Agent to the Borrower in accordance with Section 7.11.7. 7.11.6 Proceeds in Excess of $5,000,000. Provided that the conditions set forth in Section 7.11.3 have been waived by the Agent, the Required Banks and the Independent Engineer, or have been acknowledged by such Persons as having been satisfied, if there shall occur any damage or destruction of the Project with respect to which Insurance Proceeds for any single loss in excess of $5,000,000 are payable, such Insurance Proceeds shall be held by the Agent in the Loss Proceeds Account and released by Agent to the Borrower in accordance with Section 7.11.7. 7.11.7 Repair and Restoration Procedures. Amounts which are to be applied to repair or restoration of the Project pursuant to this Section 7.11 shall be disbursed by Agent from the Loss Proceeds Account in accordance with the following procedures: (a) Borrower shall cause any repairs or restoration to be commenced and completed promptly and diligently at the cost and expense of Borrower; (b) From time to time (after the Agent or the Required Banks, if applicable, shall have duly approved the making of such repairs or restoration), Agent's authorization of release of Insurance Proceeds for application toward such repairs or restoration shall be conditioned upon Borrower's written request and the presentation to Agent of all documents, certificates and information with respect to such Insurance Proceeds which would be required in order to obtain a Construction Loan under this Agreement, including a certificate from Borrower (i) describing in reasonable detail the nature of the repairs or restoration to be effected with such release, (ii) stating the cost of such repairs or restoration and the specific amount 82 95 requested to be paid over to or upon the order of Borrower and that such amount is requested to pay the cost thereof, (iii) stating that the aggregate amount requested by Borrower in respect of such repairs or restoration (when added to any other Insurance Proceeds received by Borrower in respect of such damage or destruction) does not exceed the cost of such repairs or restoration and that a sufficient amount of funds is or will be available to Borrower to complete the Project, and (iv) stating that no Inchoate Default has occurred and is continuing other than an Event of Default resulting solely from such damage or destruction. 7.11.8 Excess Insurance Proceeds. If, after Insurance Proceeds have been applied to the repair or restoration of the Project as provided in Sections 7.11.4, 7.11.5 or 7.11.6, the Banks in consultation with the Independent Consultants determine that the Project will be able to operate at a level enabling Borrower to satisfy its obligations hereunder as well as before the damage or destruction, any excess Insurance Proceeds shall be paid into the Revenue Account. In the event that the Banks in consultation with the Independent Engineer determine otherwise, such excess Insurance Proceeds shall be applied (a) to the prepayment of Loans in such order as will enable the Project to operate at a level enabling Borrower to satisfy its obligations hereunder as well as before the damage and destruction and thereafter in inverse order of maturity, and (b) to the payment of all other Obligations of Borrower. 7.11.9 Events of Default. If an Event of Default shall have occurred and be continuing, then any provisions of this Sections 7.11 to the contrary notwithstanding, the Insurance Proceeds (including any Permitted Investments made with such proceeds, which shall be liquidated in such manner as the Banks shall deem reasonable and prudent under the circumstances) may be applied by Agent (a) to curing such Event of Default, and any Insurance Proceeds remaining thereafter shall be applied as provided in this Section 7.11 or (b) if such Event of Default cannot be cured, toward payment of all other Obligations of Borrower, in connection with exercise of the Banks' remedies pursuant to Article 8. 7.12 Application of Eminent Domain Proceeds. All amounts and proceeds (including instruments) received in respect of any Event of Eminent Domain ("Eminent Domain Proceeds") shall be subject to the same treatment as Insurance Proceeds as provided in Section 7.10. 7.13 Application of Certain Damages Payments; Mandatory Prepayments. 7.13.1 Contractor. Delay related Liquidated Damages shall be deposited in the Construction Account and applied pursuant to Section 7.1.4. Performance related Liquidated Damages received before Term-Conversion shall be applied to the prepayment of Construction Loans in accordance with Section 2.1.7. Performance related Liquidated Damages received after Term- Conversion shall be applied first to the prepayment of Term Loans in accordance with Section 2.1.7 and thereafter to all other Obligations of Borrower. 7.13.2 Power Purchasers. Any damage payments made by Phillips, HL&P, Power Marketer, or any other purchaser of the power generated by the Project in 83 96 satisfaction of such party's obligations under its purchase agreement shall (a) to the extent such damages are intended to replace lost revenues, be deposited in the Revenue Account for application as provided in Section 7.2, and (b) otherwise, be deposited in the Loss Proceeds Account and (i) applied to the prepayment of (A) prior to Term-Conversion, Construction Loans, and (B) following Term-Conversion, Term Loans in inverse order of maturity and (ii) to the extent that all such Construction Loans or Term Loans, as applicable, have been prepaid, applied to the other Obligations of Borrower. 7.13.3 Other. Except as otherwise expressly permitted under this Agreement, including this Section 7.13, Borrower shall apply the proceeds of any other surety, performance or similar bonds and any other liquidated or other damages paid in respect of damage payments or performance payments by any contractors or subcontractors or other Persons involved in the construction and operation of the Project, to the prepayment of the Loans in inverse order of maturity, and thereafter to the Obligations of Borrower or, with the prior written consent of Agent acting in consultation with the Independent Engineer, to such other application in relation to the Project as Borrower may request. 7.14 Security Interest in Proceeds and Accounts. Borrower hereby pledges, assigns and transfers to the Agent on behalf of the Banks and grants to Agent on behalf of the Banks a security interest in and to all Insurance Proceeds and Eminent Domain Proceeds (collectively, "Proceeds"), Accounts, and contents of Accounts, as security for the Loans and the full and faithful performance of all of Borrower's obligations hereunder and under the other Credit Documents. Borrower shall not have any rights or powers with respect to any Account except to have funds on deposit therein applied or distributed to Borrower in accordance with this Agreement. Agent is hereby authorized to reduce to cash any Permitted Investment (without regard to maturity) in order to make any application required by any section of this Article 7 or otherwise pursuant to the Credit Documents. Upon the occurrence and during the continuance of an Event of Default, Agent shall have all rights and powers with respect to Proceeds, the Accounts and the contents of the Accounts as it has with respect to any other Collateral and may apply such amounts to the payment of interest, principal, fees, costs, charges or other amounts due or payable to Agent or the Banks with respect to the Loans in such order as the Majority Banks may elect in their sole discretion. If such Event of Default occurs prior to Term-Conversion, until such time as the Majority Banks so elect to exercise such rights and powers, amounts in the Revenue Account constituting Project Operating Revenues shall continue to be applied by Agent to Pre-Conversion Senior O&M Costs to the extent that Agent so elects in its sole discretion. If such Event of Default occurs following Term-Conversion, until such time as the Required Banks so elect to exercise such rights and powers, amounts in the Revenue Account shall continue to be applied by Agent to the payment categories specified in Waterfall Levels 1 (to the extent of actual Senior O&M Costs payable to third parties that are not Affiliates of Borrower) and 2 through 7, and, to the extent that Agent so elects in its sole discretion, Waterfall Levels 1, 8, 9, 10 and 11. Borrower shall not have any rights or powers with respect to such amounts except as expressly provided in this Article 7. 84 97 7.15 Permitted Investments. All amounts held by Borrower and/or Agent in the Accounts or as Insurance Proceeds or Eminent Domain Proceeds shall only be invested in Permitted Investments as provided in the Depositary Agreement. Borrower shall not hold funds in any accounts other than the Accounts; provided that Borrower shall be permitted to maintain the Operating Account in accordance with Section 7.7. 7.16 Earnings on Accounts. Except as otherwise expressly provided herein, including with respect to the Revenue Account and the Operating Account, all earnings on funds in any Account maintained hereunder shall, on each Repayment Date, be deposited in the Revenue Account as Project Operating Revenues. 7.17 Dominion and Control. Each of the Accounts and the amounts held thereunder (including Permitted Investments therein), except for the Operating Account, shall at all times be under the exclusive dominion and control of the Depository Agent. 7.18 Termination of Commitments. Upon repayment in full of all Obligations and expiration or irrevocable termination of all Commitments, Agent shall disburse any amounts on deposit in the Accounts to Borrower, or, if applicable, as directed by a court of competent jurisdiction. ARTICLE 8 - EVENTS OF DEFAULT; REMEDIES 8.1 Events of Default. The occurrence of any of the following events shall constitute an event of default ("Events of Default") hereunder: 8.1.1 Failure to Make Payments. Borrower shall fail to pay, in accordance with the terms of this Agreement, (a) any principal on any Loan on the date that such sum is due, (b) any interest on any Loan or any scheduled fee, cost, charge or sum due hereunder or under the other Credit Documents, within three (3) days after the date that such sum is due, or (c) any other fee, cost, charge or other sum due under this Agreement within five (5) days after written notice that such sum is due and has not been paid. 8.1.2 Judgments. A final judgment or judgments shall be entered against Borrower or any Partner in the amount of $1,000,000 or more individually or in the aggregate (other than (a) a judgment which is fully covered by insurance or discharged within 30 days after its entry, or (b) a judgment, the execution of which is effectively stayed within 30 days after its entry but only for 30 days after the date on which such stay is terminated or expires) or which if left unstayed could reasonably be expected to have a Material Adverse Effect. 8.1.3 Misstatements; Omissions. Any financial statement, representation, warranty or certificate made or prepared by, under the control of or on behalf of Borrower and furnished to Agent or any Bank pursuant to this Agreement, or in any separate statement or 85 98 document to be delivered to Agent or any Bank hereunder or under any other Credit Document, shall contain an untrue or misleading statement of a material fact or shall fail to state a material fact necessary to make the statements therein not misleading as of the date made, in either case, which could reasonably be expected to result in a Material Adverse Effect. 8.1.4 Bankruptcy; Insolvency. Any of Borrower, the Partners, the Shareholders, Calpine (until Term- Conversion), Phillips, HL&P, Power Marketer or any other purchaser of capacity or energy from the Project (so long as Phillips, HL&P, Power Marketer or such other purchaser, as the case may be, has outstanding or unperformed obligations under the Power Purchase Documents to which it is party and such party's Bankruptcy Event could reasonably be expected to have a Material Adverse Effect), the Fuel Supplier or any Contractor (so long as such Contractor has outstanding or unperformed obligations under the Construction Contract to which it is a party) shall become subject to a Bankruptcy Event; provided that, solely with respect to a Bankruptcy Event affecting any entity other then Borrower, the Partners, the Shareholders and Calpine, no Event of Default shall occur as a result of such Bankruptcy Event if Borrower obtains a Replacement Obligor for the affected party within 90 days thereafter and such Bankruptcy Event has not had and does not have prior to so obtaining such Replacement Obligor, a Material Adverse Effect. 8.1.5 Debt Cross Default. Borrower, or, at any time prior to Term-Conversion, Calpine or any Calpine Affiliate other than a Calpine Sole Purpose Entity shall default for a period beyond any applicable grace period (a) in the payment of any principal, interest or other amount due under any agreement involving the borrowing of money or the advance of credit and the outstanding amount or amounts payable under all such agreements equals or exceeds $1,000,000 in the aggregate, or (b) in the payment of any amount or performance of any obligation due under any guarantee or other agreement if in either case, pursuant to such default, the holder of the obligation concerned has the right to accelerate the maturity of an indebtedness evidenced thereby which equals or exceeds $1,000,000. For purposes of this Section, the term "Calpine Sole Purpose Entity" shall mean a Calpine Affiliate (i) whose sole purpose is the ownership and maintenance of a power project (other than the Project) that has been financed on a non- recourse basis and (ii) that is not directly connected to the Project or responsible for actions materially and directly affecting the Project. 8.1.6 ERISA. If Borrower or any member of the Controlled Group should establish, maintain, contribute to or become obligated to contribute to any ERISA Plan and (a) a reportable event (as defined in Section 4043(b) of ERISA) shall have occurred with respect to any ERISA Plan and, within 30 days after the reporting of such reportable event to Agent by Borrower (or Agent otherwise obtaining knowledge of such event) and the furnishing of such information as Agent may reasonably request with respect thereto, Agent shall have notified Borrower in writing that (i) Agent has made a determination that, on the basis of such reportable event, there are reasonable grounds for the termination of such ERISA Plan by the PBGC or for the appointment by the appropriate United States District Court of a trustee to administer such ERISA Plan and (ii) as a result thereof, an Event of Default exists hereunder; or (b) a trustee shall be appointed by a United States District Court to administer any ERISA Plan; or (c) the PBGC 86 99 shall institute proceedings to terminate any ERISA Plan; or (d) a complete or partial withdrawal by Borrower or any member of the Controlled Group from any Multiemployer Plan shall have occurred, or any Multiemployer Plan shall enter reorganization status, become insolvent, or terminate (or notify Borrower or any member of the Controlled Group of its intent to terminate) under Section 4041A of ERISA and, within 30 days after the reporting of any such occurrence to Agent by Borrower (or Agent otherwise obtaining knowledge of such event) and the furnishing of such information as Agent may reasonably request with respect thereto, Agent shall have notified Borrower in writing that Agent has made a determination that, on the basis of such occurrence, an Event of Default exists hereunder; provided that any of the events described in this Section 8.1.6 shall involve (A) one or more ERISA Plans that are single-employer plans (as defined in Section 4001(a)(15) of ERISA) and under which the aggregate gross amount of unfunded benefit liabilities (as defined in Section 4001(a)(16) of ERISA), including vested unfunded liabilities which arise or might arise as the result of the termination of such ERISA Plans, and/or (B) one or more Multiemployer Plans to which the aggregate liabilities of Borrower and all members of the Controlled Group, shall exceed $500,000. 8.1.7 Breach of Project Documents. (a) Borrower. Borrower shall be in breach of any term, condition, provision, covenant, representation, warranty or obligation, or in default, under a Project Document, and such breach or default shall not be remediable or, if remediable, shall continue unremedied for a period of 30 days; provided that, except with respect to a breach or default under the Phillips Documents, if (i) such breach cannot be cured within such 30 day period, (ii) such breach is susceptible of cure within 90 days, (iii) Borrower is proceeding with diligence and in good faith to cure such breach, (iv) the existence of such breach has not had and could not after considering the nature of the cure, be reasonably expected to give rise to termination by the counterparty to the Project Document which is subject to breach or to otherwise have a Material Adverse Effect and (v) Agent shall have received an officer's certificate signed by a Responsible Officer to the effect of clauses (i), (ii), (iii) and (iv) above and stating what action Borrower is taking to cure such breach, then such 30 day cure period shall be extended to such date, not to exceed a total of 90 days, as shall be necessary for Borrower diligently to cure such breach. (b) Third Party. A party other than Borrower shall be in breach of, or in default under, a Project Document or any Consent, Pledge and Security Agreement or, Shareholder Pledge and Security Agreement, or any Equity Document such breach or default shall not be remediable or, if remediable, shall continue unremedied for a period of 30 days; provided that if (i) such breach cannot be cured within such 30 day period, (ii) such breach is susceptible of cure within 90 days, (iii) the breaching party is proceeding with diligence and in good faith to cure such breach, and (iv) the existence of such breach has not had and could not after considering the nature of the cure, be reasonably expected to have a Material Adverse Effect, then such 30 day cure period shall be extended to such date, not to exceed a total of 90 days, as shall be necessary for such third party diligently to cure such breach; provided further that, no Event of Default shall be declared as a result of any such action if Borrower obtains a Replacement Obligor for the 87 100 affected party within the 90 day cure period referred to in this paragraph (or within the 30 day cure period, if no extension is given) and such action has not had and does not have prior to so obtaining such Replacement Obligor a Material Adverse Effect. (c) Termination. Any material provision in any Project Document shall for any reason cease to be valid and binding on any party thereto (other than Borrower) except upon fulfillment of such party's obligations thereunder (or any such party shall so state in writing), or shall be declared null and void, or the validity or enforceability thereof shall be contested by any party thereto (other than Agent and the Banks) or any Governmental Authority, or any such party shall deny that it has any liability or obligation thereunder, except upon fulfillment of its obligations thereunder; provided that no Event of Default shall occur as a result of such breach or default if Borrower obtains a Replacement Obligor for the affected party within 90 days thereafter and, such breach or default has not had and does not have prior to so obtaining such Replacement Obligor, a Material Adverse Effect. 8.1.8 Breach of Terms of Agreement. (a) Borrower shall fail to perform or observe any of the covenants set forth in Section 5.1, 5.9(a), 5.9(f), 5.11, 5.18, 5.19, 5.22.1 or Article 6 (other than Section 6.7, 6.8, 6.14, 6.15 or 6.20). (b) Borrower shall fail to perform or observe any other covenant to be observed or performed by it hereunder or any other Credit Document not otherwise specifically provided for in Section 8.1.8(a) or elsewhere in this Article 8, and such failure shall continue unremedied for a period of 30 days after Borrower becomes aware thereof or receives written notice thereof from Agent provided, however, that, if (i) such failure cannot be cured within such 30 day period, (ii) such failure is susceptible of cure, (iii) Borrower is proceeding with diligence and in good faith to cure such failure, (iv) the existence of such failure has not had and cannot after considering the nature of the cure be reasonably expected to have a Material Adverse Effect and (v) Agent shall have received an officer's certificate signed by a Responsible Officer to the effect of clauses (i), (ii), (iii) and (iv) above and stating what action Borrower is taking to cure such failure, then such 30 day cure period shall be extended to such date, not to exceed a total of 90 days, as shall be necessary for Borrower diligently to cure such failure. 8.1.9 Term-Conversion. Term-Conversion shall not have occurred by the Construction Loan Maturity Date. 8.1.10 Conditions to Initial Distributions. Any of the conditions to the initial distribution set forth in Section 3.5, other than Section 3.5.7, has not been satisfied or waived prior to the Date Certain. 88 101 8.1.11 Loss of Qualifying Facility Status. (a) If loss of Qualifying Facility status could reasonably be expected to have a Material Adverse Effect, (i) FERC shall have issued an order determining that the Project has ceased to be a Qualifying Facility or (ii) the Project shall have failed to meet the criteria for a Qualifying Facility, and, subject to the provisions of Section 8.1.7(a), shall have failed to obtain a waiver from FERC on account thereof within six months after the end of any calendar year in which the Borrower knows or should reasonably have known that it has failed to meet such criteria. (b) Borrower or any Partner shall lose the exemption from regulation under PUHCA. 8.1.12 Abandonment. (a) At any time prior to the Term-Conversion, Borrower shall announce that it is abandoning the Project or the Project shall be abandoned or work thereon shall cease for a period of more than 30 consecutive days for any reason (which period (i) shall be measured from the first occurrence of a work stoppage and continuing until work of a substantial nature is resumed and thereafter diligently continued, and (ii) shall not include delays caused by any event of force majeure or default by a Major Project Participant (other than Borrower or its Affiliates) under the Construction Contracts or the Phillips Documents), or the Project shall not be constructed substantially in accordance with the Plans and Specifications (except as to changes therein approved by Agent). (b) At any time following Term-Conversion, Borrower shall announce that it is abandoning the Project or the Project shall be abandoned or operation thereof shall cease for a period of more than thirty (30) consecutive days for any reason (other than force majeure). 8.1.13 Security. Any of the Collateral Documents, once executed and delivered, shall, except as the result of the acts or omissions of Agent or the Banks, fail to provide the Banks the Liens, first priority security interest, rights, titles, interest, remedies permitted by law, powers or privileges intended to be created thereby or cease to be in full force and effect, or the first priority or validity thereof or the applicability thereof to the Loans, the Notes or any other obligations purported to be secured or guaranteed thereby or any part thereof shall be disaffirmed by or on behalf of Borrower. 8.1.14 Loss of Control. The occurrence of any of the following: (a) At any time prior to Term-Conversion, without the prior written consent of Agent and the Required Banks, any Transfer of an ownership interest in Borrower shall occur, other than a transfer (i) to any Affiliate of Calpine reasonably approved by the Agent and the Required Banks and (ii) to Phillips pursuant to the Equity Rights Agreement; 89 102 (b) At any time following Term-Conversion, without the prior written consent of Agent and the Required Banks, any Transfer of an ownership interest in Borrower shall occur, other than a transfer (i) to any Affiliate of Calpine reasonably approved by the Agent and the Required Banks, (ii) to Phillips pursuant to the Equity Rights Agreement and (iii) to any Qualified Transferee; (c) Calpine shall cease to directly or indirectly (i) own and control at least 50% of the partnership interests in Borrower or (ii) maintain a controlling managing general partner interest in Borrower; (d) CPC shall cease to directly own and control 100% of the managing general partnership interests in Borrower; or (e) any Transfer (including the transfers described in Sections (a), (b), (c) and (d) above) unless (i) no Event of Default or Inchoate Default shall have occurred and be continuing or shall occur as a result of any such Transfer; (ii) all Permits and other certificates, licenses, appraisals or requirements of any Governmental Authority with respect to such Transfer have been obtained and are in full force and effect, and such Transfer complies in all material respects with the terms, conditions and requirements thereof; (iii) such Transfer complies with the terms and conditions of the Project Documents; (iv) such Transfer complies with all applicable laws, rules, regulations, ordinances, codes, orders, decrees or judgments of any Governmental Authority having jurisdiction with respect thereto, including all federal and state securities laws; (v) all Base Equity and Additional Borrower Equity required to be deposited under the Operative Documents has been applied toward Project Costs or payment of Loans or provision therefor acceptable to Agent has been made; (vi) the intended transferee has executed and delivered to Agent a pledge and security agreement in substantially the form of Exhibit D-5 or D-6 to the Credit Agreement; and (vii) if such intended Transfer is a pledge, hypothecation or other encumbrance, the intended lienholder shall have executed and delivered a Subordination Agreement in the form of Exhibit D-8 to the Credit Agreement. 8.1.15 Loss of or Failure to Obtain Applicable Permits or Applicable Third Party Permits. (a) Borrower shall fail to obtain any Permit on or before the date that such Permit becomes an Applicable Permit, or any Major Project Participant shall fail to obtain any Permit on or before the date that such Permit becomes an Applicable Third Party Permit, and such failure could reasonably be expected to have a Material Adverse Effect. (b) Any Applicable Permit necessary for operation of the Project shall be materially modified (other than modifications requested by Borrower and approved in writing in advance of such modification by Agent acting at the direction of the Majority Banks which approval shall not be unreasonably withheld), revoked, cancelled or not renewed by the issuing agency or other Governmental Authority having jurisdiction and within 30 days thereafter Borrower is not able to demonstrate to the reasonable satisfaction of the Majority Banks that such 90 103 modification or loss of such Permit reasonably could not be expected to have a Material Adverse Effect. (c) Any Third Party Permit necessary for performance by the applicable Major Project Participant shall be materially modified, revoked, cancelled or not renewed by the issuing agency or other Governmental Authority having jurisdiction and within 90 days thereafter Borrower is not able to (i) demonstrate to the reasonable satisfaction of the Majority Banks that such modification or loss of such Third Party Permit will not have a Material Adverse Effect, or (ii) obtain a Replacement Obligor for such Major Project Participant, where prior to Borrower obtaining such Replacement Obligor such breach or default has not had and could not reasonably be expected to have, a Material Adverse Effect. 8.1.16 Loss of Collateral. Any substantial portion of Borrower's property is damaged, seized or appropriated without fair value being paid therefor so as to allow replacement of such property and/or prepayment of Loans and to allow Borrower in Agent's reasonable judgment to continue satisfying its obligations hereunder and under the other Operative Documents. 8.1.17 Material Adverse Effect. Except as otherwise specifically provided in this Article 8, an event causing a Material Adverse Effect has occurred and is continuing. 8.2 Remedies. Upon the occurrence and during the continuation of an Event of Default, Agent and the Banks may, at the election of the Required Banks, without further notice of default, presentment or demand for payment, protest or notice of non-payment or dishonor, or other notices or demands of any kind, all such notices and demands being waived, exercise any or all of the following rights and remedies, in any combination or order that the Required Banks may elect, in addition to such other rights or remedies as the Banks may have hereunder, under the Collateral Documents or at law or in equity: 8.2.1 No Further Loans. Cancel all commitments, refuse, and Agent and the Banks shall not be obligated, to continue any Loans, make any additional Loans or make any payments, or permit the making of payments, from any Account or any Proceeds or other funds held by Agent under the Credit Documents or on behalf of Borrower: 8.2.2 Cure by Agent. Without any obligation to do so, make disbursements or Loans to or on behalf of Borrower to cure any Event of Default hereunder and to cure any default and render any performance under any Project Documents as the Majority Banks in their sole discretion may consider necessary or appropriate, whether to preserve and protect the Collateral or the Banks' interests therein or for any other reason, and all sums so expended, together with interest on such total amount at the Default Rate (but in no event shall the rate exceed the maximum lawful rate), shall be repaid by Borrower to Agent on demand and shall be secured by the Credit Documents, notwithstanding that such expenditures may, together 91 104 with amounts advanced under this Agreement, exceed the amount of the Total Construction Loan Commitment. 8.2.3 Acceleration. Declare and make all sums of accrued and outstanding principal and accrued but unpaid interest remaining under this Agreement together with all unpaid fees, costs (including Liquidation Costs and Hedge Breaking Fees) and charges due hereunder or under any other Credit Document, immediately due and payable, provided that in the event of an Event of Default occurring under Section 8.1.4 with respect to Borrower, all such amounts shall become immediately due and payable without further act of Agent or the Banks. 8.2.4 Cash Collateral. Apply or execute upon any amounts on deposit in any Account or any Proceeds, Base Equity or any other moneys of Borrower on deposit with Agent or any Bank in the manner provided in the Uniform Commercial Code and other relevant statutes and decisions and interpretations thereunder with respect to cash collateral. 8.2.5 Possession of Project. Enter into possession of the Project and perform any and all work and labor necessary to complete the Project substantially according to the Plans and Specifications or to operate and maintain the Project, and all sums expended by Agent in so doing, together with interest on such total amount at the Default Rate, shall be repaid by Borrower to Agent upon demand and shall be secured by the Credit Documents, notwithstanding that such expenditures may, together with amounts advanced under this Agreement, exceed the amount of the Total Construction Loan Commitment. 8.2.6 Remedies Under Credit Documents. Exercise any and all rights and remedies available to it under any of the Credit Documents, including judicial or non-judicial foreclosure or public or private sale of any of the Collateral pursuant to the Collateral Documents. ARTICLE 9 - SCOPE OF LIABILITY The Banks shall have no claims with respect to the transactions contemplated by the Operative Documents against any Partners, Shareholders or any of their respective Affiliates (other than the Borrower), shareholders, officers, directors or employees (collectively the "Nonrecourse Persons"); provided that (a) the foregoing provision of this Article 9 shall not constitute a waiver, release or discharge of any of the indebtedness, or of any of the terms, covenants, conditions, or provisions of this Agreement, any other Security Document or Credit Document and the same shall continue (but without personal liability to the Nonrecourse Person) until fully paid, discharged, observed, or performed; (b) the foregoing provision of this Article 9 shall not limit or restrict the right of the Agent and/or the Banks or Hedge Banks (or any assignee, beneficiary or successor to any of them) to name Borrower or any other Person as a defendant in any action or suit for a judicial foreclosure or for the exercise of any other remedy under or with respect to this Agreement or any other Security Document or Credit Document, or for injunction or specific performance, so long as no judgment in the nature of a deficiency judgment shall be enforced against any Nonrecourse Person, except as set forth in this Article 9, (c) the foregoing provision of this Article 9 shall not in any way limit or restrict any right or 92 105 remedy of Agent and/or the Banks (or any assignee or beneficiary thereof or successor thereto) with respect to, and each of the Nonrecourse Persons shall remain fully liable to the extent that it would otherwise be liable for its own actions with respect to, any fraud (which shall not include innocent or negligent misrepresentation), willful misrepresentation, or misappropriation of Project Revenues, Proceeds or any other earnings, revenues, rents, issues, profits or proceeds from or of the Collateral that should or would have been paid as provided herein or paid or delivered to Agent or any Bank (or any assignee or beneficiary thereof or successor thereto) towards any payment required under this Agreement or any other Credit Document; (d) the foregoing provision of this Article 9 shall not affect or diminish or constitute a waiver, release or discharge of any specific written obligation, covenant, or agreement in respect of the Project made by any of the Nonrecourse Persons or any security granted by the Nonrecourse Persons in support of the obligations of such persons under any Equity Document or as security for the obligations of the Borrower; and (e) nothing contained herein shall limit the liability of (i) any Person who is a party to any Project Document or has issued any certificate or other statement in connection therewith with respect to such liability as may arise by reason of the terms and conditions of such Project Document (but subject to any limitation of liability in such Project Document), certificate or statement, or (ii) any Person rendering a legal opinion pursuant to Section 3.1.8, or otherwise, in each case under this clause (e) relating solely to such liability of such Person as may arise under such referenced agreement, instrument or opinion. The limitations on recourse set forth in this Article 9 shall survive the termination of this Agreement and the full payment and performance of the Obligations hereunder and under the other Operative Documents. ARTICLE 10 - THE AGENT; SUBSTITUTION 10.1 Appointment, Powers and Immunities. 10.1.1 Each Bank hereby appoints and authorizes Agent to act as its agent hereunder and under the other Credit Documents with such powers as are expressly delegated to Agent by the terms of this Agreement and the other Credit Documents, together with such other powers as are reasonably incidental thereto. Agent shall not have any duties or responsibilities except those expressly set forth in this Agreement or in any other Credit Document, or be a trustee for any Bank. Notwithstanding anything to the contrary contained herein Agent shall not be required to take any action which is contrary to this Agreement or any other Credit Documents or any Legal Requirement or exposes Agent to any liability. Each of Agent, the Banks and any of their respective Affiliates shall not be responsible to any other Bank for any recitals, statements, representations or warranties made by Borrower, its Affiliates or Partners contained in this Agreement or in any certificate or other document referred to or provided for in, or received by Agent, or any Bank under this Agreement, for the value, validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement, the Notes or any other document referred to or provided for herein or for any failure by Borrower, its Affiliates, its Partners or the Shareholders to perform their respective obligations hereunder or thereunder. Agent may employ agents and attorneys-in-fact and shall not be responsible for the negligence or misconduct of any such agents or attorneys-in-fact selected by it with reasonable care. 93 106 10.1.2 Agent and its respective directors, officers, employees or agents shall not be responsible for any action taken or omitted to be taken by it or them hereunder or under any other Credit Document or in connection herewith or therewith, except for its or their own gross negligence or willful misconduct. Without limiting the generality of the foregoing, Agent (a) may treat the payee of any Note as the holder thereof until Agent receives written notice of the assignment or transfer thereof signed by such payee and in form satisfactory to Agent; (b) may consult with legal counsel, independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by them in accordance with the advice of such counsel, accountants or experts; (c) makes no warranty or representation to any Bank for any statements, warranties or representations made in or in connection with any Project Document or Credit Document; (d) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of any Operative Document on the part of any party thereto or to inspect the property (including the books and records) of Borrower or any other Person; and (e) shall not be responsible to any Bank for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of any Operative Document or any other instrument or document furnished pursuant hereto. Except as otherwise provided under this Agreement, Agent shall take such action with respect to the Credit Documents as shall be directed by the Majority Banks. 10.2 Reliance by Agent. Agent shall be entitled to rely upon any certificate, notice or other document (including any cable, telegram, telecopy or telex) believed by it to be genuine and correct and to have been signed or sent by or on behalf of the proper Person or Persons, and upon advice and statements of legal counsel, independent accountants and other experts selected by Agent. As to any other matters not expressly provided for by this Agreement, Agent shall not be required to take any action or exercise any discretion, but shall be required to act or to refrain from acting upon instructions of the Majority Banks or, where expressly provided, the Required Banks (except that Agent shall not be required to take any action which exposes Agent to personal liability or which is contrary to this Agreement, any other Credit Document or any Legal Requirement) and shall in all cases be fully protected in acting, or in refraining from acting, hereunder or under any other Credit Document in accordance with the instructions of the Majority Banks (or, where so expressly stated, the Required Banks), and such instructions of the Majority Banks (or Required Banks, where applicable) and any action taken or failure to act pursuant thereto shall be binding on all of the Banks. 10.3 Non-Reliance. Each Bank represents that it has, independently and without reliance on Agent or any other Bank, and based on such documents and information as it has deemed appropriate, made its own appraisal of the financial condition and affairs of Borrower and decision to enter into this Agreement and agrees that it will, independently and without reliance upon Agent, or any other Bank, and based on such documents and information as it shall deem appropriate at the time, continue to make its own appraisals and decisions in taking or not taking action under this Agreement. Each of Agent and any Bank shall not be required to keep informed as to the performance or observance by Borrower, its Affiliates or Partners under this Agreement or any other document referred to or provided for herein or to make inquiry of, or to inspect the properties or books of Borrower, its Affiliates or Partners. 94 107 10.4 Defaults. Agent shall not be deemed to have knowledge or notice of the occurrence of any Inchoate Default or Event of Default unless Agent has received a notice from a Bank or Borrower, referring to this Agreement, describing such Inchoate Default or Event of Default and indicating that such notice is a notice of default. If Agent receives such a notice of the occurrence of an Inchoate Default or Event of Default, Agent shall give notice thereof to the Banks. Agent shall take such action with respect to such Inchoate Default or Event of Default as is provided in Article 8 or if not provided for in Article 8, as Agent shall be reasonably directed by the Majority Banks; provided, however, unless and until Agent shall have received such directions, Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Inchoate Default or Event of Default as it shall deem advisable in the best interest of the Banks. 10.5 Indemnification. Without limiting the Obligations of Borrower hereunder, each Bank agrees to indemnify Agent, ratably in accordance with their Proportionate Shares for any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may at any time be imposed on, incurred by or asserted against Agent in any way relating to or arising out of this Agreement or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or the enforcement of any of the terms hereof or thereof or of any such other documents; provided, however, that no Bank shall be liable for any of the foregoing to the extent they arise from Agent's gross negligence or willful misconduct. Agent shall be fully justified in refusing to take or to continue to take any action hereunder unless it shall first be indemnified to its satisfaction by the Banks against any and all liability and expense which may be incurred by it by reason of taking or continuing to take any such action. Without limitation of the foregoing, each Bank agrees to reimburse Agent promptly upon demand for its ratable share of any out-of-pocket expenses (including counsel fees) incurred by Agent in connection with the preparation, execution, administration or enforcement of, or legal advice in respect of rights or responsibilities under, the Operative Documents, to the extent that Agent is not reimbursed for such expenses by Borrower. 10.6 Successor Agent. Agent acknowledges that its current intention is to remain Agent hereunder. Nevertheless, Agent may resign at any time by giving written notice thereof to the Banks and Borrower. Agent may be removed involuntarily only for a material breach of its duties and obligations hereunder or under the other Credit Documents or for gross negligence or willful misconduct in connection with the performance of its duties hereunder or under the other Credit Documents and then only upon the affirmative vote of the Majority Banks (excluding Agent from such vote and Agent's Proportionate Share of the Commitment from the amounts used to determine the portion of the Commitment necessary to constitute the required Proportionate Share of the remaining Banks). Upon any such resignation or removal, the Majority Banks shall have the right, with the consent of Borrower (such consent not to be unreasonably withheld or delayed) to appoint a successor Agent. If no successor Agent shall have been so appointed by the Majority Banks, and shall have accepted such appointment, within 30 days after the retiring Agent's giving of notice of resignation or the Banks' removal of the retiring Agent, the retiring Agent may, on behalf of the Banks, with the consent of Borrower (such consent not to be 95 108 unreasonably withheld or delayed), appoint a successor Agent, which shall be a Bank, if any Bank shall be willing to serve, and otherwise shall be a commercial bank having a combined capital and surplus of at least $500,000,000. Upon the acceptance of any appointment as Agent under the Operative Documents by a successor Agent, such successor Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations as Agent only under the Credit Documents. After any retiring Agent's resignation or removal hereunder as Agent, the provisions of this Article 10 shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Agent under the Operative Documents. 10.7 Authorization. Agent is hereby authorized by the Banks to execute, deliver and perform each of the Credit Documents to which Agent is or is intended to be a party and each Bank agrees to be bound by all of the agreements of Agent contained in the Credit Documents. Agent is further authorized by the Banks to release liens on property that Borrower is permitted to sell or transfer pursuant to the terms of this Agreement, the other Credit Documents or the Operative Documents, and to enter into agreements supplemental hereto for the purpose of curing any formal defect, inconsistency, omission or ambiguity in this Agreement or any Credit Document to which it is a party. 10.8 Agent. With respect to its Commitment, the Loans made by it and any Note issued to it, Agent shall have the same rights and powers under the Operative Documents as any other Bank and may exercise the same as though it were not Agent. The term "Bank" or "Banks" shall, unless otherwise expressly indicated, include Agent in its individual capacity. Agent and its Affiliates may accept deposits from, lend money to, act as trustee under indentures of, and generally engage in any kind of business with Borrower or any other Person, without any duty to account therefor to the Banks. 10.9 Amendments; Waivers. Subject to the provisions of this Section 10.9, unless otherwise specified in this Agreement or another Credit Document, the Required Banks (or Agent with the consent in writing of the Required Banks) and Borrower may enter into agreements supplemental hereto for the purpose of adding, modifying or waiving any provisions to the Credit Documents or changing in any manner the rights of the Banks or Borrower hereunder or waiving any Inchoate Default or Event of Default; provided, however, that no such supplemental agreement shall, without the consent of all of the Banks: 10.9.1 Extend the maturity of any Loan or any of the Notes or reduce the principal amount thereof, or reduce the rate or change the time of payment of interest due on any Loan or any Notes; or 10.9.2 Extend the Construction Loan Maturity Date; or 10.9.3 Modify Section 2.1.1(d), 2.5, 2.6, 2.7, 5.1, 5.18, 6.17, 6.22, 7.1 through 7.18, 8.1.13, 10.1, 10.13 or 10.14; or 96 109 10.9.4 Reduce the amount or extend the payment date for any amount due under Article 2, whether principal, interest, fees or other amounts; or 10.9.5 Increase the amount of the Commitment of any Bank hereunder; or 10.9.6 Reduce or change the time of payment of any fee due or payable hereunder; or 10.9.7 Reduce the percentage specified in the definition of Majority Banks or Required Banks; or 10.9.8 Permit Borrower to assign its rights under this Agreement except as provided in Section 6.17, or permit a Transfer except as provided in Section 8.1.14, or 10.9.9 Amend this Section 10.9; or 10.9.10 Release any Collateral from the Lien of any of the Collateral Documents or allow release of any funds from any Account otherwise than in accordance with the terms hereof. No amendment of any provision of this Agreement relating to Agent shall be effective without the written consent of Agent. 10.10 Withholding Tax. 10.10.1 Agent may withhold from any interest payment to any Bank an amount equivalent to any applicable withholding tax. If the forms or other documentation required by Section 2.5 are not delivered to Agent, then Agent may withhold from any interest payment to any Bank not providing such forms or other documentation, an amount equivalent to the applicable withholding tax. 10.10.2 If the Internal Revenue Service or any authority of the United States or other jurisdiction asserts a claim that Agent did not properly withhold tax from amounts paid to or for the account of any Bank (because the appropriate form was not delivered, was not properly executed, or because such Bank failed to notify Agent of a change in circumstances which rendered the exemption from, or reduction of, withholding tax ineffective, or for any other reason) such Bank shall indemnify Agent fully for all amounts paid, directly or indirectly, by Agent as tax or otherwise, including penalties and interest, together with all expenses incurred, including legal expenses, allocated staff costs, and any out of pocket expenses. 10.10.3 If any Bank sells, assigns, grants participation in, or otherwise transfers its rights under this Agreement, the purchaser, assignee, participant or transferee, as applicable, shall comply and be bound by the terms of Sections 2.4.7, 10.10.1 and 10.10.2 as though it were such Bank. 97 110 10.11 General Provisions as to Payments. Agent shall promptly distribute to each Bank, subject to the terms of the assignment and assumption agreement between Agent and such Bank, its pro rata share of each payment of principal and interest payable to the Banks on the Loans and of fees hereunder received by Agent for the account of the Banks and of any other amounts owing under the Loans. The payments made for the account of each Bank shall be made, and distributed to it, for the account of (a) its domestic lending office in the case of payments of principal of, and interest on, its Base Rate Loans, (b) its domestic or foreign lending office, as each Bank may designate in writing to Agent, in the case of LIBOR Loans, and (c) its domestic lending office, or such other lending office as it may designate for the purpose from time to time, in the case of payments of fees and other amounts payable hereunder. Banks shall have the right to alter designated domestic lending offices upon notice to Agent and Borrower. 10.12 Substitution of Bank. Should any Bank fail to make a Loan in violation of its obligations under this Agreement (a "Non-Advancing Bank"), Agent shall (a) in its sole discretion fund the Loan on behalf of the Non-Advancing Bank or (b) cooperate with Borrower or any other Bank to find another Person that shall be acceptable to Agent and that shall be willing to assume the Non-Advancing Bank's obligations under this Agreement (including the obligation to make the Loan which the Non-Advancing Bank failed to make but without assuming any liability for damages for failing to have made such Loan or any previously required Loan). Subject to the provisions of the next following sentence, such Person shall be substituted for the Non-Advancing Bank hereunder upon execution and delivery to Agent of an agreement acceptable to Agent by such Person assuming the Non-Advancing Bank's obligations under this Agreement, and all interest and fees which would otherwise have been payable to the Non-Advancing Bank shall thereafter be payable to such Person. Nothing in (and no action taken pursuant to) this Section 10.12 shall relieve the Non-Advancing Bank from any liability it might have to Borrower or to the other Banks as a result of its failure to make any Loan. 10.13 Participation. Nothing herein provided shall prevent any Bank from selling a participation in its Commitment (and Loans made thereunder) in an aggregate amount of at least $5,000,000 with respect to any participant; provided that (a) no such sale of a participation shall alter such Bank's or the Borrower's obligations hereunder, (b) any agreement pursuant to which any Bank may grant a participation in its rights with respect to its Commitment (and Loans) shall provide that, with respect to such Commitment (and Loans), subject to the following proviso, such Bank shall retain the sole right and responsibility to exercise the rights of such Bank, and enforce the obligations of Borrower relating to such Commitment (and Loans), including the right to approve any amendment, modification or waiver of any provision of this Agreement or any other Bank Document and the right to take action to have the Notes declared due and payable pursuant to Article 8; provided, however, that such agreement may provide that the participant may have rights to approve or disapprove decreases in interest rates or fees, lengthening of maturity of any Loans, or release of any material Collateral. No recipient of a participation in any Commitment or Loans of any Bank shall have any rights under this Agreement or shall be entitled to any reimbursement for Taxes, Other Taxes increased costs or reserve requirements under Sections 2.4 or 2.6 or any other indemnity or payment rights against the Borrower (but shall be permitted to 98 111 receive from the Bank granting such participation a proportionate amount which would have been payable to the Bank from whom such Person acquired its participation). 10.14 Transfer of Commitment. Notwithstanding anything else herein to the contrary, any Bank, after receiving Agent's prior written consent, and after reasonable notice to and consultation with Borrower, may from time to time, at its option, sell, assign, transfer, negotiate or otherwise dispose of a portion of its Commitment (and Loans made thereunder) (including the Bank's interest in this Agreement and the other Credit Documents) to any bank or other lending institution which in such assigning Bank's judgment is reasonably capable of performing the obligations of a Bank hereunder and reasonably experienced in project financing; provided, however, that no Bank (including any assignee of any Bank) may assign any portion of its Commitment (including Loans) of less than $5,000,000 (unless to another Bank) or which leaves the assigning Bank with a Commitment (including Loans) of less than $5,000,000 after giving effect to such assignment and all previous assignments (except that a Bank may be left with no Commitment and Loans if it assigns its entire Commitment and Loans). In the event of any such assignment, (a) the assigning Bank's Proportionate Share shall be reduced by the amount of the Proportionate Share assigned to the new lender, (b) the parties to such assignment shall execute and deliver an appropriate agreement evidencing such sale, assignment, transfer or other disposition, (c) at the assigning Bank's option, Borrower shall execute and deliver to such new lender new Notes in the forms attached hereto as Exhibits B-1 or Exhibit B-2, as appropriate, in a principal amount equal to such new lender's Commitment, and Borrower shall execute and exchange with the assigning Bank a replacement note for any Note in an amount equal to the Commitment retained by the Bank, if any and (d) Agent may amend Exhibit H attached hereto to reflect the Proportionate Shares of the Banks following such assignment. Thereafter, such new lender shall be deemed to be a Bank and shall have all of the rights and duties of a Bank (except as otherwise provided in this Article 10), in accordance with its Proportionate Share, under each of the Credit Documents. 10.15 Laws. Notwithstanding the foregoing provisions of this Article 10, no sale, assignment, transfer, negotiation or other disposition of the interests of any Bank hereunder or under the other Credit Documents shall be allowed if it would require registration under the federal Securities Act of 1933, as then amended, any other federal securities laws or regulations or the securities laws or regulations of any applicable jurisdiction. Borrower shall, from time to time at the request and expense of Agent, execute and deliver to Agent, or to such party or parties as Agent may designate, any and all further instruments as may in the opinion of Agent be reasonably necessary or advisable to give full force and effect to such disposition. 10.16 Assignability to Federal Reserve Bank. Notwithstanding any other provision contained in this Agreement or any other Credit Document to the contrary, any Bank may assign all or any portion of the Loans or Notes held by it to any Federal Reserve Bank or the United States Treasury as collateral security pursuant to Regulation A of the Board of Governors of the Federal Reserve System and any Operating Circular issued by such Federal Reserve Bank, provided that any payment in respect of such assigned Loans or Notes made by Borrower to or for the account of the assigning and/or pledging Bank in accordance with the terms of this 99 112 Agreement shall satisfy Borrower's obligations hereunder in respect of such assigned Loans or Notes to the extent of such payment. No such assignment shall release the assigning Bank from its obligations hereunder. ARTICLE 11 - INDEPENDENT CONSULTANTS 11.1 Removal and Fees. Agent, in its reasonable discretion, may remove from time to time, any one or more of the Independent Consultants and, after consulting with Borrower as to an appropriate Person, appoint replacements as Agent may choose. Notice of any replacement Independent Consultant shall be given by Agent to Borrower, the Banks and to the Independent Consultant being replaced. All reasonable fees and expenses of the Independent Consultants (whether the original ones or replacements) shall be paid by Borrower. 11.2 Duties. Each Independent Consultant shall be contractually obligated to Agent to carry out the activities required of it in this Agreement and as otherwise requested by Agent and shall be responsible solely to Agent. Borrower acknowledges that it will not have any cause of action or claim against any Independent Consultant resulting from any decision made or not made, any action taken or not taken or any advice given by such Independent Consultant in the due performance in good faith of its duties to Agent, except to the extent arising from such Independent Consultant's gross negligence or willful misconduct. 11.3 Independent Consultants' Certificates. 11.3.1 Until the receipt by Agent of certificates satisfactory to Agent from each Independent Consultant whom Agent considers necessary or appropriate certifying Completion, Borrower shall provide such documents and information to the Independent Consultants as any of the Independent Consultants may reasonably consider necessary in order for the Independent Consultants to deliver to Agent the following certificates: (a) certificates of the Insurance Consultant, Independent Engineer, Fuel Consultant and Power Marketing Consultant delivered on and dated as of the Closing Date as described in Sections 3.1.9, 3.1.11, 3.1.12, 3.1.13 and 3.1.14, respectively, and containing the matters set out therein; (b) after the Closing Date, all certificates to be delivered pursuant to Section 3.2.4 or, if no Loan has taken place in any month, certificates delivered at the end of the month as to the matters required by Exhibit C-5; and (c) monthly after the Closing Date, a full report and status of the progress of the Project to that date, a complete assessment of Project Costs to Final Completion and such other information and certification as Agent may reasonably require from time to time. 11.3.2 Following Completion, Borrower shall provide such documents and information to the Independent Consultants as they may reasonably consider necessary in order 100 113 for the Independent Consultants to deliver annually to Agent a certificate setting forth a full report on the status of the Project and such other information and certification as Agent may reasonably require from time to time. 11.4 Certification of Dates. Agent will request that the Independent Consultants act diligently in the issuance of all certificates required to be delivered by the Independent Consultants hereunder, if their issuance is appropriate. Borrower shall provide the Independent Consultants with reasonable notice of the expected occurrence of any such dates or events. ARTICLE 12 - MISCELLANEOUS 12.1 Addresses. Any communications between the parties hereto or notices provided herein to be given may be given to the following addresses: If to Agent: ING (U.S.) Capital Corporation 135 East 57th Street 8th Floor New York, New York 10022 Attn: Manager, Project Finance Telephone No.: (212) 350-7700 Telecopy No.: (212) 486-4636 If to Borrower: Pasadena Cogeneration L.P. 50 West San Fernando Street San Jose, California 95113 Attn: Asset Manager and General Counsel Telephone No.: (408) 995-5115 Telecopy No.: (408) 995-0505
All notices or other communications required or permitted to be given hereunder shall be in writing and shall be considered as properly given (a) if delivered in person, (b) if sent by overnight delivery service (including Federal Express, ETA, Emery, DHL, AirBorne and other similar overnight delivery services), (c) in the event overnight delivery services are not readily available, if mailed by first class United States Mail, postage prepaid, registered or certified with return receipt requested or (d) if sent by prepaid telegram, or by telecopy confirmed by telephone. Notice so given shall be effective upon receipt by the addressee, except that communication or notice so transmitted by telecopy or other direct written electronic means shall be deemed to have been validly and effectively given on the day (if a Banking Day and, if not, on the next following Banking Day) on which it is transmitted if transmitted before 4:00 p.m., recipient's time, and if transmitted after that time, on the next following Banking Day; provided, however, that if any notice is tendered to an addressee and the delivery thereof is refused by such addressee, such notice shall be effective upon such tender. Any party shall have the right to change its address 101 114 for notice hereunder to any other location within the continental United States by giving of 30 days' notice to the other parties in the manner set forth hereinabove. 12.2 Additional Security; Right to Set-Off. Any deposits or other sums at any time credited or due from Banks and any Project Revenues, securities or other property of Borrower in the possession of Agent may at all times be treated as collateral security for the payment of the Loans and the Notes and all other obligations of Borrower to Banks under this Agreement and the other Credit Documents, and Borrower hereby pledges to Agent for the benefit of the Banks and grants Agent a security interest in and to all such deposits, sums, securities or other property. Regardless of the adequacy of any other collateral, Agent and only Agent, may execute or realize on the Banks' security interest in any such deposits or other sums credited by or due from Banks to Borrower, may apply any such deposits or other sums to or set them off against Borrower's obligations to Banks under the Notes and this Agreement at any time after the occurrence and during the continuance of any Event of Default. 12.3 Delay and Waiver. No delay or omission to exercise any right, power or remedy accruing to the Banks upon the occurrence of any Event of Default or Inchoate Default or any breach or default of Borrower under this Agreement or any other Credit Document shall impair any such right, power or remedy of the Banks, nor shall it be construed to be a waiver of any such breach or default, or an acquiescence therein, or of or in any similar breach or default thereafter occurring, nor shall any waiver of any single Event of Default, Inchoate Default or other breach or default be deemed a waiver of any other Event of Default, Inchoate Default or other breach or default theretofore or thereafter occurring. Any waiver, permit, consent or approval of any kind or character on the part of Agent and/or the Banks of any Event of Default, Inchoate Default or other breach or default under this Agreement or any other Credit Document, or any waiver on the part of Agent and/or the Banks of any provision or condition of this Agreement or any other Credit Document, must be in writing and shall be effective only to the extent in such writing specifically set forth. All remedies, either under this Agreement or any other Credit Document or by law or otherwise afforded to Agent, LC Bank and the Banks, shall be cumulative and not alternative. 12.4 Costs, Expenses and Attorneys' Fees; Syndication. 12.4.1 Borrower will pay to Agent all of its reasonable costs and expenses in connection with the preparation, negotiation, closing and administering this Agreement and the documents contemplated hereby and any participation or syndication of the Loans, including the reasonable fees, expenses and disbursements of Latham & Watkins and other attorneys retained by Agent in connection with the preparation of such documents and any amendments hereof or thereof, or the preparation, negotiation, closing, administration, enforcement, participation or syndication of the Loans or this Agreement, the reasonable fees, expenses and disbursements of the Independent Consultants and any other engineering, insurance and construction consultants to Agent incurred in connection with this Agreement or the Loans subsequent to the Closing Date, and the travel and out-of-pocket costs incurred by Agent following the Closing Date, and Borrower further agrees to pay Agent the out-of-pocket costs and travel costs incurred by Agent 102 115 in connection with syndication of the Loans; provided, however, Borrower shall not be required to pay advertising costs of any of the Banks or the fees of the Banks' (other than Agent's) attorneys. Borrower will reimburse Agent for all costs and expenses, including reasonable attorneys' fees, expended or incurred by Agent in enforcing this Agreement or the other Credit Documents in connection with an Event of Default or Inchoate Default, in actions for declaratory relief in any way related to this Agreement or in collecting any sum which becomes due Agent on the Notes or under the Credit Documents. 12.4.2 In connection with syndication of the Loans and Commitments, an information package containing certain relevant information concerning Borrower, the Project and the other Project participants will be provided to potential Banks and participants. Borrower agrees to cooperate and to cause the Partners and the Shareholders to cooperate in the syndication of the Loans and Commitments in all respects reasonably requested by Agent, including participation in bank meetings held in connection with such syndication, and to provide, for inclusion in such package, all information which Agent may request from it or which Agent or Borrower may consider material to a lender or participant, or necessary or appropriate for accurate and complete disclosure. Upon request of Agent, Borrower shall represent to Agent, and indemnify Agent for claims relating to, the accuracy and completeness of such disclosure, upon terms acceptable to Agent. 12.5 Entire Agreement. This Agreement and any agreement, document or instrument attached hereto or referred to herein integrate all the terms and conditions mentioned herein or incidental hereto and supersede all oral negotiations and prior writings in respect to the subject matter hereof. In the event of any conflict between the terms, conditions and provisions of this Agreement and any such agreement, document or instrument, the terms, conditions and provisions of this Agreement shall prevail. This Agreement and the other Credit Documents may only be amended or modified by an instrument in writing signed by Borrower, Agent and any other parties to such agreements. 12.6 Governing Law. This Agreement, and any instrument or agreement required hereunder (to the extent not otherwise expressly provided for therein), shall be governed by, and construed under, the laws of the State of New York, without reference to conflicts of laws (other than Section 5-1401 of the New York General Obligations Law). 12.7 Severability. In case any one or more of the provisions contained in this Agreement should be invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby. 12.8 Headings. Paragraph headings have been inserted in this Agreement as a matter of convenience for reference only and it is agreed that such paragraph headings are not a part of this Agreement and shall not be used in the interpretation of any provision of this Agreement. 103 116 12.9 Accounting Terms. All accounting terms not specifically defined herein shall be construed in accordance with GAAP and practices consistent with those applied in the preparation of the financial statements submitted by Borrower to Agent, and all financial data submitted pursuant to this Agreement shall be prepared in accordance with such principles and practices. 12.10 Additional Financing. The parties hereto acknowledge that the Banks have made no agreement or commitment to provide any financing except as set forth herein. 12.11 No Partnership, Etc. The Banks and Borrower intend that the relationship between them shall be solely that of creditor and debtor. Nothing contained in this Agreement, the Notes or in any of the other Credit Documents shall be deemed or construed to create a partnership, tenancy-in-common, joint tenancy, joint venture or co-ownership by or between the Banks and Borrower or any other Person. The Banks shall not be in any way responsible or liable for the debts, losses, obligations or duties of Borrower or any other Person with respect to the Project or otherwise. All obligations to pay real property or other taxes, assessments, insurance premiums, and all other fees and charges arising from the ownership, operation or occupancy of the Project and to perform all obligations and other agreements and contracts relating to the Project shall be the sole responsibility of Borrower. 12.12 Deed of Trust/Collateral Documents. The Loans are secured in part by the Deed of Trust encumbering certain properties in the State of Texas. Reference is hereby made to the Deed of Trust and the other Collateral Documents for the provisions, among others, relating to the nature and extent of the security provided thereunder, the rights, duties and obligations of Borrower and the rights of Agent and the Banks with respect to such security. 12.13 Limitation on Liability. No claim shall be made by Borrower, any Partner or any of their Affiliates against the Banks or any of their Affiliates, directors, employees, attorneys or agents for any special, indirect, consequential or punitive damages in respect of any breach or wrongful conduct (whether or not the claim therefor is based on contract, tort or duty imposed by law), in connection with, arising out of or in any way related to the transactions contemplated by this Agreement or the other Operative Documents or any act or omission or event occurring in connection therewith except to the extent that any such claims are caused by the gross negligence or willful misconduct of the Banks; and Borrower hereby waives, releases and agrees not to sue upon any such claim for any such damages, whether or not accrued and whether or not known or suspected to exist in its favor. 12.14 Waiver of Jury Trial. THE BANKS AND BORROWER HEREBY KNOWINGLY, VOLUNTARILY, AND INTENTIONALLY WAIVE ANY RIGHTS THEY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH, THIS AGREEMENT OR ANY OTHER CREDIT DOCUMENT, OR ANY COURSE OR CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN), OR ACTIONS OF THE 104 117 BANKS OR BORROWER. THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE BANKS TO ENTER INTO THIS AGREEMENT. 12.15 Consent to Jurisdiction. The Banks and Borrower agree that any legal action or proceeding by or against Borrower or with respect to or arising out of this Agreement, the Notes, or any other Credit Document may be brought in or removed to the courts of the State of New York, in and for the County of New York, or of the United States of America for the Southern District of New York, as Agent may elect. By execution and delivery of the Agreement, the Banks and Borrower accept, for themselves and in respect of their property, generally and unconditionally, the jurisdiction of the aforesaid courts. The Banks and Borrower irrevocably consent to the service of process out of any of the aforementioned courts in any manner permitted by law. Nothing herein shall affect the right of Agent to bring legal action or proceedings in any other competent jurisdiction, including judicial or non-judicial foreclosure of the Deed of Trust. Notwithstanding the foregoing, service of process shall not be deemed served or mailed to Agent or the Banks until a copy of all matters to be served have be mailed to Latham & Watkins, 701 B Street, Suite 2100, San Diego, California 92101, Attn: Andrew D. Singer or such other Person as Agent or the Banks may hereafter designate by notice given pursuant to Section 12.1. The Banks and Borrower further agree that the aforesaid courts of the State of New York and of the United States of America shall have exclusive jurisdiction with respect to any claim or counterclaim of Borrower based upon the assertion that the rate of interest charged by the Banks on or under this Agreement, the Loans and/or the other Credit Documents is usurious. The Banks and Borrower hereby waive any right to stay or dismiss any action or proceeding under or in connection with any or all of the Project, this Agreement or any other Credit Document brought before the foregoing courts on the basis of forum non-conveniens. 12.16 Usury. Nothing contained in this Agreement or the Notes shall be deemed to require the payment of interest or other charges by Borrower or any other Person in excess of the amount which the holders of the Notes may lawfully charge under any applicable usury laws. In the event that the holders of the Notes shall collect moneys which are deemed to constitute interest which would increase the effective interest rate to a rate in excess of that permitted to be charged by applicable law, all such sums deemed to constitute interest in excess of the legal rate shall, upon such determination, at the option of the holder of the Notes, be returned to Borrower or credited against the principal balance of the Notes then outstanding. 12.17 Knowledge and Attribution. References in this Agreement and the other Credit Documents to the "knowledge," "best knowledge" or facts and circumstances "known to" Borrower, and all like references, mean facts or circumstances of which a Responsible Officer of Borrower or a Partner has actual knowledge. 12.18 Successors and Assigns. The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Borrower may not assign or otherwise transfer any of its rights under this Agreement except as provided in Section 6.17, and the Banks may not assign or otherwise transfer any of their rights under this Agreement except as provided in Article 10. 105 118 12.19 Counterparts. This Agreement may be executed in one or more duplicate counterparts and when signed by all of the parties listed below shall constitute a single binding agreement. 106 119 IN WITNESS WHEREOF, the parties have caused this Credit Agreement to be duly executed by their officers or partners thereunto duly authorized as of the day and year first above written. PASADENA COGENERATION L.P., a Delaware limited partnership By: Calpine Pasadena Cogeneration, Inc., a Delaware corporation, its General Partner By: ----------------------------------------------------------------------------- Name: ------------------------------------------------------------------ Title: ----------------------------------------------------------------- ING (U.S.) CAPITAL CORPORATION, as Agent By: ------------------------------------------------------------------------- Name: ------------------------------------------------------------------ Title: ----------------------------------------------------------------- By: ------------------------------------------------------------------------- Name: ------------------------------------------------------------------- Title: ------------------------------------------------------------------
S-1 120 ING (U.S.) CAPITAL CORPORATION, as Bank By: ------------------------------------------------------------------------- Name: ------------------------------------------------------------------ Title: ----------------------------------------------------------------- By: ------------------------------------------------------------------------- Name: ------------------------------------------------------------------- Title: ------------------------------------------------------------------
S-2 EX-10.3.11 3 AMENDED AND RESTATED ENERGY SALES AGREEMENT 1 EXHIBIT 10.3.11 AMENDED AND RESTATED ENERGY SALES AGREEMENT THIS AMENDED AND RESTATED ENERGY SALES AGREEMENT is entered into as of December 16, 1996 by and between Phillips Petroleum Company, a Delaware corporation, and Pasadena Cogeneration L.P., a Delaware limited partnership. RECITALS A. Phillips owns and operates HCC, which utilizes steam and electrical energy for industrial purposes. The Partnership will construct, own and operate the Project and intends to sell steam and electrical energy generated at the Project to Phillips, and electrical energy to Third-Party Purchasers. The Partnership intends that the Project will be certified as a "Qualifying Cogeneration Facility" under the provisions of PURPA. B. The Parties have previously entered into that certain Energy Sales Agreement dated as of August 30, 1996 setting forth their respective rights and obligations in connection with the operation of the Project, and the purchase by Phillips and the sale by the Partnership of Electrical Energy and Steam. C. The Parties desire to modify the Energy Sales Agreement dated as of August 30, 1996 in certain respects to modify certain of their respective rights and obligations in connection with the operation of the Project, and the purchase by Phillips and the sale by the Partnership of Electrical Energy and Steam. D. The Parties therefore desire to amend and restate the Energy Sales Agreement dated as of August 30, 1996 in its entirety and to enter into this Agreement, which shall supersede the Energy Sales Agreement dated as of August 30, 1996 in its entirety, effective as of December 16, 1996, to set forth their respective rights and obligations in connection with the operation of the Project, and the purchase by Phillips and the sale by the Partnership of Electrical Energy and Steam. NOW, THEREFORE, in consideration of the mutual promises and agreements set forth herein, the Parties, intending to be legally bound, hereby agree as follows: 1. DEFINITIONS AND INTERPRETATION 1.1 DEFINITIONS. Capitalized terms used in this Agreement without other definition shall have the meanings specified in Appendix A to this Agreement, unless the context requires otherwise. 2 1.2 CONSTRUCTION OF TERMS. As used in this Agreement, the terms "herein," "herewith" and "hereof" are references to this Agreement, taken as a whole, the term "includes" or "including" shall mean "including, without limitation," and references to a "Section", "subsection", "clause", "Exhibit", "Appendix" or "Schedule" shall mean a Section, subsection, clause, Exhibit, Appendix or Schedule of this Agreement, as the case may be, unless in any such case the context requires otherwise. All references to a given agreement, instrument or other document shall be a reference to that agreement, instrument or other document as modified, amended, supplemented and restated through the date as of which such reference is made, and reference to a law, regulation or ordinance includes any amendment or modification thereof. A reference to a Person includes its successors and permitted assigns. The singular shall include the plural and the masculine shall include the feminine, and vice versa. 1.3 DRAFTING INTERPRETATIONS. Preparation of this Agreement has been a joint effort of both the Parties and the resulting document shall not be construed more severely against one of the Parties than against the other. 1.4 DOCUMENTS INCLUDED. This Agreement consists of this document and the Exhibits which are listed in the Table of Contents and attached hereto or shall be attached hereto in accordance with the provisions hereof, and which are specifically incorporated herein and made a part hereof by this reference. 1.5 CONFLICTING PROVISIONS. In the event of any conflict between this document and any Exhibit hereto, the terms and provisions of this Agreement, as amended from time to time, shall control. In the event of any conflict among the Exhibits, the Exhibit of the latest date mutually agreed upon by the Parties shall control. 1.6 ENTIRE AGREEMENT. This Agreement together with the other Project Agreements set forth the full and complete understanding of the Parties relating to the subject matter of each such Project Agreement as of the Effective Date, and supersede any and all negotiations, other agreements and representations made or dated prior thereto with respect to such subject matter thereof. 2. PURCHASE AND SALE OF ELECTRICAL ENERGY AND ELECTRICAL CAPACITY 2.1 EXCLUSIVE SOURCE. Except as provided in Section 2.3.2.1, from and after the Commercial Operation Date and continuing for the remainder of the Term, (a) the Partnership shall sell and deliver to Phillips, and -2- 3 Phillips shall purchase and accept from the Partnership, Electrical Energy at the Electrical Energy Point of Delivery, and (b) the Partnership shall make available and Phillips shall reserve electrical capacity generated by the Project, all in accordance with the terms and conditions set forth in this Section 2. Phillips shall not purchase any electrical energy or capacity for HCC from any other source, without the consent of the Partnership, except as set forth in Section 2.8, as contemplated by the Standby Agreement, if Phillips has electrical energy requirements in excess of 90 MW or when the Partnership does not meet its obligations to supply Electrical Energy to Phillips under this Agreement. In addition, Phillips shall not purchase or use any equipment for the sole purpose of generating electrical energy; provided, however, Phillips may purchase or use any equipment to generate electrical energy derived from the optimization of its process unit operations. 2.2 PURCHASE AND SALE OBLIGATION FOR ELECTRICAL ENERGY AND ELECTRICAL CAPACITY. 2.2.1 PURCHASE AND SALE OBLIGATION FOR ELECTRICAL ENERGY. The Partnership shall sell and deliver to Phillips, and Phillips shall purchase and accept from the Partnership, at the Electrical Energy Point of Delivery, (a) all of the electrical energy requirements of HCC up to 90 MW which are in excess of any electrical energy permitted to be generated by HCC from time to time from its process unit operations under Section 2.1 above, and (b) at Phillips' option, Electrical Energy in excess of the amount provided under (a) above, up to a total of 90 MW; provided, however, that the Partnership shall deliver up to, but shall not be obligated to deliver more than, the total of Firm Capacity and Interruptible Capacity. Notwithstanding anything to the contrary contained herein, (x) the commitment by Phillips to purchase Electrical Energy is on an HCC requirements basis only, with no minimum amount of Electrical Energy required to be taken by Phillips, and (y) Phillips may at any time purchase any amounts of electrical energy in excess of 90 MW from any third party. 2.2.2 PURCHASE AND SALE OBLIGATION FOR ELECTRICAL CAPACITY. The Partnership shall make available to Phillips, and Phillips shall reserve from the Partnership, the Firm Capacity and the Interruptible Capacity. 2.3 ELECTRICAL PAYMENT. -3- 4 2.3.1 VARIABLE FUEL PAYMENT AND VARIABLE O&M PAYMENT. During the Initial Term or any Phillips Extension Term, for any Electrical Energy delivered to Phillips by the Partnership for each Billing Period, Phillips shall pay the Variable Fuel Payment and the Variable O&M Payment (a) at the rates set forth in Exhibit A, or (b) if a price adjustment has occurred pursuant to Section 2.8, at the rates specified in the Pricing Notice Response. During any Renewal Term for any Electrical Energy delivered to Phillips by the Partnership, Phillips shall pay for Electrical Energy at the price mutually agreed upon between the Parties. 2.3.2 ELECTRICAL CAPACITY PAYMENT. 2.3.2.1 COMMENCEMENT OF FIRM ELECTRICAL CAPACITY PAYMENTS. Phillips shall pay the Partnership, in accordance with the provisions of Section 5.2, the Electrical Capacity Payment. Thirteen (13) months prior to the anticipated Commercial Operation Date, the Partnership shall notify Phillips of the anticipated Commercial Operation Date. Phillips shall use reasonable efforts to terminate any agreements with HL&P for the supply of electrical energy (other than the Standby Agreement) and to arrange for the Standby Agreement to be effective as of such anticipated Commercial Operation Date. Notwithstanding Section 2.1 and Section 5.2, Firm Electrical Capacity Payments shall begin as of the date Phillips is able to terminate payments under the HL&P agreements in effect immediately prior to the Commercial Operation Date. In any event, the Firm Electrical Capacity Payments shall commence no later than thirty (30) days after the Commercial Operation Date. 2.3.2.2 ADJUSTMENTS TO ELECTRICAL CAPACITY PAYMENTS. Phillips shall pay the Electrical Capacity Payments through the Capacity Payment Termination Date; provided, however, that the Electrical Capacity Payment shall be (a) adjusted as provided in a Pricing Notice Response delivered pursuant to Section 2.8.2, or (b) terminated in the event of an HCC Shutdown on the terms described in Section 5.2. During any period when a Force Majeure Event prevents the Partnership from delivering Electrical Energy to Phillips under this Agreement and Phillips is unable to continue to obtain electrical energy under the tariff in effect under the Standby Agreement at the time of the Force Majeure Event, the Partnership shall pay to Phillips the incremental increased -4- 5 demand costs Phillips actually pays under any alternate tariffs as may be applicable in the circumstances over the demand costs otherwise payable by Phillips under the Standby Agreement. If the Partnership fails to make such payments within fifteen (15) days after receipt of an invoice from Phillips together with evidence of payment by Phillips, Phillips may, at its option, offset the amount of the incremental increase in demand payments it actually pays against the Electrical Capacity Payment otherwise due hereunder for such period of time as the Partnership fails to either supply Electrical Energy or reimburse Phillips for its increased demand costs. 2.3.3 PAYMENT FOR USE OF EXCESS ELECTRICAL ENERGY. If at any time Phillips takes Electrical Energy from the Partnership in excess of the total of 80 MVA plus the number of MVA calculated pursuant to Section 2.4.2 of Interruptible Capacity after integrating (averaging) amounts taken over any hour period, Phillips shall pay the Partnership for the exceeded amount the payment specified in Exhibit A. The Partnership shall notify Phillips promptly after such time as the Partnership determines that the electrical capacity of the Project is fully committed. 2.4 INTERRUPTIBLE CAPACITY. 2.4.1 SCHEDULING INTERRUPTIBLE CAPACITY. Phillips shall furnish the Partnership with an annual forecast of its planned daily profile of its electrical requirements not later than December 1st each year for the following calendar year, indicating in such forecast its major planned outages for the year. Phillips may update the annual forecast if any changes in the annual forecast are anticipated. The Partnership shall reserve Interruptible Capacity for the megawatts Phillips indicates it will require in the most recent forecast received by the Partnership at least three (3) days in advance of the effective change in the forecast. 2.4.2 MVA CALCULATION. Interruptible Electrical Capacity Payments for each Billing Period shall be based upon the greater of the following: (a) the number of MVA, on an integrated (averaged) basis during any one-hour period of maximum use above 80 MVA in a Billing Period; (b) the maximum number of MVA requested by Phillips in such Billing Period in the last timely notice received by the Partnership as specified in Section 2.4.1 above; and (c) five (5) MVA. -5- 6 2.5 STANDBY ELECTRICAL AGREEMENT. 2.5.1 STANDBY AGREEMENT. Prior to the Commercial Operation Date, Phillips shall enter into a Standby Agreement pursuant to which Phillips shall have Contingency Failure Protection with regard to electrical energy. Neither Party shall have any liability under a standby agreement entered into by the other. 2.5.2 DEMAND PAYMENT ADJUSTMENT. If Phillips takes electrical energy under the terms of the Standby Agreement, solely because the Partnership failed to keep the Project at a 95% Availability Percentage, resulting in an upward pricing adjustment in the demand payments under the Standby Agreement, the Partnership shall reimburse Phillips for the actual incremental amount of increase in such demand payments Phillips is required to pay as a result of the Project's failure to operate at a 95% Availability Percentage within fifteen (15) days after receipt of a copy of an invoice for any such increased amount and evidence of payment of the applicable amount by Phillips. 2.6 PAYMENT ADJUSTMENT FOR FAILURE TO SUPPLY. 2.6.1 ENERGY PAYMENT ADJUSTMENT. Notwithstanding any other provision of this Agreement, the Partnership is obligated to supply Phillips with Electrical Energy no more than 95% of the time during any COD Year. If the Project does not have Availability to supply Electrical Energy to Phillips, Phillips shall obtain electrical energy pursuant to the terms of the Standby Agreement, and the Partnership shall not be deemed to be in default hereunder for any failure to supply, even if the Project Availability Percentage is less than 95% in a COD Year. The Partnership shall, however, reimburse Phillips for any actual incremental electrical energy costs to Phillips for any COD Year in which the Project fails to achieve 95% Availability by paying Phillips the amount of the Availability Debit for such COD Year; provided that if any Availability Credits have accrued during the applicable Availability Cycle prior to any COD Year in such Availability Cycle in which the Project fails to achieve 95% Availability, such Availability Credits shall be used to offset the Availability Debit otherwise payable to Phillips. -6- 7 2.6.2 REIMBURSEMENT FOR INCREMENTAL COSTS Within thirty (30) days after the end of each COD Year, the Partnership shall determine and advise Phillips of the Availability Percentage of the Project for the preceding year. If the Availability Percentage exceeds 95%, the Partnership shall calculate and record an Availability Credit for such COD Year. If the Availability Percentage is less than 95%, the Partnership shall calculate and pay Phillips the amount of the Availability Debit for such COD Year, after first offsetting the amount of any Availability Credits which may have accrued during the applicable Availability Cycle, but were not used previously as offsets. The Partnership shall pay such amount within forty-five (45) days after the end of the COD Year. 2.7 ADDITIONAL ELECTRICAL ENERGY. If at any time or from time to time, the Project has capacity in excess of 90 MW which has not been sold to Third-Party Purchasers and Phillips requires Electrical Energy in excess of 90 MW, Phillips may purchase Electrical Energy and electrical capacity on terms and conditions negotiated by the Partnership and Phillips at that time; provided, however, the Partnership shall not have any obligation to make Electrical Energy in excess of 90 MW available to Phillips. 2.8 OPTION TO ADJUST PURCHASE OF ELECTRICAL ENERGY AND ELECTRICAL CAPACITY. Notwithstanding any other provision of this Agreement, at any time during the Electrical Option Period, Phillips shall have a one time option to adjust its obligation to purchase from the Partnership all or a portion of its requirements for electrical capacity and electrical energy under this Agreement in accordance with the following provisions. 2.8.1 PRICING NOTICE. At any time during the Electrical Option Period, Phillips may provide the Partnership with a Pricing Notice. Phillips shall deliver a copy of the Electrical Pricing Offer to the Partnership when it delivers the Pricing Notice. Phillips shall not issue more than one Pricing Notice during the Electrical Option Period; provided, however, in the event any Electrical Pricing Offer is withdrawn at any time prior to the issuance of a Pricing Notice Response by the Partnership, Phillips shall have the right to issue another Pricing Notice during the Electrical Option Period. 2.8.2 RIGHT OF FIRST REFUSAL. The Partnership shall have a right of first refusal to match the terms and conditions required to be specified in an Electrical Pricing Offer for a ninety (90) day period after receipt of the Pricing Notice; provided, however, -7- 8 that the Partnership will be deemed to have matched the pricing in the Electrical Pricing Offer if the Partnership's price for energy and capacity as delivered to Phillips at the point of interconnection to HCC is equal to or less than the "all in" price in the Electrical Pricing Offer for energy and capacity as delivered to Phillips at the point of interconnection at HCC (i.e., including all transmission or transportation charges and other charges in the Electrical Pricing Offer in addition to commodity, demand or reservation charges). The Partnership may exercise such right of first refusal by delivering, within the ninety (90) day response period, a Pricing Notice Response to Phillips setting forth the adjusted pricing. Thereafter, the Partnership shall continue to be the exclusive supplier of all required electrical capacity and energy at HCC on and subject to all of the terms and conditions set forth in this Agreement, except that from and after twenty-four (24) months after the Partnership receives the Pricing Notice, the pricing hereunder shall be adjusted to those terms set forth in the Pricing Notice Response for the remainder of the Initial Term. 2.8.3 ADJUSTMENT TERMS. If the Partnership either fails to deliver a Pricing Notice Response within the ninety (90) day response period or notifies Phillips that the Partnership will not issue a Pricing Notice Response, Phillips' obligation to purchase (and the Partnership's obligation to supply) electrical capacity and Electrical Energy hereunder for the number of megawatts specified in the Electrical Pricing Offer shall terminate as of twenty-four (24) months after the Partnership receives the Pricing Notice, and the Firm Electrical Capacity Payment shall be reduced as set forth in Exhibit A for each annual megawatt no longer supplied by the Partnership. In such event, if the Partnership remains obligated to supply any Firm Capacity to Phillips, Phillips shall take its requirements for HCC first from the Partnership, and then from the alternate source. Notwithstanding any termination of the obligation to purchase and supply all or a portion of the electrical capacity and Electrical Energy provided for hereunder, all other provisions of this Agreement shall remain in full force and effect, including the obligation to purchase and supply Electrical Energy and electrical capacity not covered by the Pricing Notice, as well as Steam and Steam capacity on the terms described in Section 3. -8- 9 3. PURCHASE AND SALE OF STEAM AND STEAM CAPACITY 3.1 EXCLUSIVE SOURCE. From and after the Commercial Operation Date and continuing for the remainder of the Term, (a) the Partnership shall sell and deliver to Phillips, and Phillips shall purchase and accept from the Partnership, Steam at the Point of Delivery for Steam, and (b) the Partnership shall make available and Phillips shall reserve steam capacity from the Project, all in accordance with the terms and conditions set forth in this Section 3. Phillips shall not purchase any steam or steam capacity for HCC from any other source, without the consent of the Partnership, except to the extent Phillips requires steam in excess of the Maximum Steam Requirement or during any period when the Partnership does not meet its obligations to supply Steam to Phillips under this Agreement, even if due to a Force Majeure Event. In addition, Phillips shall not purchase or use equipment for the sole purpose of generating steam; provided, however, Phillips may purchase or use any equipment to generate steam derived from the optimization of its process unit operations. 3.2 PURCHASE AND SALE OBLIGATION FOR STEAM AND STEAM CAPACITY. 3.2.1 PURCHASE AND SALE OBLIGATION. The Partnership shall sell and deliver to Phillips, and Phillips shall purchase and accept from the Partnership, all the Steam requirements of HCC up to the Maximum Steam Requirement which are in excess of the amount of steam permitted to be generated by HCC from time to time in connection with process unit operations under Section 3.1 above. Notwithstanding the foregoing, except for a Force Majeure Event or HCC Shutdown, the Partnership shall be obligated to deliver, and Phillips shall be obligated to request, take and productively use not less than the Minimum Steam Requirement, nor more than the Maximum Steam Requirement. Notwithstanding anything to the contrary contained herein, (a) the commitment by Phillips to purchase Steam in excess of the Minimum Steam Requirement is on an HCC requirements basis only, with no other minimum amount of Steam required to be taken by Phillips, and (b) Phillips may at any time purchase any amounts of steam in excess of the Maximum Steam Requirement from any third party. 3.2.2 PURCHASE AND SALE OBLIGATION FOR STEAM CAPACITY. The Partnership shall make available to Phillips, and Phillips shall reserve from the Partnership, steam capacity sufficient to enable the Partnership to deliver Steam up to the Maximum Steam Requirement. -9- 10 3.3 CHARACTERISTICS OF STEAM. The Steam delivered by the Partnership to Phillips at the Point of Delivery for Steam shall conform to the Steam Specifications. 3.4 STEAM PAYMENT. 3.4.1 VARIABLE STEAM PAYMENT. From and after the Commercial Operation Date and continuing for the Initial Term or any Phillips Extension Term, for any Steam delivered to Phillips by the Partnership, for each Billing Period Phillips shall pay the Variable Steam Payment at the rates set forth in Exhibit B attached hereto. During any Renewal Term, for any Steam delivered to Phillips by the Partnership, for each Billing Period Phillips shall pay the Variable Steam Payment mutually negotiated between the Parties. 3.4.2 FIXED STEAM O&M PAYMENT. From and after the Commercial Operation Date and continuing for the Initial Term or any Phillips Extension Term, Phillips shall pay the Fixed Steam O&M Payment on a quarterly basis in accordance with the provisions of Section 5.2; provided, however, the Fixed Steam O&M Payment shall be suspended in accordance with Section 5.2 in the event of an HCC Shutdown. 3.4.3 FIXED STEAM CAPACITY PAYMENT. From the Commercial Operation Date through the Capacity Payment Termination Date, Phillips shall pay the Partnership the Fixed Steam Capacity Payment on a quarterly basis in accordance with the provisions of Section 5.2; provided, however, the Fixed Steam Capacity Payment shall be suspended in accordance with Section 5.2 in the event of an HCC Shutdown. 3.5 ADDITIONAL STEAM REQUIREMENT. If at any time after the Commercial Operation Date the Project has steam capacity in excess of the Maximum Steam Requirement, and Phillips requires such additional steam and steam capacity, Phillips may purchase such amounts on terms and conditions negotiated by the Partnership and Phillips at that time; provided, however, the Partnership shall not have any obligation to provide steam in excess of the Maximum Steam Requirement to Phillips. 4. CONDENSATE RETURN 4.1 TRANSPORTATION OF STEAM AND CONDENSATE. Phillips shall take delivery of and transport Steam from the Point of Delivery for Steam into the HCC steam distribution system and shall maintain a Steam line and a Condensate line properly supported and insulated as required for the -10- 11 transportation of Steam and Condensate within the HCC steam distribution system. The Partnership shall not be under any obligation to inspect, maintain or repair the HCC steam distribution system. 4.2 CONDENSATE RETURN. During any Billing Period, Phillips shall return Condensate which meets the Condensate Return Specifications to the Partnership at the Point of Delivery for Condensate, in an amount equal to approximately fifty percent (50%) of the Steam delivered to Phillips. The Partnership shall monitor the Condensate delivered to the Partnership to determine whether the Condensate meets the Condensate Return Specifications. In the event any Condensate returned by Phillips fails to meet the Condensate Return Specifications, the Partnership shall be under no obligation to accept such Condensate. 4.3 FAILURE TO SUPPLY CONDENSATE. If Phillips fails to return to the Partnership approximately fifty percent (50%) of the Steam delivered to Phillips by the Partnership as Condensate meeting the Condensate Return Specifications, then the Partnership shall, if possible, take and de-mineralize raw water (whether supplied by a third party or is Raw Water supplied by Phillips) in the Partnership's water treatment facility, in amounts sufficient to permit the Partnership to continue to supply Steam and Electrical Energy, to Phillips. The Partnership's sole remedy for Phillips' failure to return to the Partnership approximately fifty percent (50%) of the Steam as Condensate shall be reimbursement (a) for the cost of such additional raw water, and (b) for any additional chemical costs incurred by the Partnership to de-mineralize such raw water. 4.4 OPERATION OF THE STANDBY BOILERS DUE TO PHILLIPS' FAILURE TO SUPPLY RAW WATER AND CONDENSATE. The provisions of this Section 4.4 shall not apply unless Phillips is the sole supplier of raw water to the Project under the Facility Services Agreement. Phillips shall at all times use its Best Commercial Efforts to ensure that the Partnership has sufficient Raw Water to both make Steam and operate the Power Plant at capacity; provided however, Phillips shall have no obligation to provide Raw Water in excess of the maximum amounts required to be supplied under the Facility Services Agreement. If the Partnership must shut down its turbines solely because Phillips has failed to supply sufficient Raw Water in accordance with Phillips' obligations under the Facility Services Agreement and this Agreement, then the Partnership shall use its Best Commercial Efforts to continue to supply Steam sufficient to meet the Steam requirements of HCC by operation of the Standby Boilers; provided, however, Phillips shall pay the Partnership the additional incremental costs for the operation of the Standby Boilers. -11- 12 4.5 INTERRUPTION OF WATER SUPPLY. The Partnership shall have storage capacity at the Project Site sufficient to enable it to supply 200,000 lbs of Steam for at least thirty-six (36) hours after an interruption in the supply of raw water. Under any circumstances, if the interruption in the supply of raw water to the Power Plant is of greater duration, Phillips and the Partnership shall attempt to arrange for the Partnership to obtain water from Phillips to enable the Partnership to continue to make and deliver Steam. 5. BILLING AND PAYMENT 5.1 MONTHLY BILLING CYCLE FOR STEAM, ELECTRICAL ENERGY AND STANDBY. The Partnership shall read the Metering Devices installed pursuant to Section 8.1 monthly, and shall provide Phillips with an invoice for each Billing Period setting forth the amount of Steam and Electrical Energy delivered to Phillips during such Billing Period and the amount of the Variable Fuel Payment, Variable O&M Payment and Variable Steam Payment to be paid by Phillips pursuant to Sections 2.3.1 and 3.4.1 respectively. 5.2 QUARTERLY PAYMENT FOR CAPACITY AND FIXED STEAM O&M. Except as otherwise provided pursuant to Section 2.3.2.1, as of the Commercial Operation Date and thereafter on a quarterly basis, which quarters may, at the option of the Partnership, coincide with the date payment is due to any Project Financing Entities, the Partnership shall invoice Phillips and Phillips shall pay one quarter of the annual Fixed Steam O&M Payment, one quarter of the annual Fixed Steam Capacity Payment, one quarter of the annual Firm Electrical Capacity Payment plus all Interruptible Electrical Capacity Payments payable for the applicable quarter, in arrears, for any whole or partial calendar quarter occurring as of or after the Commercial Operation Date. The Fixed Steam O&M Payment shall be payable during the Initial Term or any Phillips Extension Term. The Fixed Steam Capacity Payment and the Electrical Capacity Payment shall be payable from the Commercial Operation Date through the Capacity Payment Termination Date. If the Commercial Operation Date, the Capacity Payment Termination Date or any termination date of this Agreement does not coincide with the last day of a calendar quarter, the first such payment and/or last such payment, as applicable, shall be prorated on a daily basis over a ninety (90) day period. In the event of an HCC Shutdown, notwithstanding any termination of this Agreement pursuant to Section 17.3, the Fixed Steam O&M Payment, Fixed Steam Capacity Payment and the Electrical Capacity Payment shall continue to be payable through the last day of the calendar year in which the HCC Shutdown occurs, but shall terminate thereafter. -12- 13 5.3 PAYMENT OF INVOICES. Each invoice issued by the Partnership shall be paid by Phillips by electronic funds transfer or by such other means agreed upon by the Parties as will ensure that the Partnership receives such payment in good funds (a) on or before the last day of the month if Phillips receives the invoice prior to the fifteenth (15th) day of the month, or (b) within fifteen (15) days after receipt of an invoice at any later time in the month. If Phillips disputes the correctness of any statement, information or invoice submitted by the Partnership hereunder, Phillips shall promptly submit to the Partnership a written statement detailing the specific items disputed. If the Parties are unable to reach agreement with respect to a disputed item, such dispute shall be subject to further resolution pursuant to the Dispute Resolution Procedures. Notwithstanding the foregoing, if Phillips disputes the correctness of any statement or invoice submitted by the Partnership hereunder, Phillips shall nevertheless make payment on the basis of the undisputed portion of the statement or invoice within the time period specified for payment hereunder. 5.4 INTEREST. Amounts not paid by either Party to the other when due under any provisions of this Agreement, including the provisions of this Section 5, shall bear interest at the Delayed Payment Rate from the date such payment is due until and including the date of payment. 6. OPERATION OF THE PROJECT 6.1 OPERATION OF THE PROJECT. The Parties acknowledge and agree that the Partnership shall delegate the operation and maintenance of the Power Plant to Calpine, and that Calpine or its Affiliates shall be the operator of the Power Plant for at least a six (6) year period after the Commercial Operation Date; provided, however that Phillips shall not unreasonably withhold its consent to another operator during such period if any Project Financing Entity reasonably requests a change in the operator of the Power Plant. The Partnership may delegate the operation and maintenance of the Power Plant after such six (6) year period only if Phillips consents to another operator, which consent shall not be unreasonably withheld. Phillips shall have the absolute right to prohibit a competitor of Phillips from becoming the operator of the Power Plant. Notwithstanding any delegation, the Partnership shall remain responsible to perform its obligations under this Agreement. At all times after the Commercial Operation Date, the Partnership shall operate and manage the Power Plant and the Operating Easement Improvements, and Phillips shall operate and manage the Development and Construction Easement Improvements, in a manner consistent with Prudent Operating Practices. The Partnership shall keep, or cause to be kept, in full force and effect all Applicable Permits which are -13- 14 necessary for the ownership, operation, maintenance, use and repair of the Power Plant and shall comply with, or cause to be complied with, all Laws which are applicable to the Partnership or the Project. 6.2 OPERATING AND COMMUNICATION GUIDELINES. Prior to the Commercial Operation Date, the Parties shall develop written mutually agreeable operating and communication procedures to serve as guidelines for the Parties addressing operating and communication aspects of mutual interest, including communication links between the Parties for supplying information on normal operations, interconnections or separation, switching and equipment clearances, levels of operating voltage and power factors, special procedures required during the testing and initial operation of the Project and scheduling considerations related to both planned and emergency outages of the Project and HCC. Such guidelines shall not override provisions of this Agreement. 6.3 STEAM REDUNDANCY REQUIREMENTS. From and after the Commercial Operation Date and continuing for the remainder of the Term, the Partnership shall provide Phillips with firm standby Steam availability from the Standby Boilers. The Partnership shall operate the Project, including the Standby Boilers, in compliance with the Steam Redundancy Requirements. 6.4 STANDBY BOILERS OPERATING RIGHTS. 6.4.1 EXERCISE OF RIGHTS. The Partnership acknowledges that a reliable supply of Steam is critical to the efficient and safe operation of HCC and agrees that the Project shall be operated in such a manner as to provide a reliable source of Steam to HCC. Phillips shall be entitled to exercise the Standby Boilers Operating Rights during the Term of this Agreement if any of the Partnership, the Project Financing Entities, or any assignee of either (a) fails for any reason to supply Steam in accordance with the terms of this Agreement and the Standby Boilers are capable of operation or (b) decides to no longer supply Steam in breach of its obligations to supply Steam hereunder. If the failure to deliver Steam is the result of clause (a) above, then Phillips shall have the right to immediately exercise the Standby Boilers Operating Rights by sending notice by facsimile to the Partnership at the Power Plant and as provided in Section 21.1, or to such other address as the Partnership may from time to time indicate, and to the Project Financing Entity and any other assignee of which Phillips has received notice, that Phillips has failed to receive Steam and that it intends to promptly exercise the Standby Boilers Operating -14- 15 Rights. If the Partnership is still providing an uninterrupted supply of Steam but decides to no longer supply Steam under clause (b) above, then the Partnership shall immediately notify Phillips in the quickest possible way (in person or telephone), confirmed no later than the next Business Day thereafter in writing, and Phillips shall have the right to exercise the Standby Boilers Operating Rights in advance of the actual cessation of Steam deliveries. 6.4.2 PARTNERSHIP COOPERATION. Upon the exercise by Phillips of the Standby Boilers Operating Rights, the Partnership shall use its Best Commercial Efforts to afford Phillips access to the Project and to assist Phillips to obtain control of the operation of the Standby Boilers to the extent necessary to enable Phillips to exercise the Standby Boilers Operating Rights. 6.4.3 PARTNERSHIP FUEL GAS. During any period that Phillips exercises the Standby Boilers Operating Rights, the Partnership grants Phillips the right, which shall not be construed as an obligation, to utilize the Partnership's supply of fuel gas to the extent available, as reasonably required by Phillips to operate the Standby Boilers. 6.4.4 REMEDIES AND LIABILITIES. The exercise by Phillips of the Standby Boilers Operating Rights shall be in addition to any other remedies available to Phillips hereunder, shall not affect the running of any of the cure periods with respect to an Event of Default, and shall not be deemed an assumption by Phillips of any liability of the Partnership for the period during which Phillips exercises the Standby Boilers Operating Rights. During the exercise of Standby Boilers Operating Rights, Phillips shall operate the Standby Boilers in accordance with Prudent Operating Practices and all Permits and Laws. Phillips shall have no liability to the Partnership for damages to the Standby Boilers during the period Phillips exercises the Standby Boilers Operating Rights unless such damage is caused by the gross negligence or willful misconduct of Phillips or the Permitted Steam Operator(s). In no event shall Phillips' election to exercise the Standby Boilers Operating Rights be deemed to constitute a transfer of title to the Standby Boilers or any of the Partnership's obligations as owner thereof. 6.4.5 REIMBURSEMENT FOR COSTS AND EXPENSES. The Partnership agrees to reimburse Phillips for reasonable labor costs -15- 16 and expenses incurred by Phillips in the exercise of the Standby Boilers Operating Rights. 6.4.6 CESSATION OF STANDBY BOILER OPERATING RIGHTS. Phillips shall have the right to continue to exercise the Standby Boilers Operating Rights until the earlier to occur of (a) such time as the Partnership, its agent or its assignee assumes operational control of the Standby Boilers and provides Steam to Phillips in accordance with the terms of this Agreement, or (b) Phillips obtains another permanent supply of steam for HCC, but in no event longer than two (2) years. 6.4.7 TRAINING. From the Commercial Operation Date and continuing for the remainder of the Term, the Partnership shall annually provide a training class on the operation of the Standby Boilers, at no cost to Phillips, for up to eight Phillips employees or agents as potential Permitted Steam Operators. The Partnership shall not have any obligation to pay labor costs or related expenses for such Phillips employees or agents. 6.5 PHILLIPS REPRESENTATIVE. Phillips shall appoint an individual as the Phillips Representative; provided, however, that Phillips may at any time in its sole discretion by written notice to the Partnership designate a substitute or replacement Phillips Representative. The Phillips Representative shall not have any authority to amend this Agreement. The Phillips Representative shall receive all reports required hereunder and shall be available during normal business hours for consultations with the Partnership Representative and other Partnership personnel. The Partnership shall be entitled to rely upon any consents, approvals or authorizations provided by the Phillips Representative. No directions or approvals given by any Phillips personnel other than the Phillips Representative shall be binding upon Phillips, except that (a) the Phillips Representative may notify the Partnership in writing of any alternate representative who may act in the absence of the Phillips Representative, and (b) the Phillips Representative, by written notice to the Partnership Representative, may designate named individuals who shall have full power and authority to act on behalf of the Phillips Representative with respect to designated areas of responsibility. 6.6 THE PARTNERSHIP REPRESENTATIVE. The Partnership shall appoint an individual as the Partnership Representative; provided, however, that the Partnership may at any time in its sole discretion by written notice to Phillips designate a substitute or replacement Partnership Representative. The Partnership Representative shall not have any -16- 17 authority to amend this Agreement. The Partnership Representative shall receive required reports, and shall be available during normal business hours for consultation with the Phillips Representative and other Phillips personnel. Phillips shall be entitled to rely upon any consents, approvals or authorizations provided by the Partnership Representative. No directions or approvals given by any Partnership personnel other than the Partnership Representative shall be binding upon the Partnership, except that (a) the Partnership Representative may notify Phillips in writing of any alternate representative who may act in the absence of the Partnership Representative, and (b) the Partnership Representative, by written notice to the Phillips Representative, may designate named individuals who shall have full power and authority to act on behalf of the Partnership Representative with respect to designated areas of responsibility. 6.7 OBLIGATION TO PROVIDE AUXILIARY BOILERS. Notwithstanding the provisions of Section 15, in the event the Standby Boilers are no longer capable of operation or cannot supply Steam up to the Maximum Steam Requirement, the Partnership shall within twelve (12) hours after such damage or destruction rent, and advise Phillips that it has rented, auxiliary boilers sufficient to supply Steam up to the Maximum Steam Requirement and that such boilers will be available for operation within seven (7) days. In the event the Partnership fails to rent such auxiliary boilers and notify Phillips as required above, then Phillips shall have the right, on behalf of and at the Partnership's cost and expense, to rent and operate auxiliary boilers sufficient to supply Steam up to the Maximum Steam Requirement. Phillips may offset any such reasonable costs and expenses incurred by it against Fixed Steam O&M and Fixed Steam Capacity Payments due to the Partnership hereunder. The Partnership shall continue to rent auxiliary boilers sufficient to meet the steam requirements of HCC which are not in excess of the Maximum Steam Requirement until the earlier to occur of (a) such time as the Partnership is capable of providing Steam up to the Maximum Steam Requirements of HCC or (b) termination of this Agreement. 7. MAINTENANCE AND REPAIR OF THE PROJECT 7.1 THE PARTNERSHIP'S MAINTENANCE OBLIGATIONS. After the Commercial Operation Date, the Partnership shall keep and maintain the Power Plant in good operating condition, consistent with Prudent Operating Practices, and shall make or cause to be made all repairs and equipment overhauls necessary to keep the Power Plant in such condition. The Partnership shall be responsible, at its expense, for the maintenance, repair and replacement of (a) the Development and Construction Easement Improvements through the Commercial -17- 18 Operation Date and (b) the Operating Easement Improvements, and for keeping such improvements in good operating condition, consistent with Prudent Operating Practices. The Partnership shall repair and restore operation of the Easement Improvements for which it has the responsibility to maintain as soon as reasonably practicable after notice of any failure or damage. Except under emergency circumstances, the Partnership shall use its Best Commercial Efforts to schedule any planned maintenance outages for such Easement Improvements during planned outages for HCC; provided, however, the Partnership shall not be forced to accept a maintenance schedule which would conflict with its obligations to Third Party Purchasers, materially increase maintenance costs or cause damage to the Power Plant. 7.2 PHILLIPS' MAINTENANCE OBLIGATIONS. After the Commercial Operation Date, Phillips shall be responsible, at its expense, for the maintenance, repair and replacement of the Development and Construction Easement Improvements, and for keeping such improvements in good operating condition, consistent with Prudent Operating Practices. Phillips shall repair and restore operation of the Development and Construction Easement Improvements as soon as reasonably practicable after notice of any failure or damage. Except under emergency circumstances, Phillips shall use its Best Commercial Efforts to schedule any planned maintenance outages for the Development and Construction Easement Improvements during planned outages for the Power Plant; provided, however, Phillips shall not be forced to accept a maintenance schedule which would conflict with its obligations to third parties, materially increase maintenance costs or cause damage to HCC. In the event Phillips requires that the Development and Construction Easement Improvements be taken out of service for maintenance, repair or any other reason on an emergency basis, Phillips shall promptly notify the Partnership and shall use its Best Commercial Efforts to minimize any interruption in the delivery of Steam, Condensate or Water while completing such maintenance or repairs. Notwithstanding the foregoing provisions of this Section 7.2, the maintenance costs for the high voltage equipment at HCC substation 1 shall be shared equally between the Parties. 7.3 SCHEDULED MAINTENANCE FOR THE POWER PLANT AND HCC. No later than December 1st of each year the Parties shall exchange production schedules which identify periods for planned outages of the Power Plant and HCC. The Parties shall use their respective Best Commercial Efforts to work together to maximize efficiencies and minimize downtime for maintenance outages at both the Power Plant and HCC. The Parties shall notify each other by telephone as soon as possible concerning the cause and anticipated duration of any forced outage of their respective -18- 19 facilities. Subject to obligations to third parties, whenever possible, the Parties shall coordinate scheduled maintenance requiring outages of the Power Plant and HCC. Neither Phillips nor the Partnership shall be forced to accept a maintenance schedule which would conflict with its obligations to third parties, materially increase maintenance costs or cause damage to the Power Plant, the Easement Improvements or HCC. 7.4 INSPECTION AND OBSERVATION RIGHTS. At any time, upon reasonable advance notice and the availability of the Project Site manager or a designee to accompany Phillips, and provided the Partnership has approved the names of the Phillips authorized representatives, Phillips and its authorized representatives shall have the right to enter upon the Project Site and to obtain access to the Power Plant to inspect and observe the operation and condition of the Power Plant. Any inspection by Phillips shall not relieve the Partnership of any of its obligations under the Project Agreements. Pursuant to the terms of the Project Agreements, upon reasonable advance notice, the availability of the HCC Site general manager or a designee to accompany the Partnership, and provided Phillips has approved the names of the Partnership's authorized representatives, the Partnership and its authorized representatives shall have the right to enter upon the HCC Site and to obtain access to the Development and Construction Easement Improvements to inspect and observe the operation and condition of such facilities. Any inspection by the Partnership shall not relieve Phillips of any of its obligations under the Project Agreements. 8. METERING 8.1 METERING DEVICES. At the Partnership's expense, the Partnership shall install or cause to be installed the Metering Devices for determining the quantity (and any other parameters deemed appropriate by the Partnership and Phillips) of the Steam and Electrical Energy delivered by the Partnership under this Agreement. All such Metering Devices shall be owned and maintained by the Partnership. Phillips shall provide the Partnership adequate space for those Metering Devices which are to be installed at the HCC Site. 8.2 PERIODIC INSPECTION. The Partnership shall inspect and test all Metering Devices upon installation thereof. In addition, on an annual basis thereafter or upon the request of Phillips, the Partnership shall inspect and test each Metering Device and shall provide Phillips reasonable advance notice of, and shall permit an authorized representative of Phillips to be present at, any such inspection or test. The cost and expense of any such inspection or test shall be paid by the -19- 20 Partnership. If a Metering Device is found to be defective or inaccurate, it shall promptly be adjusted, calibrated, repaired or replaced by the Partnership at the Partnership's cost and expense. If at any time Phillips desires to independently test the Metering Devices, Phillips shall have the right to test a Metering Device upon reasonable advance notice to the Partnership and upon the availability of the Project Site manager or a designee to accompany Phillips. Phillips shall bear the cost of any such testing if the Metering Device is determined to be accurate within the tolerances indicated in Section 8.3, but the Partnership shall otherwise bear the cost of such testing. 8.3 RETROACTIVE ADJUSTMENTS. If a Metering Device fails to register, or if the measurement made by a Metering Device is found upon testing to be inaccurate by an amount exceeding plus or minus two percent (2%) of full scale with respect to a Metering Device measuring Steam, or by an amount exceeding plus or minus one half of one percent (.5%) with respect to a Metering Device measuring Electrical Energy, an adjustment shall be made correcting all measurements of Steam and Electrical Energy made by the inaccurate or defective Metering Device during the Adjustment Period. If the Parties are unable to agree on the amount of the adjustment to be applied to the Adjustment Period, the amount of the adjustment shall be determined (a) by correcting the error if the percentage of error is ascertainable by calibration, tests or mathematical calculation, or (b) if not so ascertainable, by estimating on the basis of deliveries under similar conditions during periods when the Metering Device was registering accurately. Upon the determination of the amount of any adjustment, Phillips shall pay to the Partnership any additional amounts then due for deliveries of Steam or Electrical Energy during the Adjustment Period at such time as other payments are due for the Billing Period in which the determination is made, or Phillips shall be entitled to a credit against the next subsequent payments due for deliveries of Steam or Electrical Energy, whichever case is applicable. 8.4 ACCESS TO METERING DEVICES. Pursuant to the terms of the Project Agreements, upon reasonable advance notice, the availability of the HCC Site general manager or a designee to accompany the Partnership, and provided Phillips has approved the names of the Partnership's authorized representatives, the Partnership and its authorized representatives shall have the right to enter upon the HCC Site and to obtain access to the Metering Devices owned and maintained by the Partnership on the HCC Site to read, inspect, test, repair and remove such Metering Devices. 9. REVIEW MEETINGS -20- 21 After the Commercial Operation Date, unless otherwise mutually agreed by the Parties, the Partnership shall conduct a quarterly Review Meeting with Phillips to discuss information pertinent to the operation or maintenance of the Project or any other matters pertinent to the performance of the Parties under the Project Agreements. Review Meetings shall take place at the Project Site, unless otherwise agreed by the Phillips Representative and the Partnership Representative. 10. SALES TO THIRD PARTY PURCHASERS The Parties acknowledge that the Power Plant is intended to have an aggregate generating capacity in excess of the Firm Capacity and Interruptible Capacity committed to Phillips pursuant to this Agreement. The Partnership shall be entitled at any time, in its sole discretion, to make deliveries and sales of such excess electrical energy and electrical capacity from the Power Plant to HL&P and other Third-Party Purchasers under short-term or long-term arrangements. The Partnership shall have sole responsibility for the marketing and sale of such electrical energy and electrical capacity to HL&P and Third-Party Purchasers. Any sales to Third-Party Purchasers shall be consistent with the Partnership's obligations under this Agreement and shall not adversely affect deliveries of Electrical Energy or Firm Capacity and Interruptible Capacity to Phillips hereunder. 11. TERM OF AGREEMENT 11.1 TERM. This Agreement shall be in effect for the Initial Term and any Renewal Term or Phillips Extension Term, unless terminated earlier in accordance with the other provisions of this Agreement. 11.2 RENEWAL TERM. Three (3) years prior to the end of the Initial Term, the Parties shall meet and negotiate for such terms, conditions and pricing for the renewal of the Project Agreements as may be mutually acceptable to the Parties. If the Parties reach a mutual agreement on the terms, conditions and pricing for extending the Initial Term of the Project Agreements, then the Project Agreements shall be extended on such negotiated terms for a Renewal Term. 11.3 PHILLIPS EXTENSION TERM. In the event the Parties can not reach mutual agreement under Section 11.2, then Phillips shall have the option, exercisable by delivering a written notice to the Partnership no later than two (2) years prior to the end of the Initial Term, to extend the Initial Term of all of the Project Agreements in effect as of the last day of the Initial Term for the Phillips Extension Term upon the same terms and conditions as are applicable as of the end of the Initial Term, except that the price for Electrical Energy and Steam shall not include the Electrical Capacity Payment or Fixed Steam Capacity Payment. If during the Electrical Option Period Phillips exercised the option to adjust as set forth in Section 2.8, the Partnership shall notify Phillips of any -21- 22 uncommitted electrical energy and electrical capacity up to 90 MW which may become available during the Phillips Extension Term and the Parties may negotiate regarding the price of any such electrical energy and capacity. If Phillips does not elect to extend the Project Agreements for the Phillips Extension Term, the Term of this Agreement shall end upon the expiration or other termination of the Initial Term. 12. INSURANCE 12.1 INSURANCE COVERAGES. From after the earlier of Financial Closing or the Equity Commitment Date, the Partnership shall, at all times during the Term of this Agreement or any other Project Agreement, provide and maintain the types and amounts of insurance as set forth in this Section 12. In the event any insurance (including the limits thereof) hereby required to be maintained is not reasonably available or obtainable on a commercially reasonable basis in the commercial insurance market, the Partnership may request Phillips to agree that such requirements be reduced or eliminated for a specified period, and Phillips shall not unreasonably withhold its agreement to waive such requirements for the specified period. The Partnership shall procure at its own expense, and shall maintain in full force and effect during the Term of this Agreement or any other Project Agreement (or as otherwise provided in this Section 12) with insurance carriers (with the exception of captive insurance companies used as provided in Section 12.8) having an A.M. Best rating of B++VII or better or of recognized responsibility satisfactory to Phillips, the types and amount of insurance and with limits and coverages no less than those set forth below. 12.1.1 WORKERS' COMPENSATION INSURANCE. Workers' Compensation insurance as required by state laws, and Employer's Liability (including Occupational Disease) coverage with limits of One Million Dollars ($1,000,000). 12.1.2 COMMERCIAL GENERAL LIABILITY INSURANCE. Commercial General Liability insurance with a combined single limit of not less than One Million Dollars ($1,000,000) per occurrence. Such coverage shall include Premises/Operations, Broad Form Property Damage and Personal Injury, Products-Completed Operations, Explosion, Collapse and Underground Hazards coverage, Broad Form Contractual Liability and Independent Contractors Liability. 12.1.3 AUTOMOBILE LIABILITY INSURANCE. Automobile Liability Insurance including coverage for owned, non-owned and hired -22- 23 automobiles with a combined single limit of not less than One Million Dollars ($1,000,000) per occurrence. 12.1.4 EXCESS/UMBRELLA LIABILITY INSURANCE. Excess/Umbrella Liability insurance covering claims in excess of the underlying insurance described in Sections 12.1.1 through 12.1.3, with a combined single limit of Twenty-Nine Million Dollars ($29,000,000) per occurrence. The amounts of insurance required in Sections 12.1.1 through 12.1.4 may be satisfied by purchasing coverage in the amounts specified or by any combination thereof, so long as such insurance meets the requirements specified herein. 12.2 ENDORSEMENTS. All policies of insurance described in Sections 12.1.1 through 12.1.4 to be maintained by the Partnership shall be written or endorsed as follows: 12.2.1 WAIVER OF SUBROGATION. With respect to Workers' Compensation/Employer's Liability Insurance, to provide that the insurer (a) shall waive for the benefit of Phillips (i) all rights of subrogation against Phillips, its Affiliates, co-venturers, or their directors, officers, employees or agents, for payment under such policies, (ii) any right of set-off and counterclaim, and (iii) any other right to deduction whether by attachment or otherwise by any Person to or for whom the insurer pays monies or other benefits, and (b) in the event and to the extent that the Parties agree that such provisions are available on commercially reasonable terms, shall assign and relinquish to Phillips such rights of recovery, including any rights of liens; 12.2.2 SEVERABILITY. To provide a severability of interest of the cross liability clause; 12.2.3 PRIMARY COVERAGE. That the insurance shall be primary and not excess to or contributing with any insurance or self-insurance maintained by Phillips; and 12.2.4 ADDITIONAL INSURED. With the exception of the insurance required under Section 12.1.1, to name Phillips, its Affiliates and co-ventures at HCC, and their directors, officers, employees and agents, as additional insureds with respect to any injury or damage arising from any work or services performed by the Partnership, its Affiliates, their contractors or agents under the Project Agreements or the presence of the Partnership, its Affiliates, their contractors or agents, on Phillips' premises. -23- 24 12.3 ALL-RISK PROPERTY INSURANCE. 12.3.1 BUILDER'S ALL-RISK INSURANCE AND ALL-RISK PROPERTY AND BOILER AND MACHINERY INSURANCE. The Partnership shall procure and maintain at its own expense (a) Builder's All-Risk Insurance covering physical loss or damage to the Project and its assets (without an exclusion for resultant damage from defective materials and parts and with limits not less than the full replacement value of the Project, including all assets on or off the Project Site or in transit) and (b) effective upon the Commercial Operation Date, All-Risk Property and Boiler and Machinery insurance covering physical loss or damage during the operation of the Project. The All-Risk Property and Boiler and Machinery insurance shall not contain an exclusion for resultant damage from defective materials and parts. Such insurance shall have limits not less than the Estimated Maximum Loss of the Project and shall include coverage for Three Million Dollars ($3,000,000) for extra expense which would be incurred by the Partnership in supplying an alternate source of steam to Phillips in the event such steam was not available from the Project. 12.3.2 WAIVER OF SUBROGATION. The insurance required in this Section 12.3 shall be (a) written or endorsed to provide for a waiver of subrogation for the benefit of Phillips, its Affiliates or co-venturers at HCC, and their directors, officers, employees and agents, and (b) provided by insurance carriers with an A.M. Best rating of B++VII or shall be of recognized responsibility satisfactory to Phillips. 12.4 CONTRACTORS AND SUBCONTRACTORS. The Partnership shall at all times during the Term of this Agreement or any other Project Agreement, cause every contractor or subcontractor employed by the Partnership to carry insurance of types and amounts necessary to cover risks inherent in the work or services being performed by such contractors or subcontractors. Coverages for completed operations under the Commercial General Liability insurance provided by the prime general contractor and its subcontractors during the construction of the Project shall remain in effect for a period of at least two (2) years following the Commercial Operation Date. Alternatively, the Partnership may arrange any or all insurance policies on behalf of the contractors and subcontractors. When requested by Phillips, the Partnership shall furnish Phillips with certificates of insurance evidencing coverage for each contractor and subcontractor. -24- 25 12.5 PHILLIPS INSURANCE COVERAGES. At all times during the Term of this Agreement or any other Project Agreement, Phillips, its Affiliates and co-venturers, and insurers shall waive (a) any right of recovery which Phillips or the insurer may have or acquire against the Partnership, its Affiliates, or their directors, officers, employees or agents, for payment under those policies or coverages set forth below and (b) any right of subrogation which Phillips or the insurers may have or acquire for payments to any Person who asserts a claim against the Partnership, its Affiliates, or their directors, officers, employees or agents, by any Person to or for whom the insurer pays monies or other benefits: 12.5.1 WORKERS' COMPENSATION INSURANCE. Workers' Compensation Insurance as required by state law and Employer's Liability Insurance (including Occupational Disease) coverage with limits of One Million Dollars ($1,000,000). 12.5.2 COMMERCIAL GENERAL LIABILITY INSURANCE. Commercial General Liability Insurance with a combined single limit of not less than One Million Dollars ($1,000,000) per occurrence. Such coverage shall include Premises/Operations, Broad Form Property Damage and Personal Injury, Products-Completed Operations, Explosion, Collapse and Underground Hazards coverage, Broad Form Contractual Liability and Independent Contractors Liability. 12.5.3 AUTOMOBILE LIABILITY INSURANCE. Automobile Liability insurance, including coverage for owned, non-owned and hired automobiles with a combined single limit of not less than One Million Dollars ($1,000,000) per occurrence. 12.5.4 EXCESS/UMBRELLA LIABILITY INSURANCE. Excess/Umbrella Liability insurance covering claims in excess of the underlying insurance described in Sections 12.5.1 through 12.5.3 with a combined single limit of Twenty-Nine Million Dollars ($29,000,000) per occurrence. 12.5.5 PROPERTY INSURANCE. All-Risk Property Insurance which shall cover assets at HCC in an amount of not less than Two Hundred Million Dollars ($200,000,000). Phillips shall have the right to self-insure any or part of the coverage shown in this Section 12.5. In the event the long term senior unsecured debt securities of Phillips fall below both BBB- by Standard & Poor's Corporation and Baa3 by Moody's Investors Service, Phillips will procure insurance in excess of One Million Dollars ($1,000,000) up to Phillips' insurance captive's then full retentions -25- 26 from insurers not affiliated with Phillips which have a Best rating of no less than A-10. 12.6 EVIDENCE OF INSURANCE. Prior to the initiation or performance of any work or services under the Project Agreements, the Partnership and Phillips shall furnish to each other certificates of insurance from each insurance carrier showing that the above required insurance and endorsements are in full force and effect, the amount of the carrier's liability thereunder, and further providing that the insurance will not be canceled, materially changed or not renewed until the expiration of at least thirty (30) days (or ten (10) days in the case of cancellation due to non-payment of premiums) after written notice of such cancellation, material change or nonrenewal has been received by Phillips or the Partnership, respectively; provided, however, that in the event and to the extent that Phillips, in its sole discretion, shall self-insure any such coverages, Phillips shall provide to the Partnership written notice of such self-insurance. 12.7 DISCLAIMER. The insurance requirements set out in this Section 12 are not a representation that the coverage and limits provided thereby are sufficient to protect the interest of the Partnership or Phillips and shall not be deemed as a limitation on the Partnership's or Phillips' liability. 12.8 PLACEMENT OF INSURANCE COVERAGE WITH CAPTIVE. 12.8.1 PHILLIPS' CAPTIVE INSURER. Phillips shall have the right to use its wholly-owned captive insurance company to insure or reinsure part of all of the coverage shown in Section 12.5. Such captive insurance company shall maintain capital and surplus of at least One Hundred Million Dollars ($100,000,000) throughout the period during which the captive insurance company shall provide coverage to Phillips. Audited annual reports for the captive insurance companies shall be provided at the request of the Parties or of a Project Financing Entity each year. 12.8.2 THE PARTNERSHIP'S CAPTIVE INSURER. The Partnership shall have the right to use its wholly-owned captive insurance company, if any, to insure or reinsure part of all of the coverage shown in Section 12.1. Such captive insurance company shall maintain capital and surplus of at least One Hundred Million Dollars ($100,000,000) throughout the period during which the captive insurance company shall provide coverage to the Partnership. Audited annual reports for the captive insurance companies shall be provided at the request of the Parties or of a Project Financing Entity each year. -26- 27 13. INDEMNIFICATION 13.1 RELEASE AND INDEMNIFICATION BY THE PARTNERSHIP. Subject to the limitation set forth in Section 13.4, the Partnership shall release, indemnify, defend and hold Phillips, its Affiliates, and each of their employees, directors and agents, harmless from and against any and all damages, liabilities, expenses and costs (including court costs and reasonable attorneys' fees) as a result of any claims, demands, suits, causes of action, proceedings or judgments for (a) any damage to or loss of property (including the Project) of the Partnership, its Affiliates, or any of the Partnership's partners (excluding Phillips if it is a partner) or (b) any personal injury or death to any of the employees, contractors, agents or Invitees of the Partnership, its Affiliates, or any of the Partnership's partners (excluding Phillips if it is a Partner); provided, however, that such indemnity and release shall not apply to any damage to land or water which is the subject of the environmental indemnity provisions in the Ground Lease and Easement Agreement. 13.2 RELEASE AND INDEMNIFICATION BY PHILLIPS. Subject to the limitation set forth in Section 13.4, Phillips shall release, indemnify, defend and hold the Partnership, its Affiliates, any of the Partnership's partners and each of their employees, directors and agents harmless from and against any and all damages, liabilities, expenses and costs (including court costs and reasonable attorneys' fees) as a result of any claims, demands, suits, causes of action, proceedings or judgments for (a) any damage to or loss of property (including HCC) of Phillips or its Affiliates or (b) of any personal injury or death to any of the employees, contractors, agents or Invitees of Phillips or its Affiliates; provided, however, that such indemnity and release shall not apply to any damage to land or water which is the subject of the environmental indemnity provisions in the Ground Lease and Easement Agreement. 13.3 COMPREHENSIVE CONSTRUCTION AND APPLICATION. THE PARTIES HEREBY EXPRESS THEIR INTENT THAT THE RELEASES OF LIABILITY AND INDEMNITIES CONTAINED IN SECTIONS 13.1 AND 13.2 ABOVE BE LIBERALLY CONSTRUED. SUCH RELEASES OF LIABILITY AND INDEMNITIES SHALL APPLY TO ANY LOSS, DAMAGE, DEFECT, PERSONAL INJURY OR DEATH: (A) WHICH ARISES FROM THE PERFORMANCE OF THE PROJECT AGREEMENTS; AND (B) WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF, INCLUDING, WITHOUT LIMITATION, UNSEAWORTHINESS, STRICT LIABILITY, BREACH OF WARRANTY (EXPRESS OR -27- 28 IMPLIED), IMPERFECTION OF MATERIALS, CONDITION OF ANY PREMISES OR TRANSPORT TO OR FROM SUCH PREMISES, OR THE NEGLIGENCE OF THE INDEMNITEE (OR RELEASED PARTY) OR ITS EMPLOYEES, AGENTS AND INVITEES, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, ACTIVE OR PASSIVE; AND (C) WHETHER THE CLAIM THEREFOR IS BASED ON COMMON LAW, CIVIL LAW, MARITIME LAW, STATUTE OR CONTRACTUAL OBLIGATION BETWEEN THE INDEMNITEE AND A THIRD PARTY. 13.4 LIMITATION ON INDEMNITIES. Notwithstanding anything to the contrary contained herein, it is expressly agreed that liability under the indemnities and releases contained in Section 13.1 and 13.2 (including the obligation for attorneys' fees and costs of defense) arising out of any single occurrence which directly or indirectly results in coverage relating to personal injury to or death of employees, agents, contractors, their respective employees or Invitees, shall be limited to Seven Million Five Hundred Thousand Dollars ($7,500,000). If in the course of defense by either Party or any claims subject to this Section 13.4, a Party believes its potential liability under the indemnities set forth in Section 13.1 or 13.2, as applicable, is likely to exceed the Seven Million Five Hundred Thousand Dollar ($7,500,000) limitation, said Party shall have the option of notifying the other Party that it will unconditionally agree to pay the other Party the first Seven Million Five Hundred Thousand Dollars ($7,500,000) of damages, liabilities, expenses and costs (including but not limited to court costs and attorneys' fees). The notifying Party shall transfer the defense of all pending suits and claims subject to this Section 13.4 to the other Party, and will cooperate in arranging for an orderly transition in responsibility for handling such suits and claims. The other Party shall, at its option, be entitled to require that the notifying Party provide security in a form satisfactory to the other Party to guarantee payment of the Seven Million Five Hundred Thousand Dollars ($7,500,000) less any amount of damages, liabilities, expenses and costs already incurred by the notifying Party (all of which will be credited against this Seven Million Five Hundred Thousand Dollar ($7,500,000) maximum payment under the indemnities and releases contained in Sections 13.1 and 13.2). To the extent any amount of damages, liabilities, expenses and costs exceed the limitation set forth in this Section 13.4, the Parties shall rely upon such rights and remedies as they may have at law or in equity. 13.5 PROPERTY DAMAGE EXCLUSION. Notwithstanding the provisions of Sections 13.1 and 13.2, each Party shall be liable to the extent of its -28- 29 negligence for damage to the property of the other Party or its Affiliates for the first One Hundred Thousand Dollars ($100,000) per occurrence. 13.6 MUTUAL INDEMNIFICATION FOR BREACH OF REPRESENTATIONS; FINES AND PENALTIES. 13.6.1 PARTNERSHIP INDEMNIFICATION. The Partnership shall indemnify, defend and hold Phillips, its Affiliates, and each of their employees, directors and agents, harmless from and against any and all (i) damages, liabilities, expenses and costs (including court costs and reasonable attorneys' fees) as a result of any claims, demands, suits, causes of action, proceedings or judgments arising as a result of the breach of any of the representations and warranties made by the Partnership herein, or (ii) any and all fines or penalties (criminal or civil) or other liabilities, expenses and costs (including court costs and reasonable attorneys' fees) incurred or paid as a result of any claims, demands, suits, causes of action, proceedings or judgments made or asserted by any Person against Phillips, its Affiliates, or any of their employees, directors or agents, for failure of the Partnership to comply with any applicable Law or Permit related to the performance of the obligations of the Partnership, its Affiliates, or their employees, contractors or agents, under the Project Agreements or arising out of or otherwise related to the operation of the Project; provided, however, that such indemnity shall not apply to the extent that such fine, penalty or other liability, expense or cost results from any environmental matter which is the subject of the environmental indemnity provisions in the Ground Lease and Easement Agreement. 13.6.2 PHILLIPS INDEMNIFICATION. Phillips shall indemnify, defend and hold the Partnership, its Affiliates, and each of their employees, directors and agents, harmless from and against any and all (i) damages, liabilities, expenses and costs (including court costs and reasonable attorneys' fees) as a result of any claims, demands, suits, causes of action, proceedings or judgments arising as a result of the breach of any of the representations and warranties made by Phillips herein, or (ii) any and all fines or penalties (criminal or civil) or other liabilities, expenses and costs (including court costs and reasonable attorneys' fees) incurred or paid as a result of any claims, demands, suits, causes of action, proceedings or judgments made or asserted by any Person against the Partnership, its Affiliates, or any of their employees, -29- 30 directors or agents, for failure of Phillips to comply with any applicable Law or Permit related to the performance of the obligations of Phillips, its Affiliates, or their employees or agents, under the Project Agreements or arising out of or otherwise related to the operation of HCC; provided, however, that such indemnity shall not apply to the extent that such fine, penalty or other liability, expense or cost results from any environmental matter which is the subject oF environmental indemnity provisions in the Ground Lease and Easement Agreement. 13.7 EXCLUSIONS FROM RELEASES AND INDEMNITIES. Notwithstanding anything to the contrary contained herein, the releases of liabilities and indemnifications contained in Sections 13.1, 13.2 and 13.6 above and Section 2.7.3 of the Ground Lease and Easement Agreement shall not apply to awards or assessment of punitive damages and may not be relied upon by a Party to the extent that any claim or liability was caused by the willful misconduct of such Party. 13.8 NOTICE OF LEGAL DEFENSE. After receipt of notice of the commencement of any legal action or claim against a Party as to which the indemnities in this Section 13 may apply, the indemnified Party shall provide reasonably prompt written notice to the indemnifying Party; provided, however, that the failure of the indemnified Party to provide such reasonably prompt notice shall not relieve the indemnifying Party of any obligations under this Section 13, but shall only reduce the liability of the indemnifying Party by the amount of damages attributable to the failure of the indemnified Party to give such reasonably prompt notice. After receipt of such notice, the indemnifying Party may, or if so requested by such indemnified Party shall, assume the defense of such claim or legal action without any reservation of rights and with counsel reasonably satisfactory to the indemnified Party. The indemnifying Party shall control the settlement of all claims over which it has assumed defense; provided, however, that the indemnifying Party shall not conclude any settlement which requires any action or forbearance from action by the indemnified Party or any of its Affiliates without the prior written approval of the indemnified Party. In connection with any such legal action or claim, when requested the indemnified Party shall provide reasonable assistance, at the indemnifying Party's expense, to the indemnifying Party. In all cases the indemnified Party shall have the right to participate in and be represented by counsel of its own choice and at its own expense in any such legal action or claim. 13.9 APPLICATION OF INDEMNITIES. Except as specifically provided in Sections 13.1, 13.2 and 13.6 above, the indemnities and releases provided in this Section 13 shall be in addition to and not in derogation -30- 31 or substitution of the releases or indemnifications provided elsewhere in the Project Agreements. 13.10 SURVIVAL. The provisions of this Section 13 shall survive the termination or expiration of the Project Agreements. 14. LIABILITY; NO DEDICATION 14.1 THIRD PARTIES. Except as otherwise expressly provided in Section 13, nothing in this Agreement shall be construed to create any duty to, standard of care with respect to, or any liability to, any Person who is not a party to this Agreement. 14.2 NO DEDICATION. No undertaking by either Party under any provision of this Agreement shall constitute the dedication of that Party's electrical or transmission system, equipment or facilities, or any portion thereof, to the other Party or to the public, or affect the status of Phillips or of the Partnership as an independent private entity and not a public utility. 14.3 NO PARTNERSHIP. Nothing contained in this Agreement shall be construed to create as between Phillips and the Partnership an association, trust, partnership, joint venture, association taxable as a corporation or other entity for the conduct of any business for profit, or impose a trust or partnership duty, obligation or liability or agency relationship on, or with regard to, either Party. Each Party shall be individually and severally liable for its own obligations under this Agreement. 14.4 NO CONSEQUENTIAL DAMAGES. The Parties agree that it is the intent that notwithstanding anything to the contrary contained in Section 14.5, neither Phillips nor the Partnership, nor their respective officers, directors, partners, shareholders, agents, employees, contractors or Affiliates, shall be liable to the other Party or to its Affiliates, officers, directors, shareholders, partners, agents, employees, successors or assigns, for claims for incidental, special, indirect, punitive or consequential damages of any nature connected with or resulting from performance or non-performance of this Agreement, including claims in the nature of lost revenue, income or profits, irrespective of whether such claims are based upon negligence, strict liability, contract, operation of law or otherwise; provided, however, nothing in the foregoing shall limit the obligation of a party to indemnify the other party (the "Indemnitee") with respect to claims against the Indemnitee under indemnities of the Indemnitee in favor of its lenders and contractors to the extent such claims are otherwise within the terms of Section 13.1 or Section 13.2 (as applicable) hereof. Notwithstanding the foregoing, it is specifically intended by the Parties that, subject to the duty to mitigate, -31- 32 direct damages incurred as a result of a breach of the Project Agreements, including payments, costs and expenses required under the Project Agreements are not to be construed as consequential damages or otherwise restricted hereunder. 14.5 INTENT. Except in cases of willful misconduct, the Parties intend that the waivers and disclaimers of liability, releases from liability, limitations and apportionments of liability, and remedy provisions expressed throughout this Agreement shall apply even in the event of the fault, negligence (in whole or in part), strict liability or breach of contract of the Party released or whose liability is waived, disclaimed, limited, apportioned or fixed by such remedy provision, and shall extend to such Party's Affiliates and to its and their partners, shareholders, directors, officers, employees, contractors and agents. The Parties also intend and agree that such provisions shall continue in full force and effect notwithstanding the termination, suspension, cancellation or rescission of this Agreement, or of any other agreement entered into pursuant hereto. 15. FORCE MAJEURE 15.1 EXCUSED PERFORMANCE. Each Party shall be excused from performance hereunder and shall not be considered to be in default or be liable in damages or otherwise with respect to any obligation hereunder, except the obligation to pay money in a timely manner for liabilities actually incurred, if and to the extent that its failure of, or delay in, performance is due to a Force Majeure Event; provided, that: (a) Such Party gives the other Party written notice describing the particulars of the Force Majeure Event, including the expected duration, as soon as is reasonably practicable, but in no event later than ten (10) days after the occurrence of such event; (b) The suspension of performance is of no greater scope and of no longer duration than is reasonably required by the Force Majeure Event; (c) The Party affected by the Force Majeure Event uses its Best Commercial Efforts to mitigate the effects thereof; (d) No obligations of the Party which arose before the occurrence causing the suspension of performance are excused as a result of the occurrence; and (e) When the Party is able to resume performance of its obligations under this Agreement, such Party shall give the other -32- 33 Party written notice to that effect and shall promptly resume performance hereunder. 15.2 BURDEN OF PROOF. If the Parties are unable in good faith to agree that a Force Majeure Event has occurred, the Parties shall submit the dispute for resolution in accordance with the Dispute Resolution Procedures, and the Party claiming a Force Majeure Event shall have the burden of proof as to whether such Force Majeure Event has occurred. 15.3 TERMINATION FOR FORCE MAJEURE. 15.3.1 RIGHT TO TERMINATE. (a) Either Party may terminate this Agreement with respect to the purchase and sale of Electrical Energy upon thirty (30) days written notice if, following the Commercial Operation Date, a Force Majeure Event (other than as set forth in Section 15.3.2) hereunder prevents either Party from substantial performance of its obligations hereunder with respect to the purchase and sale of Electrical Energy for a continuous period of one (1) year. (b) Either Party may terminate this Agreement with respect to the purchase and sale of Steam upon thirty (30) days written notice if, following the Commercial Operation Date, a Force Majeure Event (other than as set forth in Section 15.3.2) hereunder prevents either Party from substantial performance of its obligations hereunder with respect to the purchase and sale of Steam for a continuous period of one (1) year. 15.3.2 DESTRUCTION OR SUBSTANTIAL DAMAGE TO THE POWER PLANT OR HCC AS THE FORCE MAJEURE EVENT. If destruction or substantial damage to the Power Plant or HCC is a Force Majeure Event hereunder, and a Party is prevented from substantially performing its obligations hereunder for a continuous period of two (2) years, then either Party may terminate this Agreement upon thirty (30) days written notice; provided, however, if the Partnership does not complete the rebuilding of the Power Plant as required pursuant to Section 17.4 and elects to terminate this Agreement pursuant to this Section 15.3.2, then the Partnership shall pay to Phillips the Termination Fee, if applicable, pursuant to Section 17.4. 15.3.3 MITIGATION PLAN. Notwithstanding the foregoing, this Agreement shall not be terminated as set forth above if the Party prevented from performing its obligations is unable, -33- 34 despite the use of its Best Commercial Efforts, to overcome the effects of such Force Majeure Event during such one (1) or two (2) year period, as the case may be, but nonetheless has demonstrated to the reasonable satisfaction of the other Party that (a) it is pursuing a plan approved by the other Party to overcome the effects of the Force Majeure Event and resume performance of its obligations hereunder, (b) it is diligently applying its Best Commercial Efforts to overcome the effects of the Force Majeure Event, and (c) the Force Majeure Event can be overcome within a reasonable time after the expiration of either the one (1) or two (2) year period, as the case may be. 16. EVENTS OF DEFAULT 16.1 DEFINITION. An Event of Default under this Agreement shall be deemed to exist with respect to a Party upon the occurrence of any one or more of the following events: (a) Failure by a Party hereunder to make payment of any amount due to the other Party under this Agreement, which failure continues for a period of ten (10) days after receipt of written notice of such nonpayment, unless such amount is in dispute, in which case the Dispute Resolution Procedures shall apply; (b) Failure by a Party hereunder to perform fully any other material obligation under this Agreement, if such Party does not cure such failure within sixty (60) days of the date of receipt of a notice from the other Party demanding such cure (or within such longer period of time, as is reasonably necessary to accomplish such cure, if it cannot be reasonably accomplished within such sixty (60) day period and such Party diligently commences such cure in such period and continues such cure to completion); (c) Failure by a Party hereunder to comply with the terms of any final decision or order issued pursuant to the Dispute Resolution Procedures, if such Party does not cure such failure within sixty (60) days of the date of receipt of a notice from the other Party demanding such cure (or within such longer period of time, as is reasonably necessary to accomplish such cure, if it cannot be reasonably accomplished within such sixty (60) day period and such Party diligently commences such cure in such period and continues such cure to completion); (d) If by order of a court of competent jurisdiction, a receiver or liquidator or trustee of a Party or of any of the property of a Party shall be appointed, and such receiver or liquidator or trustee shall -34- 35 not have been discharged within a period of sixty (60) days; or if by decree of such a court, a Party shall be adjudicated bankrupt or insolvent or any substantial part of the property of such Party shall have been sequestered, and such decree shall have continued undischarged and unstayed for a period of sixty (60) days after the entry thereof; of if a petition to declare bankruptcy or to reorganize a Party pursuant to any of the provisions of the federal Bankruptcy Code, as it now exists or as it may hereafter be amended, or pursuant to any other similar state statute applicable to such Party, as now or hereafter in effect, shall be filed against such Party and shall not be dismissed within sixty (60) days after such filing; (e) If a Party shall file a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law or shall consent to the filing of any bankruptcy or reorganization petition against it under any similar law; or, without limitation of the generality of the foregoing, if a Party shall file a petition or answer or consent seeking relief or assisting in seeking relief in a proceeding under any of the provisions of the federal Bankruptcy Code, as it now exists or as it may hereafter be amended, or pursuant to any other similar state statute applicable to such Party, as now or hereafter in effect, or an answer admitting the material allegations of a petition filed against it in such a proceeding; or if a Party shall make an assignment for the benefit of its creditors; or if a Party shall admit in writing its inability to pay its debts generally as they become due; or if a Party shall consent to the appointment of a receiver or receivers, or trustee or trustees, or liquidator or liquidators of it or of all or any part of its property; or (f) If (i) Calpine shall directly or indirectly cease to retain at least fifty percent (50%) of all general partner interests in the Partnership, (ii) Calpine shall directly or indirectly cease to retain at least twenty-five percent (25%) of the overall ownership interests in the Partnership, or (iii) the Partnership ceases to own one hundred percent (100%) of the Project, in each case without Phillips' consent, which consent shall not be unreasonably withheld; provided, however, any foreclosure by, or transfer in lieu of foreclosure to, any Project Financing Entities may occur without Phillips' consent and shall not constitute an Event of Default hereunder. 16.2 REMEDIES FOR DEFAULT. Subject to the provisions of Sections 14.4 and 14.5, upon the occurrence and during the continuation of an Event of Default, the Party not in default shall have the right to (a) terminate this Agreement with respect to either the purchase and sale of Steam or -35- 36 Electrical Energy upon five (5) days written notice to the other Party, or (b) terminate this Agreement in its entirety upon five (5) days written notice to the other Party (which notice may be given prior to the expiration of the cure periods set forth in Section 16.1), in addition to the right to pursue any remedy under this Agreement, or now or hereafter existing under applicable Law or in equity; provided, however, that in the case of an Event of Default with respect to the Partnership, Phillips shall provide the Project Financing Entities (a) with notice of such Event of Default and (b) the opportunity to exercise the cure rights and such other rights, remedies, acknowledgments, waivers and consents as may be agreed to by Phillips in a Consent and Agreement in accordance with the terms thereof. 16.3 REMEDIES NOT EXCLUSIVE. Except as otherwise expressly provided to the contrary in the Project Agreements regarding the Development Phase, the rights and remedies herein provided in case of an Event of Default shall not be exclusive but shall, to the extent permitted by Law, be cumulative and in addition to all other rights and remedies existing at Law, in equity or otherwise, except those rights and remedies which have been waived or relinquished hereunder by the Parties pursuant to the provisions of Sections 14.4 and 14.5. No delay or omission of a Party to exercise any right or remedy accruing upon any Event of Default shall impair any such right or remedy or constitute a waiver of such default or an acquiescence therein. Every right and remedy given by this Agreement or by Law to a Party may be exercised from time to time, and as often as may be deemed expedient, by such Party. 17. TERMINATION 17.1 TERMINATION DURING THE DEVELOPMENT PHASE. This Agreement shall terminate in the event that either Party terminates the Project Agreements during the Development Phase in accordance with Section 4 of the Development and Construction Agreement. 17.2 TERMINATION FOR FAILURE TO ACHIEVE COMMERCIAL OPERATION. Phillips shall have the right to terminate this Agreement upon ten (10) days written notice of the Partnership in the event the Commercial Operation Date has not occurred on or before July 12, 2000, unless the Commercial Operation Date does not occur on such date due to Phillips being in an Event of Default or as a result of a Force Majeure Event, in which case the termination date for such failure to achieve the Commercial Operation Date shall be extended by one day for each day of such Event of Default or such Force Majeure Event, as the case may be, but shall not be extended for more than three hundred sixty-five (365) days due solely to Force Majeure Events. -36- 37 17.3 TERMINATION FOR HCC SHUTDOWN. In the event of an HCC Shutdown, either Party may terminate this Agreement upon thirty (30) days written notice to the other Party; provided, however, the Partnership shall continue to supply the residual electrical energy requirements of HCC, if any, at the prices set forth in this Agreement for the Variable Fuel Payment and Variable O&M Payment, and the Electrical Capacity Payment shall be reduced on a pro rata basis to the amount of electrical capacity being reserved. Notwithstanding any such termination, the Fixed Steam O&M Payment, the Fixed Steam Capacity Payment and the Electrical Capacity Payment shall continue through the end of the calendar year in which the HCC Shutdown occurs. 17.4 RIGHT TO TERMINATE FOR DESTRUCTION OR SUBSTANTIAL DAMAGE TO THE POWER Plant. Notwithstanding anything to the contrary contained herein, in the event the Power Plant is destroyed or substantially damaged, then the Partnership shall be obligated to rebuild the Power Plant as soon as possible thereafter such that the Partnership shall be able to deliver Electrical Energy and Steam to Phillips hereunder; provided, however, the Partnership at its option, exercisable by written notice to Phillips at any time within one hundred eighty (180) days after the date of such damage or substantial destruction, may elect not to rebuild the Power Plant and to terminate this Agreement by paying to Phillips within fifteen (15) days after receipt forty percent (40%) of each dollar of insurance proceeds received by the Partnership up to a maximum of the Termination Fee after first deducting all sums due to the Project Financing Entities. 17.5 TERMINATION FOR FAILURE TO TAKE OFF-GAS. If Phillips terminates the Facility Services Agreement because the Partnership was in an Event of Default under the terms of the Facility Services Agreement for failure to take Off-Gas, then Phillips may terminate this Agreement by providing written notice to the Partnership at any time within sixty (60) days after the termination of the Facility Services Agreement. 17.6 TERMINATION OF GROUND LEASE AND EASEMENT AGREEMENT. In the event the Ground Lease and Easement Agreement terminates, this Agreement shall terminate. 17.7 TERMINATION IN THE EVENT OF FORECLOSURE. In the event of an election by the Project Financing Entities under Section 13.3(ii) of the Ground Lease and Easement Agreement and the Project Financing Entities do not assume, or cause a third party (such third party being subject to the approval and consent rights of Phillips as set forth in the Project Agreements) to assume, all of the Partnership's obligations under the Project Agreements arising after the acquisition date within thirty (30) -37- 38 days of an acquisition (including foreclosure or transfer in lieu of foreclosure) by the Project Financing Entities of (a) the Project or the Partnership or any interests therein or (b) the interests of a lessor in the Project or the Partnership (in the event a financing lease or other similar financing technique is used), then Phillips shall have the right to immediately terminate this Agreement by delivery of written notice thereof to the Project Financing Entities. 18. DISPUTE RESOLUTION 18.1 PROCEDURE. In the event a dispute arises between Phillips and the Partnership regarding the application or interpretation of any provision of this Agreement, the Parties agree to use the procedures in this Section 18 to resolve any such disputes; provided, however, that this Section shall not apply to disputes relating in any manner to any indemnity, insurance or release obligations under the Project Agreements. 18.2 INITIAL RESOLUTION ATTEMPTS. Either Party may initiate dispute resolution procedures by sending written notice to the other Party specifically stating the complaining Party's claim and requesting dispute resolution in accordance with this Section 18. The receiving Party shall reply with the designation of a person authorized to settle the dispute and shall list two (2) alternative dates (both of which must be within ten (10) Business Days after receipt of the complaint) for meeting at a mutually agreeable location. If the matter has not been resolved within ten (10) days of such meeting, each Party shall refer the dispute to a senior executive of its organization who shall meet at a mutually agreeable location within fourteen (14) days to resolve the dispute. 18.3 ALTERNATIVE DISPUTE RESOLUTION. If the matter has not been resolved within fourteen (14) days of the meeting of the senior executives, the Parties will attempt in good faith to resolve the dispute by employing a neutral mediator to attempt to resolve the dispute in accordance with the CPR Model Procedure for Mediation of Business Disputes; provided, however, that if both Parties agree, the Parties can attempt to resolve the dispute in accordance with the CPR Model Minitrial Procedure. If the dispute has not been resolved pursuant to Section 18.2 within sixty (60) days of the commencement of such procedure, the complaining Party may require the dispute to be settled by arbitration. 18.4 ARBITRATION. All arbitration shall be in accordance with the CPR Rules for Non-Administered Arbitration of Business Disputes by three (3) arbitrators who shall be neutral, independent, and generally knowledgeable about the type of transaction which gave rise to the dispute. The arbitration shall be governed by the United States -38- 39 Arbitration Act, 9 U.S.C. ss. 1-16; provided, however, that the arbitrators shall include in their report/award a list of findings, with supporting evidentiary references, upon which they have relied in making their decision. The award rendered by the arbitrators shall be final and binding upon the Parties and judgment upon the award rendered by the arbitrators may be entered by any court having jurisdiction thereof. The place of arbitration shall be Houston, Texas. 18.5 GENERAL RULES AND PROVISIONS. Notwithstanding anything to the contrary contained herein, and regardless of any procedures or rules of the CPR, it is expressly agreed that the following shall apply and control over any other provision in this Section 18: (a) Except to the extent that the Parties may agree upon selection of one or more arbitrators, the CPR shall select arbitrators from a panel reviewed by the Parties. Each Party shall be entitled to exercise peremptory strikes against one-third of the panel and may challenge other candidates for lack of neutrality or lack of qualification. Challenges shall be resolved in accordance with the CPR rules. (b) The Parties shall have at least twenty (20) days following close of the arbitration hearing within which to submit a brief (not to exceed eighteen (18) pages in length) and ten (10) days from date of receipt of the opponent's brief within which to respond thereto (response not to exceed ten (10) pages in length). (c) Arbitrators shall not award punitive damages or attorneys' fees (except attorneys' fees specifically authorized in the Project Agreements). (d) The fees and expenses of the mediator and arbitrators shall be shared equally by the Parties, and each Party shall bear its own costs and expenses. (e) The Parties may by written agreement (signed by both Parties) alter any time deadline, location(s) for meeting(s), or procedure outlined in this Section 18 or in the CPR rules. (f) Time is of the essence for purposes of the provisions of this Section 18. (g) Either Party may seek a restraining order, temporary injunction, or other provisional judicial relief if the Party in its sole judgment believes that such action is necessary to avoid irreparable injury or to preserve the status quo. The Parties will continue to participate -39- 40 in good faith in the procedures despite any request for provisional relief. Notwithstanding anything to the contrary contained herein, in no event shall this Section 18.5(g) apply to Phillips' exercise of the Standby Boilers Operating Rights, and the Partnership covenants and agrees, and shall cause the Partners to covenant and agree, not to seek a restraining order, temporary injunction, or other provisional judicial relief with respect to Phillips' exercise of the Standby Boilers Operating Rights. (h) The arbitrators shall have no authority, power or right to alter, change, amend, modify, waive, add to or delete from any of the provisions of the Project Agreements, and any award rendered by the arbitrators shall be consistent with the terms and conditions of the Project Agreements. 19. ASSIGNMENT 19.1 AGREEMENT BINDING. This Agreement shall be binding upon, and shall inure to the benefit of, the Parties and their successors and permitted assigns. 19.2 PERMITTED ASSIGNMENT. This Agreement shall not be assignable by either Party without the prior written consent of the other Party hereto, which consent shall not be unreasonably withheld or delayed, except that this Agreement may be assigned (a) by the Partnership without such consent (but with notice to Phillips) to Project Financing Entities as security for the obligations of the Partnership under any Project Financing Agreement, and (b) by Phillips without such consent in accordance with Section 19.3 below. Notwithstanding the foregoing, Phillips shall have the absolute right to prohibit assignment of this Agreement to competitors of Phillips' business. Unless otherwise expressly agreed by the Parties, any assignment of this Agreement shall not relieve the assigning Party of any of its obligations under this Agreement. Except with respect to the collateral assignment permitted under clause (a) of this Section 19.2, no assignment by either Party of this Agreement for any purpose whatsoever shall be valid until all obligations of the assignor hereunder shall have been assumed by the assignee by a written agreement delivered to the other Party. Any assignment which does not comply with the provisions of this Section 19.2 shall be null and void. 19.3 SALE OR ENCUMBRANCE BY PHILLIPS. Phillips shall have the right, without the consent of the Partnership (but with notice to the Partnership), to (a) sell, assign or otherwise transfer ownership of all or any part of HCC to any Person, provided such Person agrees in writing to be bound by -40- 41 the terms and conditions of this Agreement and to assume Phillips' obligations hereunder as they relate to the portion of HCC acquired by such Person, and (b) mortgage or otherwise encumber Phillips' interests in HCC, the Project Site, the Easement Improvements or in the Project Agreements. 19.4 PROJECT FINANCING ENTITY DOCUMENTS. In connection with any collateral assignment by the Partnership to a Project Financing Entity as described in Section 19.2(a) above, Phillips agrees to execute and deliver a Consent and Agreement in a form which is reasonably acceptable to Phillips; provided, however, Phillips shall not be obligated to agree to anything which could impact the integrity and continued reliable and safe operation of HCC. Phillips further agrees to furnish the Project Financing Entity with such other documents as may be reasonably requested. Notwithstanding the foregoing, Phillips shall have no obligation to, and shall not be considered to be in default for failure to, modify, alter or amend any of the Project Agreements to accommodate any Person, including Project Financing Entities. 19.5 ACQUISITION BY PROJECT FINANCING ENTITIES. In the event a Project Financing Entity acquires (including by foreclosure or transfer in lieu of foreclosure) all or any part of the Project, then from and after such acquisition such Project Financing Entity shall be bound by and agrees to assume the obligations of the Partnership under the Project Agreements which arise after the date of such acquisition. 20. REPRESENTATIONS AND WARRANTIES Each Party hereby represents and warrants to the other Party that, as of the Effective Date: 20.1 STANDING AND QUALIFICATION. Such Party is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, is in good standing and is qualified to do business in Texas and in all other jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure so to qualify would have a material adverse effect on its financial condition, operations, prospects or business. 20.2 NO VIOLATION OF LAW; LITIGATION. Such Party (to its best knowledge) is not in violation of any applicable Law promulgated, or judgment entered by any federal, state, local or other governmental authority which violations, individually or in the aggregate, would adversely affect its performance of any obligations under this Agreement. There are no legal or arbitration proceedings or any proceeding by or before any governmental or regulatory authority or agency, now pending or (to its -41- 42 best knowledge) threatened against it which, if adversely determined, could have a material adverse effect upon its financial condition, operations, prospects or business, as a whole, or its ability to perform under this Agreement. 20.3 LICENSES AND CONSENTS. Such Party (to its best knowledge) is the holder of all Applicable Permits or other authorizations required to permit it to operate or conduct its business now and as contemplated by this Agreement, and, except for the Applicable Permits and other approvals to be obtained by the Parties pursuant to the Project Agreements, no authorization, consent or approval of, notice to or filing with, any governmental or regulatory authority is required for the execution, delivery or performance by such Party of this Agreement. 20.4 NO CONFLICT OR BREACH. To its best knowledge the execution, delivery and performance by such Party of the Project Agreement, the compliance with the terms and provisions hereof, and the carrying out of the transactions contemplated hereby, does not conflict or will not conflict with or result in a breach or violation of any of the terms, conditions or provisions of any Law, governmental rule or regulation or the charter documents, as amended, or bylaws, as amended, of such Party or any order, writ, injunction, judgment or decree of any court or governmental authority against such Party or by which it or any of its properties is bound, or any loan agreement, indenture, mortgage, note, resolution, bond, or contract or other agreement or instrument to which such Party is a party or by which it or any of its properties is bound, or constitutes or will constitute a default thereunder or will result in the imposition of any lien upon any of its properties. 20.5 AUTHORITY. Such Party has all necessary power and authority to execute, deliver and perform the Project Agreements and its obligations hereunder; the execution, delivery and performance of this Agreement has been duly authorized by all necessary action on its part; it has duly and validly executed and delivered this Agreement; and the Agreement constitutes a legal, valid and binding obligation of such Party enforceable against such Party in accordance with the terms hereof, except as the enforceability thereof may be limited by bankruptcy, insolvency, reorganization or moratorium or other similar laws relating to the enforcement of creditors' rights generally and by general equitable principles. 20.6 NO FEES. Such Party has not entered into any agreement, arrangement or understanding with any Person which will result in the obligation of the other Party, or any of its Affiliates, to pay any finder's fee, brokerage commission or similar payment in connection with this Agreement. -42- 43 21. NOTICES 21.1 WRITING. Any notice, demand, offer or other written instrument required or permitted to be given pursuant to this Agreement shall be in writing signed by the Party giving such notice and shall, to the extent reasonably practicable, be sent by telefax (confirmed by a mailed or courier copy received within five (5) days), and if not reasonably practicable to send by telefax, then by hand delivery, overnight courier, telegram or registered or certified mail, return receipt requested, to the other Party at such address as set forth below. If delivered to Phillips: Phillips Chemical Company, a Division of Phillips Petroleum Company 1400 Jefferson, Pasadena, TX 77501 Attention: HCC General Manager Telephone: 713-475-3610 Telefax: 713-475-3589 With a copy to: Phillips Chemical Company, a Division of Phillips Petroleum Company 2625 Bay Area Boulevard Houston (Clear Lake) TX 77058 Attention: ATTN: Plastics Finance Manager Telephone: 713-244-3076 Telefax: 713-244-3005 If delivered to the Partnership: Pasadena Cogeneration L.P. 50 West San Fernando San Jose, California 95113 Attention: Asset Manager and General Counsel Telephone: (408) 995-5115 Telefax: (408) 995-0505 With a copy to: Calpine Pasadena Cogeneration, Inc. Project Office Address as provided by Calpine Pasadena Cogeneration, Inc. Pasadena, TX Attention: Plant Manager -43- 44 Each Party shall have the right to change the place to which notice shall be sent or delivered or to specify one additional address to which copies of notices may be sent, in either case by similar notice sent or delivered in like manner to the other Party. 21.2 TIMING OF RECEIPT. Without limiting any other means by which a Party may be able to prove that a notice has been received by the other Party, a notice shall be deemed to be duly received: (a) If delivered by hand, overnight courier or telegram, on the date when received at the address of the recipient; (b) If sent by registered or certified mail, on the date of the return receipt; or (c) If sent by telefax, upon receipt by the sender of an acknowledgment or transmission report generated by the machine from which the telefax was sent indicating that the telefax was sent in its entirety and received at the recipient's telefax number. 22. MISCELLANEOUS 22.1 AMENDMENTS. No change, amendment or modification of this Agreement shall be valid or binding upon the Parties unless such change, amendment or modification shall be in writing and duly executed by both Parties. 22.2 CAPTIONS. The captions contained in this Agreement are for convenience and reference only and in no way define, describe, extend or limit the scope or intent of this Agreement or the intent of any provision contained herein. 22.3 SEVERABILITY. The invalidity of one or more phrases, sentences, clauses or Sections contained in this Agreement shall not affect the validity of the remaining portions of this Agreement so long as the material purposes of this Agreement can be determined and effectuated. 22.4 NO WAIVER. Any failure of either Party to enforce any of the provisions of this Agreement or to require compliance with any of its terms at any time during the pendency of this Agreement, shall in no way affect the validity of this Agreement, or any part hereof, and shall not be deemed a waiver of the right of such Party thereafter to enforce any and each such provision. Any consent or approval given pursuant to this Agreement shall be limited to its express terms and shall not otherwise increase the -44- 45 obligations of the Party giving such consent or approval or otherwise reduce the obligations of the Party receiving such consent or approval. 22.5 FURTHER ASSURANCES. Each Party agrees to execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, to effectuate the purposes and intent of this Agreement. 22.6 ESTOPPEL CERTIFICATES. Each Party shall, from time to time, upon fifteen (15) days prior request by the other Party, execute, acknowledge and deliver to the requesting Party a certificate signed by an authorized officer of such Party stating that this Agreement is unmodified and in full force and effect (or, if there have been modifications, that such Agreement is in full force and effect as modified, and setting forth such modifications) and either stating that to the knowledge of the signer of such certificate no Event of Default exists hereunder or thereunder or specifying each such Event of Default to which the signer has knowledge. Any certificate given pursuant to this Section 22.6 may be relied upon by the Project Financing Entity and by any prospective mortgagee or purchaser of any interest in this Agreement, the Power Plant, or any other portion of the Project. 22.7 CONFIDENTIALITY. During the Term of this Agreement, it may become necessary or desirable, from time to time, for either Party to provide or disclose to the other Party information that is either confidential or proprietary (which shall not include information already known to such other Party or generally known or available to the public). The Labeling Party may orally request such information to be kept confidential if such information is not in a written format, and in such case shall identify and confirm such confidential information in writing to the other Party no later than fifteen (15) days after such disclosure. If the confidential or proprietary information is in a written format, the Labeling Party shall label such information as either confidential or proprietary. The other Party shall not reproduce, copy, use or disclose (except when required by governmental authorities or by Law) any such information in whole or in part to a third party for any purpose without the consent of the Labeling Party. The other Party shall restrict the internal disclosure of any such confidential or proprietary information to only those employees, officers and directors who have a "need to know" such information, and shall restrict those individuals from disclosing, using or permitting the disclosure of such information. In disclosing confidential or proprietary information to governmental authorities, the disclosing Party shall cooperate with the Labeling Party to minimize the amount of such information furnished. At the specific request of the Labeling Party , the disclosing Party shall endeavor to secure the agreement of such -45- 46 governmental authorities to maintain specified portions of such information in confidence. In the case of any disclosure of any such confidential or proprietary information, whether or not such disclosure is permitted by this Section 22.7, the disclosing Party shall promptly give written notice thereof to the Labeling Party. 22.8 LIMITATION ON PHOTOS AND VIDEOS AT HCC. The Partnership, its Affiliates, and each of their employees, directors, agents and Invitees, shall not take any photographs, films, videos or similar visual depictions of any part of HCC without Phillips' prior written approval. 22.9 RECORDS AND AUDIT. Each Party shall, and shall procure that its contractors shall, maintain a true and correct set of records pertaining to all activities relating to its performance of this Agreement and all transactions related thereto. Each Party further agrees, and shall procure that its contractors agree, to retain all such records for a period of not less than two (2) years after the termination of this Agreement. Any representative or representatives authorized by a Party may audit any and all such records of the other Party or its contractors at any time or times during the Term of this Agreement and during the two (2) year period following its termination. The foregoing obligations in this Section 22.9 shall survive the termination, expiration or mutual cancellation of this Agreement. 22.10 CONFLICT OF INTEREST. The Partnership shall not, and shall procure that its contractors shall not, pay any commissions, fees or grant any rebates to any employee, officer or agent of Phillips nor favor employees, officers or agents of Phillips with gifts or entertainment of significant cost or value, nor enter into any business arrangement with employees, officers or agents of Phillips other than as a representative of Phillips, without Phillips' written approval. Compliance with this Section 22.10 is subject to audit under Section 22.9 above. 22.11 NO LIABILITY. Except as otherwise expressly provided in this Agreement, no Affiliate of any Party, nor the officers, directors, employees or agents of such Affiliate of any Party, shall have any liability to the other Party in connection with this Agreement; provided, however, this Section 22.11 shall not be construed to limit liability of any such Affiliate or Person under any other agreement. 22.12 APPLICABLE LAW. This Agreement shall be governed by, construed and enforced in accordance with the laws of the State of Texas, including with respect to matters of construction, validity and performance, without giving effect to any choice of law rules that may direct the application of the laws of another jurisdiction. -46- 47 22.13 VENUE AND SUBMISSION TO JURISDICTION. THE VENUE FOR ANY LEGAL ACTION TO ENFORCE, INTERPRET OR OTHERWISE LITIGATE DISPUTES RELATING TO THIS AGREEMENT SHALL BE HOUSTON, TEXAS, AND EACH PARTY HERETO HEREBY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF THE FEDERAL AND STATE COURTS OF THE STATE OF TEXAS LOCATED IN HOUSTON, TEXAS. EACH PARTY HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUCH PROCEEDING BROUGHT IN ANY SUCH COURT AND ANY CLAIM THAT ANY SUCH PROCEEDING HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. THE PREVAILING PARTY IN ANY SUCH ACTION SHALL BE ENTITLED TO RECOVER FROM THE OTHER PARTY REASONABLE ATTORNEYS' FEES AND COSTS. 22.14 COUNTERPARTS. This Agreement may be signed in any number of counterparts and each counterpart shall represent a fully executed original as if signed by both Parties. 22.15 SURVIVAL. Notwithstanding any provision of this Agreement to the contrary, expiration or other termination of this Agreement shall not relieve the Parties of obligations that by their nature should survive such expiration or termination, including remedies in the case of a termination for an Event of Default, promises of indemnity, payment obligations, confidentiality, audit rights, and dispute resolution provisions. 23. INCORPORATION OF PROVISIONS Notwithstanding anything to the contrary contained herein, Philips shall have the rights set forth in Sections 13 and 14 (titled Project Financing Agreements and Electric Utility Agreements) of the Ground Lease and Easement Agreement and such provisions are incorporated herein and made a part hereof by this reference and shall apply as though fully set forth herein. -47- 48 IN WITNESS WHEREOF, Phillips and the Partnership have caused this Agreement to be executed by their duly authorized representatives as of December 16, 1996. PHILLIPS PETROLEUM COMPANY By: ------------------------------------ Name: ------------------------------------ Title: ------------------------------------ PASADENA COGENERATION L.P. By: Calpine Pasadena Cogeneration, Inc., its General Partner By: ------------------------------------ Name: ------------------------------------ Title: ------------------------------------ -48- 49 EXHIBIT A TO THE AMENDED AND RESTATED ENERGY SALES AGREEMENT ELECTRICAL ENERGY PRICING VARIABLE FUEL PAYMENT = Actual Power Usage1/ (kWH/Billing Period) x Variable Fuel Component VARIABLE FUEL COMPONENT (1995 basis) = $0.01119/kWH x Fuel Gas Escalator VARIABLE O&M PAYMENT = Actual Power Usage1/ (kWH/Billing Period) x Variable O&M Component; provided, however, during the first COD Year, as a one time adjustment, a reduction of Five Hundred Thousand Dollars ($500,000) shall be made during the first COD Year by reducing the Variable O&M Payments by $41,666.67 each month during the first COD Year. VARIABLE O&M COMPONENT (1995 basis) = $0.00649/kWH x the O&M Escalator. FIRM ELECTRICAL CAPACITY PAYMENT = for 80 MVA, $5,518,187 per annum, paid quarterly. INTERRUPTIBLE ELECTRICAL CAPACITY PAYMENT = 10 MVA of Interruptible Electrical Capacity at $3,550 per MVA-month x the MVA determined pursuant to Section 2.4.2 of the Energy Sales Agreement, paid quarterly, for up to 10 MVA. PAYMENT FOR USE OF EXCESS ELECTRICAL ENERGY required pursuant to Section 2.3.3 = (a) $5.75 per kVA-month for a Billing Period if the electrical capacity of the Project has not been fully committed at the time of such demand, or (b) $17.25 per kVA-month for such Billing Period at any time after the electrical capacity of the Project is fully committed. OPTION TO ADJUST: if the number of MW supplied hereunder is reduced as a result of Phillips' exercise of the Option to Adjust pursuant to Section 2.8, the Firm Electrical Capacity Payment shall be reduced by $68,977.33 for each annual megawatt, of Firm Electrical Capacity no longer supplied by the Partnership. All Escalators and results of calculations shall be rounded up or down, as appropriate, to 3 decimal places (1.0333 to 1.033, 1.0335 to 1.034). 1/ "ACTUAL POWER USAGE" shall mean the actual kWH/hours delivered to Phillips from the Partnership during a Billing Period. -i- 50
Payment Payment Electricity Period Terms - ------------------------------------- -------------- ------------------------------ Variable O&M Payment Monthly o (See Section 5.3) Variable Fuel Payment Monthly o (See Section 5.3) Firm Capacity Payment Quarterly o end of quarter in arrears (See Section 5.3) Interruptible Capacity Payment Quarterly o end of quarter in arrears (See Section 5.3)
-ii- 51 EXHIBIT B TO THE AMENDED AND RESTATED ENERGY SALES AGREEMENT STEAM PRICING VARIABLE STEAM PAYMENT = Actual Steam Usage 1/ (klbs/month) x Variable Steam Component VARIABLE STEAM COMPONENT (1995 basis) = $2.259/klb 2/ x Fuel Gas Escalator FIXED STEAM CAPACITY PAYMENT = for up to the Maximum Steam Requirement $2,000,000 per annum, paid quarterly. FIXED STEAM O&M PAYMENT (1995 basis) = $1,155,000 per annum x the O&M Escalator, paid quarterly.
Steam Payment Period Payment Terms - ------------------------------------------------------------------------------- Variable Steam Payment Monthly (See Section 5.3) Fixed Steam O&M Payment Quarterly end of quarter in arrears (See Section 5.3) Fixed Steam Capacity Payment Quarterly end of quarter in arrears (See Section 5.3)
All Escalators and results of calculations shall be rounded up or down, as appropriate, to 3 decimal places (1.0333 to 1.033, 1.0335 to 1.034). 1/ "ACTUAL STEAM USAGE" shall mean the actual pounds of Steam delivered to Phillips from the Partnership during a Billing Period. 2/ For low pressure (50-90 psig) process steam, this amount shall be $2.220/klb. -iii- 52 EXHIBIT C TO THE AMENDED AND RESTATED ENERGY SALES AGREEMENT STEAM SPECIFICATIONS 1) INTERMEDIATE PRESSURE PROCESS STEAM PRESSURE 335 PSIG TEMPERATURE SATURATED TOTAL SOLIDS Less Than 0.05 PPM SODIUM Less Than 0.02 PPM SILICA Less Than 0.02 PPM (1) Steady state operations within HCC require the steam pressure variation be limited to +/- 10 psi. (2) The Project must be capable of responding to an instantaneous change in 335 psig steam demand of 60,000 lbs/hr without pressure degradation or excursions exceeding 15 psig from the regulated 335 psig steam header pressure within HCC at the Point of Delivery for Steam. 2) LOW PRESSURE PROCESS STEAM PRESSURE 50 - 90 PSIG TEMPERATURE 310(Degree) - 340(Degree)F TOTAL SOLIDS Less Than 0.05 PM SODIUM Less Than 0.02 PPM SILICA Less Than 0.02 PPM -iv- 53 EXHIBIT D TO THE AMENDED AND RESTATED ENERGY SALES AGREEMENT CONDENSATE RETURN SPECIFICATIONS PRESSURE 50 to 60 PSIG (depending on location) TEMPERATURE 240 DEG F pH 8.5 Conductivity Less Than 20 MHO/CM AMOUNT RETURNED approximately 50% -v- 54 AMENDED AND RESTATED ENERGY SALES AGREEMENT BETWEEN PHILLIPS PETROLEUM COMPANY AND PASADENA COGENERATION L.P. DATED AS OF DECEMBER 16, 1996 THE PASADENA COGENERATION PROJECT 55 TABLE OF CONTENTS
PAGE ---- 1. DEFINITIONS AND INTERPRETATION.....................................................1 1.1 Definitions...............................................................1 1.2 Construction of Terms.....................................................2 1.3 Drafting Interpretations..................................................2 1.4 Documents Included........................................................2 1.5 Conflicting Provisions....................................................2 1.6 Entire Agreement..........................................................2 2. PURCHASE AND SALE OF ELECTRICAL ENERGY AND ELECTRICAL CAPACITY.....................2 2.1 Exclusive Source..........................................................2 2.2 Purchase and Sale Obligation for Electric Energy and Electrical Capacity.................................................3 2.2.1 Purchase and Sale Obligation for Electrical Energy.....................................................3 2.2.2 Purchase and Sale Obligation for Electrical Capacity...................................................3 2.3 Electrical Payment........................................................3 2.3.1 Variable Fuel Payment and Variable O&M Payment................4 2.3.2 Electrical Capacity Payment...................................4 2.3.2.1 Commencement of Firm Electrical Capacity Payments...................................4 2.3.2.2 Adjustments to Electrical Capacity Payments............................................4 2.3.3 Payment for Use of Excess Electrical Energy...................5 2.4 Interruptible Capacity....................................................5 2.4.1 Scheduling Interruptible Capacity.............................5 2.4.2 MW Calculation................................................5 2.5 Standby Electrical Agreement..............................................5 2.5.1 Standby Agreement.............................................6 2.5.2 Payment Adjustment............................................6 2.6 Payment Adjustment for Failure to Supply..................................6 2.6.1 Payment Adjustment...........................................6 2.6.2 Reimbursement for Incremental Cost...........................6 2.7 Additional Electrical Energy..............................................7 2.8 Option to Adjust Purchase of Electrical Energy and Electrical Capacity.................................................7 2.8.1 Pricing Notice................................................7 2.8.2 Right of First Refusal........................................7
-i- 56 2.8.3 Adjustment Terms..............................................8 3. PURCHASE AND SALE OF STEAM AND STEAM CAPACITY......................................9 3.1 Exclusive Source..........................................................9 3.2 Purchase and Sale Obligation for Steam and Steam Capacity.................9 3.2.1 Purchase and Sale Obligation..................................9 3.2.2 Purchase and Sale Obligation for Steam Capacity...............9 3.3 Characteristics of Steam.................................................10 3.4 Steam Payment............................................................10 3.4.1 Variable Steam Payment.......................................10 3.4.2 Fixed Steam O&M Payment......................................10 3.4.3 Fixed Steam Capacity Payment.................................10 3.5 Additional Steam Requirement.............................................10 4. CONDENSATE RETURN.................................................................10 4.1 Transportation of Steam and Condensate...................................10 4.2 Condensate Return........................................................11 4.3 Failure to Supply Condensate.............................................11 4.4 Operation of the Standby Boilers due to Phillips' Failure to Supply Raw Water and Condensate.................................11 4.5 Interruption of Water Supply.............................................12 5. BILLING AND PAYMENT...............................................................12 5.1 Monthly Billing Cycle for Steam, Electrical Energy and Standby............................................................12 5.2 Quarterly Payment for Capacity and Fixed Steam O&M.......................12 5.3 Payment of Invoices......................................................13 5.4 Interest.................................................................13 6. OPERATION OF THE PROJECT..........................................................13 6.1 Operation of the Project.................................................13 6.2 Operating and Communication Guidelines...................................14 6.3 Steam Redundancy Requirements............................................14 6.4 Standby Boilers Operating Rights.........................................14 6.4.1 Exercise of Rights...........................................14 6.4.2 Partnership Cooperation......................................15 6.4.3 Partnership Fuel Gas.........................................15 6.4.4 Remedies and Liabilities.....................................15 6.4.5 Reimbursement for Costs and Expenses.........................15 6.4.6 Cessation of Standby Boiler Operating Rights ...............16 6.4.7 Training.....................................................16 6.5 Phillips Representative..................................................16
-ii- 57 6.6 The Partnership Representative...........................................16 6.7 Obligation to Provide Auxiliary Boilers..................................17 7. MAINTENANCE AND REPAIR OF THE PROJECT.............................................17 7.1 The Partnership's Maintenance Obligations................................17 7.2 Phillips' Maintenance Obligations........................................18 7.3 Scheduled Maintenance for the Power Plant and HCC........................18 7.4 Inspection and Observation Rights........................................19 8. METERING..........................................................................19 8.1 Metering Devices.........................................................19 8.2 Periodic Inspection......................................................19 8.3 Retroactive Adjustments..................................................20 8.4 Access to Metering Devices...............................................20 9. REVIEW MEETINGS...................................................................20 10. SALES TO THIRD PARTY PURCHASERS..................................................20 11. TERM OF AGREEMENT................................................................21 11.1 Term 21 11.2 Renewal Term............................................................21 11.3 Phillips Extension Term.................................................21 12. INSURANCE........................................................................21 12.1 Insurance Coverages.....................................................22 12.1.1 Workers' Compensation Insurance.............................22 12.1.2 Commercial General Liability Insurance......................22 12.1.3 Automobile Liability Insurance..............................22 12.1.4 Excess/Umbrella Liability Insurance.........................22 12.2 Endorsements............................................................23 12.2.1 Waiver of Subrogation.......................................23 12.2.2 Severability................................................23 12.2.3 Primary Coverage............................................23 12.2.4 Additional Insured..........................................23 12.3 All-Risk Property Insurance.............................................24 12.3.1 Builder's All-Risk Insurance and All-Risk Property and Boiler and Machinery Insurance...............24 12.3.2 Waiver of Subrogation.......................................24 12.4 Contractors and Subcontractors..........................................24 12.5 Phillips Insurance Coverages............................................25 12.5.1 Workers' Compensation Insurance.............................25 12.5.2 Commercial General Liability Insurance......................25 12.5.3 Automobile Liability Insurance..............................25 12.5.4 Excess/Umbrella Liability Insurance.........................25
-iii- 58 12.5.5 Property Insurance..........................................25 12.6 Evidence of Insurance...................................................26 12.7 Disclaimer..............................................................26 12.8 Placement of Insurance Coverage with Captive............................26 12.8.1 Phillips' Captive Insurer...................................26 12.8.2 The Partnership's Captive Insurer...........................26 13. INDEMNIFICATION..................................................................27 13.1 Release and Indemnification by the Partnership..........................27 13.2 Release and Indemnification by Phillips.................................27 13.3 COMPREHENSIVE CONSTRUCTION AND APPLICATION..............................27 13.4 Limitation on Indemnities...............................................28 13.5 Property Damage Exclusion...............................................28 13.6 Mutual Indemnification for Breach of Representations; Fines and Penalties................................................29 13.6.1 Partnership Indemnification.................................29 13.6.2 Phillips Indemnification....................................29 13.7 Exclusions from Releases and Indemnities................................30 13.8 Notice of Legal Defense.................................................30 13.9 Application of Indemnities..............................................30 13.10 Survival...............................................................31 14. LIABILITY; NO DEDICATION.........................................................31 14.1 Third Parties...........................................................31 14.2 No Dedication...........................................................31 14.3 No Partnership..........................................................31 14.4 No Consequential Damages................................................31 14.5 Intent..................................................................32 15. FORCE MAJEURE....................................................................32 15.1 Excused Performance.....................................................32 15.2 Burden of Proof.........................................................33 15.3 Termination for Force Majeure...........................................33 15.3.1 Right to Terminate..........................................33 15.3.2 Destruction or Substantial Damage to the Power Plant or HCC as the Force Majeure Event...................33 15.3.3 Mitigation Plan.............................................33 16. EVENTS OF DEFAULT................................................................34 16.1 Definition..............................................................34 16.2 Remedies for Default....................................................35 16.3 Remedies Not Exclusive..................................................36
-iv- 59 17. TERMINATION......................................................................36 17.1 Termination During the Development Phase................................36 17.2 Termination for Failure to Achieve Commercial Operation.................36 17.3 Termination for HCC Shutdown............................................36 17.4 Right to Terminate for Destruction or Substantial Damage to the Power Plant.................................................37 17.5 Termination for Failure to Take Off-Gas.................................37 17.6 Termination of Ground Lease and Easement Agreement......................37 17.7 Termination in the Event of Foreclosure.................................37 18. DISPUTE RESOLUTION...............................................................38 18.1 Procedure...............................................................38 18.2 Initial Resolution Attempts.............................................38 18.3 Alternative Dispute Resolution..........................................38 18.4 Arbitration.............................................................38 18.5 General Rules and Provisions............................................39 19. ASSIGNMENT.......................................................................40 19.1 Agreement Binding.......................................................40 19.2 Permitted Assignment....................................................40 19.3 Sale or Encumbrance by Phillips.........................................40 19.4 Project Financing Entity Documents......................................41 19.5 Acquisition by Project Financing Entities...............................41 20. REPRESENTATIONS AND WARRANTIES...................................................41 20.1 Standing and Qualification..............................................41 20.2 No Violation of Law; Litigation.........................................41 20.3 Licenses and Consents...................................................42 20.4 No Conflict or Breach...................................................42 20.5 Authority...............................................................42 20.6 No Fees.................................................................42 21. NOTICES..........................................................................42 21.1 Writing.................................................................42 21.2 Timing of Receipt.......................................................44 22. MISCELLANEOUS....................................................................44 22.1 Amendments..............................................................44 22.2 Captions................................................................44 22.3 Severability............................................................44 22.4 No Waiver...............................................................44 22.5 Further Assurances......................................................44 22.6 Estoppel Certificates...................................................45
-v- 60 22.7 Confidentiality.........................................................45 22.8 Limitation on Photos and Videos at HCC..................................46 22.9 Records and Audit.......................................................46 22.10 Conflict of Interest...................................................46 22.11 No Liability...........................................................46 22.12 Applicable Law.........................................................46 22.13 Venue and Submission to Jurisdiction...................................46 22.14 Counterparts...........................................................47 22.15 Survival...............................................................47 23. INCORPORATION OF PROVISIONS......................................................47
APPENDICES APPENDIX A Definitions EXHIBITS EXHIBIT A Electrical Energy Pricing EXHIBIT B Steam Pricing EXHIBIT C Steam Specifications EXHIBIT D Condensate Return Specifications -vi- EX-27 4 FINANCIAL DATA SCHEDULE
5 The schedule contains summary financial information extracted from Calpine Corporation's Consolidated Balance Sheet as of December 31, 1996 and from the Consolidated Statement of Operations for the twelve months ended December 31, 1996 and is qualified in its entirety by reference to such financial statements. 1,000 U.S. DOLLARS 12-MOS DEC-31-1996 JAN-01-1996 DEC-31-1996 1 100,010 5,470 42,788 0 3,262 171,187 750,727 100,674 1,030,215 74,969 563,640 0 0 20 203,107 1,030,215 199,464 214,554 121,800 129,200 0 0 45,294 27,756 9,064 18,692 0 0 0 18,692 1.27 1.24
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