-----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, IjgyezRjgRofVkI8oGCNcUI2xxfrdP5g9AnVXAtrzbvl6UoHv2PyVkjyAvRxlXr1 l/KJUNicsKvbYCq7E7LXSg== 0001017062-98-000700.txt : 19980401 0001017062-98-000700.hdr.sgml : 19980401 ACCESSION NUMBER: 0001017062-98-000700 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980331 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: EDISON MISSION ENERGY CENTRAL INDEX KEY: 0000930835 STANDARD INDUSTRIAL CLASSIFICATION: COGENERATION SERVICES & SMALL POWER PRODUCERS [4991] IRS NUMBER: 954031807 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-24890 FILM NUMBER: 98580003 BUSINESS ADDRESS: STREET 1: 18101 VON KARMAN AVE STREET 2: STE 1700 CITY: IRVINE STATE: CA ZIP: 92715 BUSINESS PHONE: 7147525588 MAIL ADDRESS: STREET 1: 18101 VON KARMAN AVE STREET 2: STE 1700 CITY: IRVINE STATE: CA ZIP: 92715 FORMER COMPANY: FORMER CONFORMED NAME: MISSION ENERGY CO DATE OF NAME CHANGE: 19941003 10-K 1 FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1997 Commission File Number 1-13434 EDISON MISSION ENERGY (Exact name of registrant as specified in its charter) CALIFORNIA 95-4031807 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 18101 VON KARMAN AVENUE IRVINE, CALIFORNIA 92612 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (714) 752-5588 Securities registered pursuant to Section 12(b) of the Act: 9-7/8% CUMULATIVE MONTHLY INCOME PREFERRED SECURITIES, SERIES A * NEW YORK STOCK EXCHANGE - --------------------------------------- ----------------------- (Title of Class) (name of each exchange on which registered) 8-1/2% CUMULATIVE MONTHLY INCOME PREFERRED SECURITIES, SERIES B * NEW YORK STOCK EXCHANGE - --------------------------------------- ------------------------- (Title of Class) (name of each exchange on which registered) Securities registered pursuant to section 12(g) of the Act: COMMON STOCK, NO PAR VALUE -------------------------- (Title of Class) * Issued by Mission Capital, L.P., a limited partnership in which Edison Mission Energy is the sole general partner. The payments of distributions on the preferred securities and payments on liquidation or redemption are guaranteed by Edison Mission Energy. 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 this Form 10-K or any amendment to this Form 10-K _____. Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of March 27, 1998: $0. Number of shares outstanding of the registrant's Common Stock as of March 27, 1998: 100 shares (all shares held by an affiliate of the registrant). TABLE OF CONTENTS
Item Page - ---- ---- PART I 1. Business................................................................. 1 2. Properties............................................................... 22 3. Legal Proceedings........................................................ 23 4. Submission of Matters to a Vote of Security Holders...................... 23 PART II 5. Market for Registrant's Common Equity and Related Shareholder Matters.... 24 6. Selected Financial Data.................................................. 25 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................................... 26 8. Financial Statements and Supplementary Data.............................. 36 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................................... 36 PART III 10. Directors and Executive Officers of the Registrant....................... 69 11. Executive Compensation................................................... 71 12. Security Ownership of Certain Beneficial Owners and Management........... 78 13. Certain Relationships and Related Transactions........................... 80 PART IV 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.......... 80 Signatures............................................................... 99
PART I ITEM 1. BUSINESS THE COMPANY - ----------- Edison Mission Energy (EME), through its subsidiaries, is engaged in the business of developing, acquiring, owning and operating electric power generation facilities worldwide. EME is a wholly owned subsidiary of The Mission Group, which is a wholly owned, non-utility subsidiary of Edison International. Edison International is also the parent holding company of Southern California Edison Company (SCE), one of the largest electric utilities in the United States. EME was formed in 1986 with two domestic operating projects. Currently, EME owns interests in 26 domestic and 24 international operating electrical power generation facilities with an aggregate generating capacity of 7,403 megawatts (MW), of which EME's share is approximately 5,173 MW. Three international projects totaling 1,922 MW of generating capacity (of which EME's anticipated share is approximately 887 MW) are currently in the construction stage. At December 31, 1997, the Company had consolidated assets of $5 billion and total shareholder's equity of $827 million. EME is incorporated under the laws of the State of California. Its headquarters and principal executive offices are located at 18101 Von Karman Avenue, Suite 1700, Irvine, California 92612, and its telephone number is (714) 752-5588. Unless indicated otherwise or the context otherwise requires, references in this Annual Report on Form 10-K to EME shall be deemed to include EME, its subsidiaries and the partnerships or limited liability entities through which EME and its partners own and manage their project investments. SEGMENT INFORMATION - ------------------- EME operates in only one industry segment: electric power generation. DESCRIPTION OF BUSINESS - ----------------------- GENERAL OVERVIEW EME is one of the leading global producers of electricity. Through its subsidiaries, EME is engaged in the business of developing, acquiring, owning and operating electric power generation facilities worldwide. EME was formed in 1986 with two domestic operating projects. Currently, EME owns interests in 26 domestic and 24 international operating electrical power generation facilities. Until the enactment of the Public Utility Regulatory Policies Act of 1978 (PURPA), utilities were the only producers of bulk electric power intended for sale to third parties in the United States. PURPA encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from certain types of non-utility power producers (qualifying facilities or QFs) under certain conditions. The passage of the Energy Policy Act of 1992 (the Energy Policy Act) further encouraged the development of independent power by significantly expanding the options available to independent power producers (IPPs) with respect to their regulatory status and by liberalizing transmission access. As a result, a significant market for electric power produced by IPPs, such as EME, has developed in the United States since the enactment of PURPA. 1 The movement toward privatization of existing power generation capacity in many foreign countries and the growing need for new capacity in developing countries have also led to the development of significant new markets for IPPs outside the United States. EME believes that it is well-positioned to continue to realize opportunities in these new foreign markets. See "--Strategy" below. STRATEGY EME's business strategy is to play an active role, as a long-term owner, in all phases of power generation, from planning and development through construction and commercial operation. EME believes that such involvement allows EME to better ensure, through the use of its experienced personnel, that its projects are well-planned, structured and managed. In making investment decisions, EME evaluates potential project returns against rate of return guidelines. EME establishes these guidelines by identifying a base rate of return and adjusting the base rate by potential risk factors, such as risks associated with project location and stage of project development. EME endeavors to mitigate project development risk by (i) selecting partners with complementary skills and local experience, (ii) structuring investments through subsidiaries, (iii) managing up-front development costs, (iv) utilizing limited recourse financing and (v) linking revenue and expense components where appropriate. Many of EME's projects are operated by its subsidiaries or affiliates (e.g., Edison Mission Operation and Maintenance, Inc. - Edison Mission O&M), which seek to preserve and enhance the value of EME's investments. In response to increasing globalization of the independent power market, EME has organized its operations and development activities into three geographic divisions: (i) Americas, (ii) Asia Pacific and (iii) Europe, Central Asia, Middle East and Africa. Each division is served by one or more teams consisting of business development, operations, finance and legal personnel, and each team is responsible for all the activities of EME within a particular geographic region. Also, EME has mobilized personnel from outside a particular region when needed in order to assist in the development of certain projects. Set forth below is a brief discussion of the current strategy for each of the three regions and a summary of certain of EME's projects that are currently in the construction, advanced development, pre-finance or early operations stage in each of the regions. While EME anticipates the successful completion of these projects, no assurance can be given that any of these projects, or any other projects currently in the construction stage, advanced development or pre- finance stage, will be successfully completed or financed or that the expected MW capacity (and EME's anticipated share thereof) will be achieved. See " -- Project Development -- Certain Considerations Associated with Project Development, Finance and Operation". Americas The Americas division is comprised of the U.S./Canada and Central and Latin America regions and is headquartered in Irvine, California. The strategy for the U.S./Canada and Central and Latin America region is to (i) manage certain operating independent power projects located throughout the United States, (ii) pursue the acquisition of existing generating assets from utilities, industrial companies and other IPPs and (iii) pursue the development of new power projects throughout the region. EME has 26 operating projects in this region. For further information regarding EME's 26 domestic operating 2 projects, see "--EME's Operating Power Generation Facilities-- Description of Domestic Operating Projects." Asia Pacific The Asia Pacific division is headquartered in Singapore with additional offices located in Australia, Indonesia and the Philippines. Among the three geographic divisions, the countries covered by the Asia Pacific division have experienced the fastest electric demand growth, and are expected to continue strong growth in the medium term. Most governments in the region have committed to privatization of the electric power industry, and are looking to the private sector to finance and develop a significant portion of new generating capacity. The strategy for this region is to (i) pursue projects in countries where there exist strong political commitment and the structural framework necessary for private power, (ii) seek opportunities to employ indigenous fuels and (iii) seek strategic, complimentary alliances with partners who bring value to the project by providing fuel, equipment and construction services. EME's activity in the Asia Pacific region commenced in December 1992 with the acquisition of a 51% interest of the 1000-MW Loy Yang B Power Station (Loy Yang B) from the State Government of Victoria (State), Australia's first electric privatization effort. In May 1997, a subsidiary of EME acquired the State's 49% interest in Loy Yang B. The first of two 500-MW units at Loy Yang B began commercial operations in October 1993. Unit 2 commenced commercial operations in October 1996. An EME affiliate provides operation and maintenance services for both units. In April 1995, EME and its partners, Mitsui & Co. Ltd., General Electric Corporation and P.T. Batu Hitam Perkasa, an Indonesian limited liability company, commenced construction of the $2.5 billion Paiton project, a 1,230-MW coal-fired power plant in East Java, Indonesia. The project will consist of two units, each of which is expected to have a capacity of 615 MW. Construction of the plant continues on schedule, with commercial operation expected in the first half of 1999. In January 1996, EME purchased an additional 7.5% interest in the Paiton project from a subsidiary of General Electric Corporation, thereby increasing its ownership interest to 40%. Construction on the two-unit Paiton project is approximately 85% complete. The tariff is higher in the early years and steps down over time, and the tariff for the Paiton project includes infrastructure to be used in common by other units at the Paiton complex. The plant's output is fully contracted with the state-owned electricity company, PT Perusahaan Listrik Negara (PLN), for payment in U.S. dollars. The projected rate of growth of the Indonesian economy and the exchange rate of Indonesian Rupiah into U.S. dollars have deteriorated significantly since the Paiton project was contracted, approved and financed with substantial finance and insurance support from the Export-Import Bank of the United States, The Export-Import Bank of Japan, the U.S. Overseas Private Investment Corporation and the Ministry of International Trade and Industry of Japan. The Paiton project's senior debt ratings have been reduced from investment grade to speculative grade based on the rating agencies' perceived increased risk that PLN might not be able to honor the electricity sales contract with Paiton. A Presidential decree has deemed some power plants, but not including the Paiton project, subject to review, postponement or cancellation. Kwinana is a $108 million 116-MW gas-fired cogeneration project located at the British Petroleum Kwinana refinery near Perth, Australia. The project, which is 100% owned by EME, began commercial operations in December 1996. The project supplies electricity to Western Power (formerly the State 3 Electricity Commission of Western Australia) and electricity and steam to the British Petroleum Kwinana refinery. In December 1997, EME (40% ownership), along with its partners, Siam City Cement (30% ownership) and Lanna Lignite (30% ownership), signed a twenty-five year power purchase contract with the Electricity Generating Authority of Thailand (EGAT) pursuant to which EGAT will purchase 734 MW of output from the coal-fired power generation project at Kui Buri in Thailand. Financial closing and commencement of construction are anticipated in late 1998 or early 1999 with commercial operations expected to begin in 2001. In September 1997, the San Pascual project, a consortium including EME (37.5% ownership), Texaco Inc. (37.5% ownership) and Caltex (25% ownership), signed a twenty-five year power purchase contract with the National Power Corporation (NPC), Philippines' state-owned electric utility company, pursuant to which NPC will purchase 304 MW of output from the San Pascual project. The low-sulfur residual fuel oil cogeneration project is located in the Philippines. Financial closing and commencement of construction are anticipated in 1998 with commercial operations expected to begin in 2001. Europe, Central Asia, Middle East and Africa The European organization is headquartered in London, England with additional offices located in Italy, Spain and Turkey. The London office was established in 1989, concurrent with the privatization of the power industry in the United Kingdom. The territorial scope of the region includes Europe, Africa, the Middle East, India and Pakistan. The region is characterized by a blend of both mature and less developed markets. The regional strategy is to pursue the development and acquisition of medium to large scale power and cogeneration facilities with diversified fuel sources and generation technology. EME's operating projects in the region are the First Hydro project located in North Wales, the Roosecote project in northwest England, the Derwent project located in Derby, England and the Iberian Hy-Power projects (which consist of 18 small, hydroelectric facilities) in Spain. EME acquired initial ownership interests of Iberian Hy-Power I and II in December 1992 and August 1993, respectively. In January 1996, EME purchased the remaining equity stake in Iberian Hy-Power Amsterdam B.V., increasing its ownership percentage to approximately 100% (minority interests are owned in three of the projects by third parties). In December 1995, EME purchased all of the outstanding shares of First Hydro Company (First Hydro) for approximately $1 billion (653 million pounds sterling). First Hydro's principal assets are two pumped-storage electric power stations located in North Wales at Dinorwig and Ffestiniog, which have a combined capacity of 2,088 MW. The Dinorwig station, which was commissioned in 1983, is comprised of six units totaling 1,728 MW. The Ffestiniog station was commissioned in 1963 and is comprised of four units totaling 360 MW. First Hydro is an independent generating company with three main sources of revenues: (i) selling power into the electricity trading market or "pool" in England and Wales, (ii) providing system support services to The National Grid Company plc, and (iii) selling its installed capacity forward by entering into "contracts for differences" with large electricity suppliers. In June 1995, EME (49% ownership) and its partner, ISAB S.p.A. (51% ownership), signed a twenty-year power purchase contract with ENEL S.p.A., Italy's state electricity corporation, pursuant to which ENEL S.p.A. will purchase 507 MW of output from the 512-MW ISAB power project, which is located near Siracusa in Sicily, Italy. The project will employ gasification technology to convert heavy 4 oil residues from the ISAB refinery in Priolo Gargallo into clean-burning syngas that will be used to generate electricity in a combustion turbine. The approximately 2 trillion lira ($1.3 billion) project financial closing was completed in April 1996 with construction commencing in July 1996. The project is more than 75% complete with commercial operation expected in late 1999. In February 1995, EME (80% ownership) signed a shareholders' agreement to develop the $180 million Doga Enerji A.S. project in Esenyurt, near Istanbul, Turkey. The 180-MW combined cycle gas-fired cogeneration facility is approximately 63% complete with commercial operations expected in 1999. In April 1997, EME completed financing and commenced construction of the Doga project. PROJECT DEVELOPMENT The development of power generation projects involves numerous elements, including evaluating and selecting development opportunities, evaluating market risk, designing and engineering the project, acquiring necessary land rights, permits and fuel resources, obtaining financing and managing construction and, in some cases obtaining power sales agreements and steam sales agreements. EME initially evaluates and selects potential development projects based on a variety of factors, including whether a project is based on a proven technology, the strength of the potential partners in the project, the feasibility of the project, the likelihood of obtaining a power sales agreement, the probability of obtaining required licenses and permits and the projected economic return from the project. During the development process, EME monitors the viability of the project and makes business judgments concerning expenditures for both internal and external development costs. Completion of the financing arrangements for a project is generally an indication that business development activities are substantially complete. Although EME has in the past been successful in developing projects with long-term contracts and arranging for necessary permits and approvals, there can be no assurance that EME will continue to be successful in doing so in the future. EME believes that future market conditions for independent power, particularly in the United States, may become increasingly characterized by shorter-term power sales agreements or spot sales arrangements. EME may be required to consider market or "merchant" risk in the future. Project Type The selection of power generation technology for a particular project is influenced by various factors, including regulatory requirements, availability of fuel and anticipated economic advantages for a particular application. The principal technology used in EME's operating projects has been gas-fired combustion turbine technology, predominately through an application known as "cogeneration". Cogeneration facilities sequentially produce two or more useful forms of energy (e.g., electricity and steam) from a single primary source of fuel (e.g., natural gas or coal). Many of EME's cogeneration projects are located near large industrial steam users or in oil fields that inject steam underground to enhance recovery of heavy oil. The regulatory advantages for cogeneration facilities under PURPA have become less significant because of expanded project options made available to IPPs under the Energy Policy Act. Accordingly, although cogeneration may provide a competitive advantage in the new market place, EME expects that the majority of its future projects will generate power without selling steam to industrial users. 5 EME also has interests in projects that use renewable resources such as hydroelectric and geothermal energy. EME's hydroelectric projects, excluding First Hydro, use "run-of-the-river" technology to generate electricity. The First Hydro project utilizes pumped-storage stations which consume electricity when it is comparatively less expensive in order to pump water up for storage in an upper reservoir. Water is then allowed to flow back through turbines in order to generate electricity when its market value is higher. This type of generation is characterized by its speed of response, its ability to work efficiently at wide variations of load and the basic reliance of revenue on the difference between the peak and trough prices of electricity during the day. EME's geothermal projects use technologies that convert the heat from geothermal fluids and underground steam into electricity. EME has international interests in an operating project and projects under construction and advanced development which are large scale, coal-fired projects using pulverized coal in coal-fired generation technology. In the United States, EME has developed coal and waste coal-fired projects that employ traditional stoker and circulating fluidized bed technology. Power and Steam Sales Contracts Electric power and steam generated by EME's operating projects in the U.S. is sold primarily to domestic electric utilities and industrial steam users pursuant to long-term (typically, 15 to 30 year) contracts. Excluding the U.K. and a project in Australia, electric power generated overseas is sold primarily under long-term contracts to electric utilities located in the country where the power is generated. A project's revenue from a power sales contract usually consists of two components: energy payments and capacity payments. Energy payments are generally based on actual deliveries of electric energy (e.g., kilowatt-hours) to the purchasing utility. Energy payment rates are usually indexed to certain variable costs that the purchasing utility avoids by purchasing such electric energy directly as opposed to operating its own power plant(s) to produce the same amount of electric energy. The variable components typically include the fuel cost and certain operation and maintenance expenses. These costs may be indexed to the utility's cost of fuel and/or certain inflation indices. Energy payments may also be time-differentiated to provide relatively higher payments for electric energy delivered during periods of peak electricity demand. Capacity payments are generally based on a project's proven capability to deliver reliable electric energy, whether or not the plant is called on to operate. Capacity payment rates are usually associated with certain fixed costs that the purchasing utility avoids by having the independent power producer build and maintain the availability of a power plant. To receive capacity payments, there are typically minimum performance standards that must be met and often there is a performance range that further influences the amount of capacity payments. EME's power sales contracts are typically negotiated during the planning stage of a project. In negotiating the power sales contracts, EME attempts to secure long-term contracts that are expected to result in consistent cash flow under a wide range of economic and operating circumstances. To accomplish this, EME structures the revenue provisions of the power sales contract so that changes in the cost components of a facility (e.g., fuel costs) will correspond to, as effectively as possible, similar changes in the revenue components of the contract. In addition to entering into a power sales agreement, EME must make arrangements to interconnect its project to a local utility's electric system. The arrangement is typically evidenced through an interconnection agreement that sets forth the provisions for construction, payment and technical requirements for the interconnection facilities. In some cases, the project will interconnect with a utility system that is not the ultimate purchaser of electric power. In such circumstances, the project must arrange for the local utility to transmit or "wheel" its power to the ultimate purchaser. 6 Projects in the U.K. and a project in Australia sell their electrical energy and capacity through a centralized electricity pool, which establishes a half- hourly clearing price (also referred to as the "pool price"). The pool price is extremely volatile and in the U.K. can vary by as much as a factor of ten or more over the course of a few hours, due to the large differentials in demand according to the time of day. First Hydro mitigates a significant portion of the market risk of the pool by entering into contracts for differences (electricity rate swap agreements), related to either the selling or purchasing price of power, whereby a contract specifies a price at which the electricity will be traded, and the parties to the agreement make payments, calculated based on the difference between the price in the contract and the pool price for the element of power under contract. These contracts can be sold in two structures: one-way contracts, where a specified monthly amount is received in advance and difference payments are made when the pool price is above the price specified in the contract, and two-way contracts, where the counterparty pays First Hydro when the pool price is below that in the contract instead of a specified monthly amount. These contracts act as a means of stabilizing production revenues or purchasing costs by removing an element of First Hydro's net exposure to pool price volatility. The Roosecote project has avoided the pool price volatility by entering into a long-term power sales contract that provides for contract pricing. The Roosecote project's power sales contract provides for the escalation of capacity payments according to an inflation index for the U.K. Loy Yang B has entered into a number of financial hedges to mitigate exposure to price volatility of the electricity traded into the pool. From May 8, 1997 to December 31, 2000, approximately 53% to 64% of the plant output sold is hedged under "Vesting Contracts" with the remainder of the plant capacity hedged under the "State Hedge" described below. Vesting Contracts were put into place by the State, between each generator and each distributor, prior to the privatization of electric power distributors in order to provide more predictable pricing for those electricity customers that were unable to choose their electricity retailer. Vesting Contracts set base strike prices at which the electricity will be traded, and the parties to the agreement make payments, calculated based on the difference between the price in the contract and the half-hourly pool clearing price for the element of power under contract. These contracts can be sold as one-way or two-way contracts which are structured similar to the electricity rate swap agreements described above. These contracts are accounted for as electricity rate swap agreements. The State Hedge is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State guarantees SECV's obligations under the State Hedge. Steam produced from EME's cogeneration facilities is sold to industrial steam users, such as petroleum refineries or companies involved in the enhanced recovery of oil through steam flooding of oil fields, under long-term steam sales contracts. Domestic steam sales contracts require the purchaser to take at least the minimum amount of steam necessary for the project to retain its QF status under PURPA. Steam payments are generally based on formulas that reflect the cost of water, fuel and capital. In some cases, EME has provided steam purchasers with discounts from their previous cost for producing such steam and/or partially indexed steam payments to other indices including certain oil prices. 7 Fuel Supply Contracts EME seeks to enter into long-term fuel supply and transportation agreements. Market prices for oil, gas and coal historically have fluctuated significantly. EME believes, however, that its financial condition will not be substantially adversely affected by such fluctuations because its long-term contracts to sell power and steam typically are structured so that fluctuations in fuel costs will produce similar fluctuations in electric energy and/or steam revenues. The degree of linkage between such revenues and expenses varies from project to project, but generally permits the projects to operate profitably under a wide array of potential price fluctuation scenarios. Project Financing Each power generation project developed by EME requires a substantial capital investment. The permanent project financing for a project is often arranged immediately prior to the construction of the project. With limited exceptions, such debt financing is for approximately 60 to 80% of each project's costs and is expected to be structured, on a basis that is nonrecourse to EME and its other projects. In addition, the collateral security for each project's financing generally has been limited to the physical assets, contracts and cash flow of that project. In general, each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Any asset of any such subsidiary may not be available to satisfy the obligations of EME or any of its other such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or its affiliates. The ability to arrange for 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, EME and other project participants, the continued success of EME's current projects, and provisions of tax and securities laws that are conducive to raising capital. To obtain project financing, EME and its partners are sometimes required to provide certain guarantees and warranties to lenders, particularly with respect to construction financing. However, because permanent financing is usually arranged on a nonrecourse basis, EME's liability is generally substantially reduced when construction has been completed and the project has passed all acceptance tests. EME's financial exposure in any project is generally limited by contractual arrangement to its equity commitment, which is usually about 20 to 40% of EME's share of the aggregate project cost. In addition, the project loan agreements are generally structured so that a default under one project loan agreement will have no effect on the loan agreements of other EME projects. Permits and Approvals Because the process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy (often taking a year or longer), EME seeks to obtain all permits, licenses and other approvals required for the construction and operation of the project, including siting, construction and environmental permits, rights-of-way and planning approvals, early in the development process. See "Certain Regulatory Matters-- General". 8 Construction and Implementation In the project implementation stage, EME provides project and construction management and start-up and testing services. The detailed engineering and construction of the projects typically are done by outside contractors under fixed-price, "turnkey" contracts. Under such contracts, the contractor generally is required to pay liquidated damages to EME in the event of cost overruns or schedule delays or if the facility fails to meet certain capacity, efficiency and emission standards. As a project goes into operation, operation and maintenance services are provided to the project by one of EME's operation and maintenance subsidiaries or another operation and maintenance contractor. The day-to-day operation of each project is generally managed by an executive director. Management committees comprised of the project partners generally meet monthly or quarterly to review and manage the operating performance of each project. Certain Considerations Associated with Project Development, Finance and Operation Independent power projects are necessarily subject to a variety of commercial, financial and other risks, including those described below. By managing, or participating in the management of each project in which it invests, EME seeks to hedge, insure against or otherwise manage these risks. EME attempts to minimize the financial risk in the development of a project by securing a favorable long-term power sales agreement, obtaining all required governmental permits and approvals and arranging adequate financing prior to the commencement of construction. However, the development of a power project may require EME to expend significant sums for preliminary engineering, permitting and legal and other expenses before it can determine whether a project is feasible, economically attractive or financeable. Power sales agreements often enable the utility to terminate such agreement, or to retain security posted by the developer as liquidated damages, in the event that a project fails to achieve commercial operation or certain operating levels by specified dates or fails to meet other significant contractual requirements. Furthermore, utility regulators or other parties may attempt to abrogate or amend contracts under which a project is entitled to receive material revenues or other benefits. If such events were to occur, the default provisions in a financing agreement could be triggered (rendering such project debt immediately due and payable) and, as a result, EME could lose its interest in the project. Although contractual and regulatory risks cannot be eliminated, EME believes that it has relevant experience in developing contracts and mitigating regulatory concerns. Certain geographic areas in which EME operates and is developing projects are subject to frequent earthquakes of low intensity, and earthquakes of greater intensity are possible. EME's existing power generation facilities are built to withstand earthquakes of relatively significant intensity and EME believes it maintains adequate insurance protection for such occurrences and other catastrophic events. The operation of a project involves many risks, including start-up problems, the breakdown or failure of equipment or processes, performance below expected levels of output and the inability to meet expected efficiency standards. EME takes steps to mitigate these risks by obtaining equipment and plant warranties and arranging for insurance that it believes is adequate. Nonetheless, these measures 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 EME losing its interest in such power generation facility. 9 EME believes, however, that it will continue to maintain a successful record of plant performance and operation. EME's operations are conducted through its subsidiaries and EME's cash flow is dependent upon the operating revenues of its subsidiaries and the ability of those subsidiaries to pay cash dividends or make distributions to EME. Financing agreements for EME's subsidiaries and affiliates generally place certain limitations on the ability of those subsidiaries and affiliates to pay dividends, make distributions or otherwise transfer funds to EME. In addition, financing agreements for EME's subsidiaries and affiliates, although generally nonrecourse to EME, contain certain representations, warranties, covenants and other agreements that, if not met, could lead to a default under such financing. After a default under a project financing for any reason, project lenders may exercise certain rights and remedies typically granted to secured parties, including the ability to take control of the project's collateral assets. The financing and development of international projects entail additional political and financial risks including uncertainties associated with privatization efforts, currency exchange rates, currency repatriation, political instability and other issues that have the potential to cause delays or impairment of value to the project being developed for which EME may not be fully capable of insuring against. The uncertainty of the legal structure in certain foreign countries in which EME may develop or acquire projects could make it more difficult to enforce its rights under agreements relating to such projects. In addition, the laws and regulations of certain countries may limit the ability of EME to hold a majority interest in some of the projects that it may develop or acquire. Although the risks of participation in international markets are significant, EME targets relatively higher rates of return on its international investments and mitigates risk by seeking complimentary alliances with well-established partners and hedging foreign exchange exposure where it deems appropriate. OPERATION AND MAINTENANCE SERVICES Certain EME subsidiaries provide specialized operating, maintenance, testing and start-up services for EME-owned projects. At December 31, 1997, Edison Mission O&M or other subsidiaries had a total of 877 employees and operated 37 of EME's projects totaling 5,161 MW of capacity. The projects that EME operates have achieved an average 97% availability during 1997. Availability is a measure of the weighted average number of hours each generator is available for generation as a percentage of the total number of hours in a year. EME'S OPERATING POWER GENERATION FACILITIES Domestic Overview EME currently owns interests in 26 domestic operating projects in eight states. These operating projects consist of 16 natural gas cogeneration projects, one coal cogeneration project, one waste coal project, four geothermal projects and four gas-fired EWG (as defined herein) projects. All of EME's domestic cogeneration and geothermal projects, as well as the waste coal project, are qualifying facilities under PURPA. EME's domestic operating projects have total generating capacity of 3,679 MW, of which EME's net ownership share is 1,640 MW. Each of EME's projects generally relies on one power sales contract with a single electric utility customer for the majority, and in some cases all, of its power sales revenues over the life of the power sales contract. The primary power sales contracts for seven of EME's operating projects are with SCE. 10 EME's share of revenues from these projects accounted for 12% of EME's consolidated revenues in 1997 and 1996. The failure of SCE to fulfill its contractual obligations could have a negative impact on a source of EME's revenues. Under the terms of an agreement between SCE and the Office of Ratepayer Advocates (ORA), the consumer advocacy branch of the California Public Utility Commission (CPUC), SCE is prohibited from entering into future power sales contracts with EME or its affiliates without ORA and CPUC consent. The terms of the agreement, however, do not affect the terms of the existing power sales contracts between EME and SCE. Fuel supply for EME's projects generally is arranged through third-party suppliers and transporters. EME's geothermal projects have power sales agreements that provide for energy payments that escalate at predetermined rates during the first 10 years of plant operation. After the initial 10-year period, the energy payments will be based on rates published monthly by the purchasing utility that reflect its cost for natural gas and/or oil. Based on current forecasts of natural gas and oil prices, EME expects the energy payment rate to drop substantially after the initial 10-year period. Accordingly, cash distributions received from these projects are recorded as reductions in the equity investments. Future cash distributions are estimated to be sufficient to recover the remaining geothermal investment balances. In April 1996, CalEnergy Company, Inc., EME's partner in four operating geothermal projects in California, purchased all of the stock of four wholly owned subsidiaries of EME, which held 50% interests in these projects. The purchase price of $70 million resulted in a pre-tax gain of $20 million. There will be no impact on EME's future revenues as EME discontinued recognizing earnings from these projects during 1993. In January 1998, Oxbow Power of Beowawe, Inc., EME's partner in an operating geothermal project in Nevada, purchased EME's 50% general partnership interest in this project from a wholly owned subsidiary of EME. The purchase price of $4.1 million resulted in an after tax gain of $1.1 million. There will be no impact on EME's future revenues as EME discontinued recognizing earnings from this project in 1996. In February 1998, the CPUC issued an order which approved an agreement entered into in August 1997 between an operating geothermal project in California in which EME has a 50% partnership interest and SCE to terminate two power sales agreements. There will be no negative impact on EME's future revenues as EME discontinued recognizing earnings from this project during 1993. 11 Description of Domestic Operating Projects EME has ownership interests in the following domestic operating projects:
ELECTRIC PRIMARY OPERATION/ CAPACITY ELECTRIC TYPE OF OWNERSHIP ACQUISITION PROJECT LOCATION (IN MW) PURCHASER(3) FACILITY(4) INTEREST DATE - ------- -------- ------- ------------ ----------- -------- ----------- Aidlin(1) Cloverdale, California 20 PG&E Geothermal 5% 1990 American Bituminous(2) Grant Town, West Virginia 80 MPC Waste Coal 50% 1993 Auburndale(2) Polk County, Florida 150 FPC EWG 50% 1994 Bayonne Bayonne, New Jersey 165 JCP&L/PSE&G Cogeneration 0.38% 1989 Brooklyn Navy Yard Brooklyn, New York 286 CE Cogeneration 50% 1996 Coalinga(2) Coalinga, California 38 PG&E Cogeneration 50% 1991 Commonwealth Atlantic Chesapeake, Virginia 340 VEPCO EWG 50% 1992 GEO East Mesa(1,2) Holtville, California 40 SCE Geothermal 50% 1989 Gordonsville(2) Gordonsville, Virginia 240 VEPCO EWG 50% 1994 Harbor(2) Wilmington, California 80 SCE Cogeneration 30% 1989 Hopewell Hopewell, Virginia 356 VEPCO Cogeneration 25% 1990 James River Hopewell, Virginia 110 VEPCO Cogeneration 50% 1987 Kern River(2) Oildale, California 300 SCE Cogeneration 50% 1985 Lost Hills Lost Hills, California 10 PG&E Cogeneration 50.09% 1989 March Point 1 Anacortes, Washington 80 PSE Cogeneration 50% 1991 March Point 2 Anacortes, Washington 60 PSE Cogeneration 50% 1993 Mid-Set(2) Fellows, California 38 PG&E Cogeneration 50% 1989 Midway-Sunset(2) Fellows, California 225 SCE Cogeneration 50% 1989 Nevada Sun-Peak Las Vegas, Nevada 210 NVP EWG 50% 1991 Saguaro(2) Henderson, Nevada 90 NVP Cogeneration 50% 1991 Salinas River(2) San Ardo, California 38 PG&E Cogeneration 50% 1991 Sargent Canyon(2) San Ardo, California 38 PG&E Cogeneration 50% 1991 Sycamore(2) Oildale, California 300 SCE Cogeneration 50% 1988 Watson Carson, California 385 SCE Cogeneration 49% 1988
(1) Consists of two projects on the same site. (2) Operated by EME. (3) Electric purchaser abbreviations are as follows: CE Consolidated Edison Company of New York, Inc. PG&E Pacific Gas & Electric Company FPC Florida Power Corporation PSE Puget Sound Energy JCP&L Jersey Central Power & Light Company PSE&G Public Service Electric & Gas Company MPC Monongahela Power Company SCE Southern California Edison Company NVP Nevada Power Company VEPCO Virginia Electric & Power Company
(4) All of the cogeneration projects are gas-fired facilities, except for the James River project, which uses coal. 12 International Overview EME owns interests in 24 operating projects outside the United States. The total generating capacity of such facilities is 3,724 MW, of which EME's net ownership share is 3,533 MW. Description of International Operating Projects EME has ownership interests in the following international operating projects:
ELECTRIC OPERATION/ CAPACITY PRIMARY ELECTRIC OWNERSHIP ACQUISITION PROJECT LOCATION (IN MW) PURCHASER(2) INTEREST DATE - ------- -------- ------- ------------ --------- ---------- Alos(1) Spain 5 FECSA 100% 1993 Bocos(1) Spain 2 FECSA 100% 1993 Castellas(1) Spain 2 FECSA 100% 1993 Derwent(1) England 214 SE(3) 33% 1995 Dinorwig(1) Wales 1,728 Pool 100% 1995 Ffestiniog(1) Wales 360 Pool 100% 1995 Gelsa(1) Spain 7 FECSA 100% 1993 Kwinana(1) Australia 116 WP 100% 1996 La Flecha(1) Spain 3 FECSA 100% 1993 La Ribera(1) Spain 4 FECSA 100% 1993 Logrono(1) Spain 4 FECSA 100% 1993 Loy Yang B(1) Australia 1,000 Pool(4) 100% 1993, 1996, 1997 Mendavia(1) Spain 6 FECSA 100% 1993 Menuza(1) Spain 17 FECSA 91.3% 1992 Monasterio(1) Spain 2 FECSA 100% 1993 Olvera(1) Spain 2 FECSA 100% 1992 Quintana(1) Spain 1 FECSA 100% 1993 Roosecote England 220 NORWEB(5) 80% 1992 Sardon Bajo(1) Spain 2 FECSA 100% 1993 Sastago I(1) Spain 3 FECSA 91.3% 1992 Sastago II(1) Spain 17 FECSA 91.3% 1992 Sossis(1) Spain 4 FECSA 100% 1992 Toro(1) Spain 4 FECSA 100% 1993 Tudela(1) Spain 1 FECSA 100% 1993
(1) Operated by EME. (2) Electric purchaser abbreviations are as follows: FECSA Fuerzas Electricas de Cataluma, S.A. Pool Electricity trading market for England, NORWEB North Western Electricity Board Wales and Australia WP Western Power SE Southern Electric plc.
(3) Sells to the pool with a long-term contract with SE. (4) Sells to the pool with a long-term contract with the State Electricity Commission of Victoria. (5) Sells to the pool with a long-term contract with NORWEB. 13 OIL AND GAS INVESTMENTS In 1988, EME formed a wholly owned subsidiary, Mission Energy Fuel Company, to develop and invest in fuel interests. Since that time, EME has invested in a number of oil and gas properties and a production company. Oil and gas produced from the properties are generally sold at spot or short-term market prices. Four Star As of December 31, 1997, EME owned 46.85% of the stock of Four Star Oil & Gas Company (Four Star), a subsidiary of Texaco Inc. The underlying value of Four Star is attributable to production of oil and gas from nine producing properties. EME's proportionate interest in net quantities of proved reserves at December 31, 1997 totaled 189 billion cubic feet of natural gas and 21.6 million barrels of oil. During 1995, EME and/or Four Star entered into a series of transactions which resulted in a net increase in EME's ownership of Four Star by 2.47%. During 1996, EME purchased additional shares of stock of Four Star increasing its ownership by 4.38%. In January 1998, EME purchased additional shares of stock of Four Star for approximately $4 million increasing its ownership by 3.24% to 50.09% and its voting ownership to 48.97%. B.C. Star B.C. Star was formed in 1991 when a subsidiary of EME and a subsidiary of Texaco Inc. each purchased a 50% partnership interest in certain proved producing properties from Esso Resources Canada Limited. These properties are geographically concentrated in the northeast region of British Columbia and enjoy proximity and direct pipeline access to the Pacific Northwest and California. Texaco Canada Petroleum Inc. operates the majority of B.C. Star's properties. During the second quarter of 1997, EME completed a sale of its ownership interest in B.C. Star for approximately $71 million. EME recorded an after-tax gain of approximately $14 million on the sale. COMPETITION EME competes with many other companies, including multinational development groups, equipment suppliers and other IPPs (including affiliates of utilities), in selling electric power and steam, and with electric utilities in obtaining the right to install new generating capacity. Over the past decade, obtaining a power sales contract with a utility has generally become a progressively more difficult, expensive and competitive process. Many power sales contracts are now awarded by competitive bidding, which both increases the costs of obtaining such contracts and decreases the chances of obtaining such contracts. 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. EME evaluates each potential project in an effort to determine when the probability of success is high enough to justify expenditures in developing a proposal or bid for the project. Amendments to the Public Utility Holding Company Act of 1935 (PUHCA) made by the Energy Policy Act have increased the number of competitors in the domestic independent power industry by 14 reducing certain restrictions applicable to projects that are not QFs under PURPA. "Retail wheeling" of power could also lead to increased competition in the independent power market. See "Certain Regulatory Matters--Retail Competition". TAX SHARING AGREEMENTS EME is included in the consolidated federal income tax and state franchise tax returns of Edison International. EME calculates its current tax benefit receivable on a separate company basis under a tax sharing agreement with The Mission Group, which in turn has a tax sharing agreement with Edison International. The Mission Group receives payment from Edison International for tax benefits and pays Edison International for tax liabilities. The Mission Group similarly pays EME for tax benefits and EME pays The Mission Group for tax liabilities. EMPLOYEES AND OFFICES At February 27, 1998, EME employed 1,172 people, all of whom were full-time employees and approximately 216, 26 and 144 of whom were covered by a collective bargaining agreement in Wales, Spain and Australia, respectively. EME has never experienced a work stoppage, strike or labor dispute. EME believes its relations with its employees to be good. EME leases its corporate headquarters in Irvine, California and its principal regional offices in London, Melbourne and Singapore. It also leases other smaller offices in the United States and certain foreign countries. CERTAIN REGULATORY MATTERS - -------------------------- GENERAL EME's domestic projects are subject to 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 projects. Federal laws and regulations govern, among other things, transactions by and with utility companies, the operations of a project and the ownership of a project. Under certain circumstances where exclusive federal jurisdiction is not applicable or specific exemptions are otherwise unavailable, state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Energy-producing projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning, land use and operation of a project. Federal, state and local environmental requirements 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. While EME believes the requisite approvals for its existing projects have been obtained and that its business is operated in substantial compliance with applicable laws, EME remains subject to a varied and complex body of laws and regulations that both public officials and private parties may seek to enforce. There can be no assurance that future developments will not have a material adverse effect on EME's business or results of operations, nor can there be any assurance that EME will be able to obtain and comply with all necessary licenses, permits and approvals for proposed projects. In addition, regulatory compliance for the construction of new facilities is a costly and time consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures and may 15 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. Each of EME's international projects will be (or, to the extent that such projects are already in operation or under construction, currently are) subject to the energy and environmental laws and regulations of the foreign jurisdiction in which it is located. The degree of regulation will vary according to each country and may be materially different from the regulatory regime in the United States. U.S. FEDERAL ENERGY REGULATION The enactment of PURPA in 1978 and the adoption of regulations thereunder by the Federal Energy Regulatory Commission (FERC) provided incentives for the development of cogeneration facilities and small power production facilities (those utilizing alternative or renewable fuels). The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing certain exemptions from PUHCA (but not from the Federal Power Act (FPA) or state regulation) for exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). 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. Subject to certain exceptions, PURPA exempts owners of QFs from PUHCA, exempts QFs from most provisions of the FPA and, except under certain limited circumstances, state laws concerning rate or financial regulation. In order to be a QF, a cogeneration facility must (i) sequentially produce both useful thermal (e.g., steam) and electric energy, (ii) meet certain operating standards and energy efficiency standards when oil or natural gas is used as a fuel source and (iii) not be controlled, or more than 50% owned by, an electric utility, electric utility holding company or an affiliate thereof. A non-cogeneration facility may also be a QF if it produces power from renewable energy (e.g., geothermal energy) or a waste source of fuel (e.g., waste coal). Before 1990, non-cogeneration QFs were subject to 30-MW or 80-MW size limits, depending upon their fuel source. In 1990, these limits were lifted for solar, wind, waste, and geothermal QFs, provided that applications for or notices of QF status were filed with FERC for such facilities on or before December 31, 1994, and provided, in the case of new facilities, the construction of such facilities commenced on or before December 31, 1999. Amendments made to PUHCA by the Energy Policy Act provide that owners or operators of EWGs and FUCOs will not be considered "electric utility companies" under PUHCA. An EWG is an entity determined by the FERC to be exclusively engaged, directly or indirectly, in the business of owning and/or operating certain eligible facilities and selling electric energy at wholesale (or, if located in a foreign country, at wholesale or retail). A FUCO is, in general, an entity located outside the United States that owns or operates facilities used for the generation, distribution or transmission of electric energy for sale or the distribution at retail of natural or manufactured gas, but derives none of its income, directly or indirectly, from such activities within the United States. The exemptions from federal and state regulation afforded to QFs, and the exemptions from PUHCA afforded to EWGs and FUCOs, are important to EME and to its competitors. Under present federal law, EME is not and will not be subject to regulation as a holding company under PUHCA as long as the projects in which it has an interest are QFs, EWGs or FUCOs (or are subject to another exemption from regulation). Of the projects that EME currently owns, operates or has an investment in, 22 projects have been certified as QFs by the FERC, four projects have been certified as EWGs and 15 projects are FUCOs. Most of the U.S. projects currently in the planning or development stage are expected to be QFs and the international projects are expected to be FUCOs. To the extent that any of 16 EME's projects in the development stage will not be QFs or FUCOs, EME expects to qualify those projects as EWGs. See "PUHCA". PURPA PURPA provides two primary benefits to QFs. First, QFs are relieved of compliance with extensive federal and state regulations that control the development, financial structure and operation of an energy-producing project and the prices and terms on which wholesale energy may be sold by the project. Second, FERC 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 utilities sell back-up power to the QF on a non-discriminatory basis. The term "avoided cost" is defined by PURPA as the "incremental cost to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source." FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at prices lower than the utility's avoided costs. While public utilities are not explicitly required by PURPA to enter into long- term contracts, it has been common for long-term contracts to be negotiated in order, among other things, to facilitate project financing of independent power facilities and to reflect the deferral by the utility of capital costs for new plant additions. However, increasing competition and power brokering may result in a trend toward shorter term power contracts that would place greater risk on the project owner. EME endeavors to develop its QF projects, monitor regulatory compliance by such projects and choose its customers in a manner that minimizes the risks of losing such projects' QF status. However, certain factors necessary to maintain QF status are subject to the risk of events outside EME's control. For example, loss of a thermal energy customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a QF could cause the facility to fail requirements regarding the level of useful thermal energy output. Upon the occurrence of such an event, EME would seek to replace the thermal energy customer or find another use for the thermal energy that meets PURPA's requirements, but no assurance can be given that this would be possible. If one of the projects in which EME has an interest was to lose its status as a QF, the project would no longer be entitled to the QF-related exemptions from regulation under PUHCA and the FPA. This could subject the project to rate regulation as a public utility under the FPA and could result in EME 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. Loss of QF status may also trigger defaults under covenants to maintain QF status in the project's power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. Such loss of QF status may be on a retroactive or a prospective basis. If a power purchaser ceased taking and paying for electricity or sought to obtain refunds of past amounts paid due to the loss of QF status, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, EME's business and financial condition could be adversely affected if regulations or legislation were modified or enacted that changed the standards for achieving QF status or that eliminated or reduced the benefits currently enjoyed by QFs. If a project were to lose its QF status, EME could attempt to avoid holding company status on a prospective basis by qualifying the project as an EWG. However, assuming this changed status would be permissible under the terms of the applicable power sales agreement, rate approval from the FERC would be required. In addition, the project would be required to cease selling electricity to any retail customers (in order to qualify for EWG status) and could become subject to state regulation of sales of thermal energy. Loss of QF status on a retroactive basis could lead to, among other things, fines 17 and penalties being levied against EME and its subsidiaries, or claims by the utility customer for refund of payments previously made. Loss of QF status by one project could also, because of PURPA ownership restrictions, adversely affect the QF status of other projects having one or more of the same partners. In addition, pursuant to Section 26(b) of PUHCA, any project contracts that are entered into in violation of PUHCA are subject to possible voidability by the courts should a lawsuit to void the contract be filed. The Energy Policy Act The passage of the Energy Policy Act in 1992 significantly expanded the options available to IPPs with respect to their regulatory status. The Energy Policy Act created a new class of power producer, the EWG, that (like a QF) is not considered an electric utility company under PUHCA. EWGs may own facilities of any size, use any fuel source and may be owned by utilities or non-utilities. Thus, in addition to QF status, an IPP now can also apply to the FERC to be granted status as an EWG. EWGs, however, are not exempt from regulation by the FERC or state public utility commissions. The effect of such amendments is to enhance the development of non-QFs that do not have to meet the fuel, production and ownership requirements of PURPA. EME believes that the amendments benefit EME by expanding its ability to own and operate facilities that do not qualify for QF status, but may also result in increased competition because utilities and other companies (e.g., equipment suppliers) may now develop facilities that are not subject to the constraints of PUHCA. The Energy Policy Act also expanded FERC authority to order utilities to grant transmission access to QFs and EWGs and lifted restrictions on ownership of foreign utilities by U.S. companies. Pursuant to the Energy Policy Act, FUCOs are also considered not to be electric utility companies under PUHCA. PUHCA Under PUHCA, any corporation, partnership or other entity or organized group that owns, controls or holds with power to vote 10% or more of the outstanding voting securities of a "public-utility company" or a company that is a "holding company" of a public utility company, is subject to registration with the Securities and Exchange Commission (SEC) and regulation under PUHCA, unless eligible for an exemption or unless an appropriate application is filed with, and an order is granted by, the SEC declaring it not to be a holding company. A registered public utility holding company regulated under PUHCA is required to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of that utility system. Approval by the SEC is required for major financial commitments and other business dealings of the regulated holding company or its subsidiaries. As noted above, however, regulations have been adopted under PURPA and the Energy Policy Act providing that QFs, EWGs and FUCOs are not public utility companies. Accordingly, EME is not regulated as a "holding company" under PUHCA because the power generation facilities owned by EME or in which EME has investments are either QFs, EWGs or FUCOs. All international projects and certain U.S. projects that EME is currently developing will be non-QF independent power projects. EME intends for each such project to qualify as an EWG or as a FUCO. Loss of EWG or FUCO status (like loss of QF status, as discussed above) could also result in EME becoming subject to registration and regulation as a public utility holding company under PUHCA and could trigger defaults under covenants in project agreements. Loss of EWG or FUCO status on a retroactive basis could lead to, among other things, fines and penalties and could cause certain project contracts to be voidable. 18 Natural Gas Act Twenty of the domestic operating facilities that EME owns, operates or has investments in are fueled by natural gas. Pursuant to the Natural Gas Act, the FERC has jurisdiction over the sale, 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 the FERC in April 1992 (and affirmed in Orders 636A and 636B issued, respectively, in August and November 1992), mandated the restructuring of interstate natural gas pipeline sales and transportation services and changed the terms and conditions under which interstate pipelines provide transportation services, as well as the rates pipelines may charge for such services. The restructuring required by the rule included (i) the separation (unbundling) of a pipeline's sales, transportation and storage 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. FPA The FPA grants the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity in interstate commerce, including ongoing as well as initial rate jurisdiction, which enables the FERC to revoke or modify previously approved rates. Such rates may be based on a cost-of-service approach or may, in competitive markets, be market-based. While qualifying facilities under PURPA generally are exempt from the ratemaking and certain other provisions of the FPA, EWGs and other non-QF independent power projects are subject to the FPA and to FERC ratemaking jurisdiction, which may limit their flexibility in negotiations with power purchasers. However, since such projects would not be bound by PURPA's thermal energy use requirement, they have greater latitude in site selection and facility size. Currently, only three of EME's operating projects, Nevada Sun-Peak, Brooklyn Navy Yard and Commonwealth Atlantic, are subject to FERC rate-making regulation under the FPA. EME's future domestic non-QF independent power projects will also be subject to FERC jurisdiction on rates. STATE ENERGY REGULATION State public utility commissions (PUCs) have broad jurisdiction over non-QF independent power projects (including EWGs), which are considered public utilities in many states. Such jurisdiction often includes the issuance of certificates of public convenience and necessity (CPCNs) to construct a facility as well as regulation of organizational, accounting, financial and other corporate matters on an ongoing basis. QFs may also be required to obtain CPCNs in some states. Although the FERC generally has exclusive jurisdiction over the rates charged by a non-QF independent power project to its wholesale customers, PUCs have the ability, in practice, to influence the establishment of such rates by asserting jurisdiction over the purchasing utility's ability to pass-through the resulting cost of purchased power to its retail customers. PUCs also have the authority to determine avoided cost for QFs. In addition, states may assert jurisdiction over the siting and construction of independent power projects and, among other things, the issuance of securities, related party transactions and the sale or other transfer of assets by 19 these facilities. The actual scope of jurisdiction over independent power projects by state PUCs varies from state to state. In addition, state PUCs may seek to modify, suspend or terminate a QF's power sales contract under certain circumstances. This could occur if the state PUC determined that the pricing mechanism of the power sales contract is unfairly high in light of the current prevailing market cost of power for the utility purchasing the power. In such instance, the state PUC may attempt to alter the terms of the power sales contract to reflect more accurately market conditions for the prevailing cost of power. While EME believes that such attempts are not common and that the state PUCs may not have any jurisdiction to modify the terms of the wholesale power sales, there can be no assurance that the power sales contracts of its projects will not be subject to adverse regulatory actions. The CPUC has authorized the electric utilities in California to "monitor" compliance by QFs with PURPA rules and regulation. However, the United States Court of Appeals for the Ninth Circuit found in 1994 that a CPUC program was preempted by PURPA insofar as it authorized utilities to determine that a QF was not in compliance with PURPA rules and regulations, to then pay a reduced avoided cost rate and to take other action contrary to a facility's status as a QF. The court did, however, uphold reasonable monitoring of QF operating data. Other states, such as New York, have also instituted QF monitoring programs. EME buys and transports the natural gas used at its domestic facilities through local distribution companies (LDCs). State PUCs have jurisdiction over the transportation of natural gas by 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. TRANSMISSION OF WHOLESALE POWER Projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others (wheeling). The prices and other terms and conditions of transmission contracts are regulated by FERC, when the entity providing the wheeling service is a jurisdictional public utility under the FPA. Until 1992, FERC's ability to compel wheeling was very limited, and the availability of voluntary wheeling service could be a significant factor in determining whether a site was viable for project development. FERC's authority under the FPA to require electric utilities to provide transmission service on a case-by-case basis to QFs, EWGs, and other power generators was expanded substantially by the Energy Policy Act. Furthermore, in 1996 FERC issued a rulemaking order, Order 888, in which FERC asserted the power, under its authority to eliminate undue discrimination in transmission, to compel all jurisdictional public utilities under the FPA to file open access transmission tariffs consistent with a pro forma tariff drafted by FERC. Although the pro forma tariff does not cover the pricing of transmission service, Order 888 is expected to improve transmission access for independent power producers such as EME. RETAIL COMPETITION In response to pressure from retail electric customers, particularly large industrial users, the state commissions or state legislatures of most states are considering, or have considered, whether to open the 20 retail electric power market to competition. Retail competition is possible when a customer's local utility agrees, or is required, to "unbundle" its distribution service (e.g., the delivery of electric power through its local distribution lines) from its transmission and generation service (e.g., the provision of electric power from the utility's generating facilities or wholesale power purchases). A few state commissions and legislatures have already issued orders or passed legislation requiring utilities to begin to offer unbundled retail distribution service (retail wheeling) beginning as soon as 1998. Other states are expected to move toward retail competition by 2000. The competitive pricing environment that will result from retail competition may cause utilities to experience revenue shortfalls and deteriorating creditworthiness. However, EME expects that most, if not all, state plans will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay their obligations under existing long-term power purchase contracts with QFs and EWGs. On the other hand, QFs and EWGs may be subject to pressure to lower their contract prices in an effort to reduce the "stranded investment" costs of their utility customers. EME believes that, as a predominately low cost producer of electricity, it will ultimately benefit from any increased competition that may arise from the opening of the retail market. Although EME's EWGs are forbidden under PUHCA from selling electric power at retail, its QFs will be permitted to market power directly to large industrial users that could not previously be served, because of local franchise laws or the inability to obtain retail wheeling. EME also believes it will be an attractive supplier to power marketers serving the newly- open retail markets. ENVIRONMENTAL REGULATION The construction and operation of power projects are subject to environmental regulation by federal, state and local authorities in the United States and regulatory authorities with jurisdiction over the projects located outside the United States. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial condition or results of operations. EME conducted a review of some of its sites in 1995 and does not believe that a material liability exists as of December 31, 1997. However, possible future developments, such as more stringent environmental laws and regulations, could affect the costs and the manner in which EME conducts its business. There can be no assurance that in such event EME would be able to recover such increased costs from its customers or that its financial position and results of operations would not be materially adversely affected. Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all of the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures. In 1990, Congress passed amendments (the 1990 Amendments) to the Clean Air Act that greatly expand the scope of federal regulations in several significant respects. An EME project is anticipated to make capital expenditures of approximately $11.6 million ($5.8 million is EME's share) from 1998 through 1999 in order to comply with the 1990 Amendments. Provisions related to nonattainment, air toxins, permitting, enforcement and "acid rain" may affect EME's projects; however, final details of all these programs have not been issued by the United States Environmental Protection Agency and state agencies. 21 The Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) requires the cleanup of sites from which there has been a release or threatened release of hazardous substances. At the present time, EME is not aware of any Superfund liability; however, there can be no assurance that EME will not incur such liability in the future. FOREIGN AND DOMESTIC OPERATIONS - ------------------------------- A summary of EME's operations by geographic area including operating revenues, net income (loss) and identifiable assets is incorporated herein by reference from note 15 (Geographic Areas--Financial Data) of Notes to the Consolidated Financial Statements. ITEM 2. PROPERTIES EME leases its principal office in Irvine, California. This lease is approximately 92,600 square feet contained on six floors. The term of the lease for approximately 65,500 square feet expires on December 31, 2002 with two five- year options to extend. The term of the lease for the balance of approximately 27,100 square feet expires on December 31, 2002 with no options to extend. EME also leases office space in Fairfax, Virginia and Washington, D.C. which is not material. Subsidiaries of EME also lease office space in Barcelona, Spain; Esenyurt, Turkey; Jakarta, Indonesia; London, England; Manila, Philippines; Melbourne, Australia; Rome, Italy; and Singapore, none of which are material. The following table shows the material properties owned or leased by EME, its subsidiaries, or partnerships. Each property represents at least five percent of EME's income before tax or is one in which EME has an investment balance greater than $50 million. All of these properties are subject to mortgages or other liens or encumbrances granted to the lenders providing financing for the plant or project. 22 DESCRIPTION OF PROPERTIES
INTEREST PLANT OR PROJECT LOCATION IN LAND PLANT DESCRIPTION - ---------------- -------- ------- ----------------- Brooklyn Navy Yard Brooklyn, New York Leased Natural gas-turbine cogeneration facility First Hydro Dinorwig, Wales Owned Pumped-storage electric power facility First Hydro Ffestiniog, Wales Owned Pumped-storage electric power facility Kern River Oildale, California Leased Natural gas-turbine cogeneration facility Loy Yang B Victoria, Australia Owned Coal-fired power facility Midway-Sunset Fellows, California Leased Natural gas-turbine cogeneration facility Paiton East Java, Indonesia Leased Coal-fired power facility under construction Roosecote Barrow-in-Furness,Cumbria, UK Owned Combined cycle generation technology Sycamore Oildale, California Leased Natural gas-turbine cogeneration facility Watson Carson, California Leased Natural gas-turbine cogeneration facility
ITEM 3. LEGAL PROCEEDINGS PMNC Litigation -In February 1997, a civil action was commenced in the --------------- Superior Court of the State of California, Orange County, entitled The Parsons ----------- Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission - ------------------------------------------------------------------------------- Energy New York, Inc. and B-41 Associates. L.P., Case No. 774980, in which - ----------------------------------------------- plaintiffs assert general monetary claims under the Construction Turnkey Agreement in the amount of $136,800,000. Brooklyn Navy Yard has also filed an ------------------------------------ action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons - ------------------------------------------------------------------------------- Main of New York, Inc., Nab Construction Corporation, L.K. Comstock & Co., Inc. - ------------------------------------------------------------------------------- and The Parsons Corporation, in the Supreme Court of the State of New York, - --------------------------- Kings County, Index No. 5966/97 asserting general monetary claims in excess of $13,000,000 under the Construction Turnkey Agreement. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations. EME experiences other routine litigation in the normal course of its business. None of such pending litigation is expected to have a material adverse effect on the consolidated financial position or results of operations of EME. See "Certain Regulatory Matters--Environmental Regulation". ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Inapplicable. 23 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of the outstanding Common Stock of EME is, as of the date hereof, owned by The Mission Group, which is a wholly owned subsidiary of Edison International. There is no market for the Common Stock. Dividends of the Common Stock will be paid when declared by the Board of Directors of EME. EME made cash dividend payments to The Mission Group of $197 million and $150 million in 1997 and 1996, respectively. In 1997, a noncash dividend of $78 million was also made to The Mission Group. At present, EME has no plans to pay a dividend on the Common Stock. In November 1994, Mission Capital, L.P. (Mission Capital), a limited partnership of which EME is the sole general partner, issued 3.5 million 9-7/8% Cumulative Monthly Income Preferred Securities, Series A (the Preferred Securities) and EME issued $90,206,186 of 9-7/8% junior subordinated deferrable interest debentures due 2024 (the Debentures) pursuant to a subordinated indenture dated as of November 30, 1994 (the Subordinated Indenture) between EME and The First National Bank of Chicago, as trustee. During August 1995, Mission Capital issued 2.5 million 8-1/2% Cumulative Monthly Income Preferred Securities, Series B (the Preferred Securities) and EME issued $64,432,990 of 8- 1/2% junior subordinated deferrable interest debentures due 2025 pursuant to the Subordinated Indenture. EME issued a guarantee (the Guarantee) in favor of the holders of the Preferred Securities, which guarantees the payments of distributions declared on the Preferred Securities, payments upon a liquidation of Mission Capital and payments on redemption with respect to any Preferred Securities called for redemption by Mission Capital. So long as any Preferred Securities remain outstanding, EME will not be able to declare or pay, directly or indirectly, any dividend on, or purchase, acquire or make a distribution or liquidation payment with respect to, any of its Common Stock if at such time (i) EME shall be in default with respect to its payment obligations under the Guarantee, (ii) there shall have occurred any event of default under the Subordinated Indenture, or (iii) EME shall have given notice of its selection of an extended interest payment period as provided in the Indenture and such period, or any extension thereof, shall be continuing. 24 ITEM 6. SELECTED FINANCIAL DATA
(IN MILLIONS) YEARS ENDED DECEMBER 31, ------------------------------------------------------------ 1997 1996 1995 1994 1993 ---- ---- ---- ---- ---- INCOME STATEMENT DATA Operating revenues $ 975.0 $ 843.6 $ 467.3 $ 380.6 $ 290.5 Operating expenses 581.1 476.5 264.0 199.9 258.7(a) -------- -------- -------- -------- ---------- Income from operations 393.9 367.1 203.3 180.7 31.8 Interest expense (223.5) (164.2) (93.1) (89.0) (33.5) Interest and other income 53.9 40.7 33.1 38.8 4.7 Minority interest (38.8) (69.5) (48.3) (46.1) (11.4) -------- -------- -------- -------- -------- Income (loss) before income taxes 185.5 174.1 95.0 84.4 (8.4) Provision (credit) for income taxes 57.4 82.0 31.0 29.4 (4.2) -------- -------- -------- -------- -------- Income (loss) before extraordinary loss and cumulative effect of change in accounting principle 128.1 92.1 64.0 55.0 (4.2) Extraordinary loss on early extinguishingment of debt, net of income tax benefit (13.1) -- -- -- -- Cumulative effect on prior periods of change in accounting for income taxes -- -- -- -- 6.5 -------- -------- -------- -------- -------- Net income $ 115.0 $ 92.1 $ 64.0 $ 55.0 $ 2.3 ======== ======== ======== ======== ======== DECEMBER 31, (IN MILLIONS) ------------------------------------------------------------ 1997 1996 1995 1994 1993 ---- ---- ---- ---- ---- BALANCE SHEET DATA Assets $4,985.1 $5,152.5 $4,374.0 $2,842.9 $2,286.1 Current liabilities 339.8 270.9 199.8 170.9 116.3 Long-term obligations 2,532.1 2,419.9 1,839.0 1,159.0 962.6 Shareholder's equity 826.6 1,019.9 1,028.5 622.2 551.3 (IN MILLIONS) YEARS ENDED DECEMBER 31, ------------------------------------------------------------ 1997 1996 1995 1994 1993 ---- ---- ---- ---- ---- PROPORTIONATE DATA (UNAUDITED)(C) Operating revenues $1,502.2 $1,261.8 $ 865.4 $ 733.0 $ 712.8 Operating expenses 1,107.1 912.4 650.3 552.5 667.5(a) -------- -------- -------- -------- -------- Income from operations 395.1 349.4 215.1 180.5 45.3 Interest expense (269.2) (212.8) (160.9) (138.5) (69.8) Interest and other income 69.2 44.2 42.1 45.7 16.1 -------- -------- -------- -------- -------- Income (loss) before income taxes 195.1 180.8 96.3 87.7 (8.4) Provision (credit) for income taxes 67.0 88.7 32.3 32.7 (4.2) -------- -------- -------- -------- -------- Income (loss) before extraordinary loss and cumulative effect of change in accounting principle 128.1 92.1 64.0 55.0 (4.2) Extraordinary loss on early extinguishment of debt, net of income tax benefit (13.1) -- -- -- -- Cumulative effect on prior periods of change in accounting for income taxes -- -- -- -- 6.5 -------- -------- -------- -------- -------- Net income $ 115.0 $ 92.1 $ 64.0 $ 55.0 $ 2.3 ======== ======== ======== ======== ======== Operating cash flow(b) $ 559.3 $ 493.7 $ 326.5 $ 264.9 $ 202.9 ======== ======== ======== ======== ========
25 (a) For the year ended December 31, 1993, operating expenses include special charges of $98.4 million. Special charges include (1) costs (unreimbursed development expenses and capitalized interest) associated with the termination of negotiations for the Carbon II project in Mexico of $28.0 million; (2) a reserve of $52.4 million, which reflects the reduced value of investments in five geothermal power plants due to lower gas price forecasts; and (3) a reserve of $18.0 million for project development and other costs. (b) Income from operations plus depreciation, amortization and other non-cash charges. (c) Reflects EME's pro rata ownership interest in its energy projects and oil and gas investments. Because significant 50% or less owned investments of EME are not consolidated, EME believes that the discussion set forth below of certain proportionate data facilitates an understanding and assessment of its results of operations. Except for certain industries, proportionate accounting is not in accordance with generally accepted accounting principles. Operating revenues increased in 1997 and 1996. The 1997 increase resulted primarily from increases in electric revenues attributable to the start of commercial operation of Loy Yang B Unit 2 in October 1996 and the Kwinana project in December 1996 and higher energy revenues from First Hydro as a result of increased utilization and higher pool prices, partially offset by lower capacity prices in 1997. There were no comparable electric revenues for Loy Yang B Unit 2 for the first nine months of 1996 or Kwinana for the first 11 months of 1996. The 1996 increase in electric revenues over 1995 was primarily due to the acquisition of First Hydro in December 1995, combined with its strong operating performance since acquisition, the start of commercial operation of Loy Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996, both of which were previously under construction, and the increase in ownership of Iberian Hy-Power from 34% to 100% in January 1996. The 1997 increase in fuel expense and plant operations was primarily due to commencement of commercial operations of the Kwinana project in the fourth quarter of 1996 and increased generation and higher prices at First Hydro. The 1997 increase in depreciation and amortization resulted from commencement of commercial operations of Loy Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996. The 1996 increase resulted from having no comparable expenses for First Hydro for the first 11 months of 1995 and no comparable expenses for Iberian Hy-Power, Loy Yang B Unit 2 and Kwinana for fiscal year 1995. Interest expense increased in 1997 and 1996, principally as a result of higher project debt levels. Interest and other income increased in 1997 and 1996. The 1997 increase resulted from interest earned on higher cash balances. The 1996 increase is primarily due to a pre-tax gain of $20 million on the sale of EME's interest in four operating geothermal projects. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This Annual Report on Form 10-K includes certain forward-looking statements, the realization of which may be affected by certain important factors discussed in Management's Discussion and Analysis of Results of Operations and Financial Condition thereunder and elsewhere herein. GENERAL - ------- Edison Mission Energy (EME) is one of the leading global producers of electricity. Through its subsidiaries, EME is engaged in the business of developing, acquiring, owning and operating electric power generation facilities worldwide. EME's current investments include 53 projects totaling 9,325 megawatts (MW) of generation capacity, of which 7,403 MW are in operation and 1,922 MW are under construction. EME's operating revenues are derived primarily from electric revenues and equity in income from energy projects. Electric revenues accounted for 76%, 77% and 64% of total operating revenues during 26 1997, 1996 and 1995, respectively. Operating revenues also include equity in income from oil and gas investments and revenue attributable to operation and maintenance services. Electric revenues are derived from consolidated results of operations of five international entities. Equity in income from energy projects primarily relates to EME's ownership interest of 50% or less in projects. The equity method of accounting is generally used to account for the operating results of entities over which a company has a significant influence but in which it does not have a controlling interest. With respect to entities accounted for under the equity method, EME recognizes its proportional share of the income or loss of such entities. ACQUISITIONS - ------------ In 1992, a subsidiary of EME (together with other wholly owned affiliates of EME) acquired 51% of the 1,000-MW Loy Yang B Power Station (Loy Yang B) from the State Government of Victoria (State). In May 1997, a subsidiary of EME acquired the State's 49% interest in Loy Yang B. In connection with the 1992 acquisition, the State Electricity Commission of Victoria (SECV) entered into a 30-year power purchase agreement with EME to purchase its share of the plant output. Loy Yang B's principal assets are two 500-MW units fired by brown coal located near Melbourne, Australia. Consideration for the State's 49% interest consisted of (1) a cash payment of approximately $64 million (84 million Australian dollars), (2) termination of the existing power purchase agreement and other related agreements and (3) entering into a new series of power sales-related contracts with the State resulting in a total transaction value of approximately $686 million (900 million Australian dollars). In December 1995, an indirect subsidiary of EME purchased all of the outstanding shares of First Hydro Company (First Hydro) for approximately $1 billion (653 million pounds sterling). First Hydro's principal assets are two pumped-storage electric power stations located in North Wales at Dinorwig and Ffestiniog, which have a combined capacity of 2,088 MW. This acquisition was funded through a combination of (i) a $621 million (400 million pounds sterling) credit facility with a bank and (ii) a $455 million (295.3 million pounds sterling) equity investment funded from a combination of a $350 million capital contribution from Edison International (EME's parent company) and from EME's working capital and credit lines. In January 1996, the 400 million pounds sterling credit facility was canceled upon repayment of all outstanding principal and accrued interest with proceeds from the issuance of 400 million pounds sterling of 9% Guaranteed Secured Bonds due on July 31, 2021. In January 1996, EME purchased the remaining 66% of Iberian Hy-Power Amsterdam B.V. (Iberian Hy-Power) for approximately $20 million, increasing its ownership to 100%. Iberian Hy-Power owns interests in 18 run-of-the-river hydroelectric facilities in Spain totaling 86 MW. Each of the acquisitions has been accounted for utilizing the purchase method. The purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair market values, with the excess being allocated to goodwill. The consolidated statement of income for 1995 includes operating results of First Hydro beginning in December 1995 and the consolidated statement of income for 1997 reflects the operations under the new contracts and the elimination of the minority interest of Loy Yang B beginning on May 9, 1997. 27 RESULTS OF OPERATIONS - --------------------- Operating Revenues Operating revenues increased significantly in 1997 and 1996. The 1997 increase resulted primarily from increases in electric revenues attributable to the start of commercial operation of Loy Yang B Unit 2 in October 1996 and the Kwinana project in December 1996 and higher energy revenues from First Hydro as a result of increased utilization and higher pool prices, partially offset by lower capacity prices in 1997. There were no comparable electric revenues for Loy Yang B Unit 2 for the first nine months of 1996 and Kwinana for the first 11 months of 1996. The 1996 increase in electric revenues over 1995 was primarily due to the acquisition of First Hydro in December 1995 combined with its strong operating performance since acquisition, the start of commercial operation of Loy Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996, both of which were previously under construction, and the increase in ownership of Iberian Hy-Power from 34% to 100% in January 1996. Electric revenues in the fourth quarter of 1997 were lower from fourth quarter revenues in 1996 attributable to the Loy Yang B project due to the restructuring of agreements associated with the 49% acquisition of Loy Yang B. This also resulted in partially offsetting the higher electric revenues from the Loy Yang B project in 1997. Equity in income from energy projects rose 17% in 1997 over 1996, compared with a 2% increase in 1996 over 1995. The 1997 increase is primarily attributable to higher electric and steam revenue for several cogeneration projects due to higher fuel gas prices upon which revenues are based. Equity in income from oil and gas investments increased substantially in 1997 and 1996, primarily due to higher gas prices in 1997 and higher oil and gas prices and increased gas production in 1996. A significant number of EME's domestic projects are located on the West Coast. These projects generally have power sales contracts that provide for higher payments during the summer months. Both First Hydro and Iberian Hy-Power provide for higher electric revenues during the winter months. In addition, First Hydro experienced higher energy sales in 1996 due to higher capacity prices resulting from narrowing of the margin between the demand and available generation forecast over the summer months and increased utilization. Unusual weather conditions and unanticipated facility maintenance may have an effect on future quarterly revenues. Operating Expenses Total operating expenses increased $104.6 million in 1997 and $212.4 million in 1996. The increases for both periods were principally due to higher fuel expense, plant operations, depreciation and amortization and administrative and general expenses. Fuel and plant operations expense increased $62.8 million in 1997 and $140.4 million in 1996, depreciation and amortization expense increased $12.9 million in 1997 and $44.3 million in 1996 and administrative and general expenses increased $27.6 million in 1997 and $26.6 million in 1996. The 1997 increase in fuel expense and plant operations was primarily due to commencement of commercial operations of the Kwinana project in the fourth quarter of 1996 and increased generation and higher prices at First Hydro. 28 The 1997 increase in depreciation and amortization resulted from commencement of commercial operations of Loy Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996. Loy Yang B's depreciation expense in 1997 was partially reduced due to an extension in the useful life of Loy Yang B's plant and equipment from approximately 30 years, the term of the previous power purchase agreement, to 50 years (the projected economic life of the plant). The 1996 increase resulted from having no comparable expenses for First Hydro for the first 11 months of 1995 and no comparable expenses for Iberian Hy-Power, Loy Yang B Unit 2 and Kwinana for fiscal year 1995. Both the 1997 and 1996 increase in administrative and general expenses is attributable to an increase of approximately $54 million and $16 million, respectively, in compensation expense as a result of charges related to EME's phantom stock plan which is a part of Edison International Officer's Long-Term Incentive Plan. The higher charges in 1997 were principally due to a substantial appreciation in the value of EME's "phantom stock" over its exercise price. The 1997 increase in compensation expense was partially offset by lower project development costs. Other Income (Expense) Interest and other income increased $6.5 million in 1997 over 1996, compared with a decrease of $9.3 million in 1996 from 1995. The 1997 increase resulted primarily from interest earned on higher cash balances. The 1996 decrease was primarily due to income recognized in August 1995 for reimbursement of certain 1994 development expenses not previously recognized in settlement of EME's remaining investment in Minera Carbonifera Rio Escondido. During the second quarter of 1997, EME completed a sale of its ownership interest in B.C. Star Partners (B.C. Star) for total cash proceeds of $71.2 million. EME recorded an after-tax gain of approximately $14 million on the sale in April 1997. Based upon management's forecast of operating profits that may have been realized from this operation, EME expects a minimal impact on its future results of operations. During the second quarter of 1996, CalEnergy Company, Inc., EME's partner in four operating geothermal projects in California, purchased all of the stock of four wholly owned subsidiaries of EME, which held interests in these projects. The purchase price of $70 million resulted in an after-tax gain of $15.5 million. There was no impact on EME's future revenues as EME discontinued recognizing earnings from these projects during 1993. Interest incurred rose slightly in 1997 over 1996, compared to a $71.3 million increase in 1996 over 1995. The 1996 increase was due primarily to a full year's inclusion of interest on the debt related to the First Hydro acquisition and debt related to Iberian Hy-Power. Capitalized interest decreased $51.9 million in 1997 from 1996, compared to an increase of $3.3 million in 1996 over 1995. The 1997 decrease is due to the completion of construction and resultant commercial operation of Loy Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996 at which time the Company discontinued recording capitalized interest related to these projects. Dividends on preferred securities increased $3 million in 1996 over 1995. The increase in 1996 was due to the inclusion of a full year of dividends on the Series B preferred securities issued during the third quarter of 1995. Minority interest expense decreased $30.7 million in 1997 from 1996, compared with an increase of $21.2 million in 1996 over 1995. The 1997 decrease resulted from the acquisition of the remaining 49% 29 ownership interest in Loy Yang B in May 1997. The acquisition also contributed to significantly lower minority interest expense in the fourth quarter of 1997 from 1996. The 1996 increase is due to Loy Yang B Unit 2 commencing commercial operation in October 1996. Provision for Income Taxes EME had an effective tax provision rate of 30.9%, 47.1% and 32.6% in 1997, 1996 and 1995, respectively. The decrease in the 1997 effective tax rate was primarily due to a reduction in corporate income taxes in the United Kingdom (U.K.). The U.K. government decreased the corporate tax rate from 33% to 31%, effective April 1, 1997. In accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," this reduction in the U.K. income tax rate resulted in an one-time reduction in income tax expense of approximately $20 million to adjust the U.K. deferred income tax liability (primarily related to First Hydro) to the new lower tax rate. The increase in the 1996 effective tax rate was primarily due to higher international earnings taxed at higher tax rates and certain expenditures not deductible in foreign jurisdictions. Extraordinary Loss The early repayment of Loy Yang B's existing debt facilities of $713 million in connection with the acquisition of the remaining 49% interest in May 1997 resulted in an extraordinary loss of $13.1 million (net of income tax benefit of $8.6 million) attributable to the write-off of unamortized debt issue costs. LIQUIDITY AND CAPITAL RESOURCES - ------------------------------- Cash provided by operating activities is derived primarily from distributions from energy projects and dividends from investments in oil and gas. For the year ended December 31, 1997, net cash provided by operating activities decreased $35 million over 1996, compared with an increase of $144.6 million in 1996 from 1995. The 1997 decline primarily reflects an increase in working capital requirements principally due to lower accounts receivable collections from First Hydro. The 1996 improvement primarily reflects higher net income, increased dividends from oil and gas investments and improved accounts receivable collections principally attributable to First Hydro. Dividends from investments in oil and gas increased $31.1 million in 1996 over 1995. The increase was principally due to increased dividends paid by Four Star Oil & Gas Company as a result of higher earnings in 1996 over 1995. Net cash provided by financing activities decreased $123.7 million during 1997 from 1996, compared with a substantial decrease during 1996 from 1995. The 1997 decrease was principally due to a reduction in financing activities and higher cash dividends paid to Edison International. In 1997, the Loy Yang B financing proceeds received in connection with the acquisition of the remaining 49% interest were primarily used to repay Loy Yang B's existing debt facilities. In 1996, EME issued 400 million pounds sterling of 9% Guaranteed Secured Bonds (U.S. $603.8 million), the proceeds of which were used to repay the 400 million pounds sterling credit facility entered into in December 1995. In addition, Edison Mission Energy Funding Corp., 99% owned by Broad Street Contract Services, Inc. and 1% owned by EME, completed a sale of $450 million of senior notes and bonds to institutional investors pursuant to the Rule 144A exemption under the U.S. Securities Act of 1933 for non-public sales in December 1996. The 1996 decrease was primarily attributable to (1) a reduction in net borrowings under 30 EME's $500 million revolving credit facility in 1996, (2) a dividend paid to Edison International of $150 million in 1996 compared with a $350 million capital contribution received from Edison International in 1995 (pursuant to the acquisition of First Hydro) and (3) proceeds of $62.5 million received in 1995 from the issuance of Series B Preferred Securities. The Loy Yang B financing in 1997 consists of (1) a $373 million (490 million Australian dollars) 15-year interest only term facility, (2) a $583 million (765 million Australian dollars) 20-year amortizing term facility with principal and interest payments scheduled quarterly commencing September 30, 1998 and (3) an $8 million (10 million Australian dollars) working capital facility with a term equal to that of the 20-year amortizing term facility. The financing was structured on a non-recourse basis. Lenders look solely to the operating cash proceeds of Loy Yang B to repay the debt and have taken a security interest in the Loy Yang B project assets. In December 1996, Edison Mission Energy Funding Corp., 99% owned by Broad Street Contract Services, Inc. and 1% owned by EME, completed a sale of $450 million of senior notes and bonds to institutional investors pursuant to the Rule 144A exemption under the U.S. Securities Act of 1933 for non-public sales. The senior notes and bonds are secured by the pledge of (i) notes issued by four EME subsidiaries that own interests in four California cogeneration projects, (ii) 99% of the capital stock of Edison Mission Energy Funding Corp. and (iii) a guarantee issued by the four EME subsidiaries. The financing structure was designed to pool and cross-collateralize available cash flow to the four EME subsidiaries from the four projects thus providing for repayment of the senior notes and bonds with available cash flow from the four projects. The obligations of the four EME subsidiaries are non-recourse to EME. The $450 million of securities issued by Edison Mission Energy Funding Corp. consist of $260 million of Series A Notes and $190 million of Series B Bonds which mature in September 2003 and September 2008, respectively. The Series A Notes and Series B Bonds bear an interest rate of 6.77% and 7.33%, respectively, and were rated BBB by Standard & Poor's Corporation and Baa1 by Moody's Investors Services, Inc. The principal and interest payments under the notes issued by the four EME subsidiaries are identical in terms to the Series A Notes and Series B Bonds. The net proceeds from the sale of securities were used by EME to repay borrowings under its $500 million revolving credit facility, retire EME's 200 million Australian dollar credit facility, defease other project debt and for other general corporate purposes. Net cash used in investing activities decreased $149.2 million in 1997 from 1996, and significantly decreased in 1996 from 1995. The 1997 decline is primarily due to an increase in proceeds received from loan repayments related to Brooklyn Navy Yard and the Carbon II project and fewer loans made to energy projects. The decrease in 1996 was principally due to the purchase of First Hydro for approximately $1 billion in December 1995. Proceeds of $70 million received from the sale of four of EME's operating geothermal facilities in 1996 also contributed to the decline in 1996 and is comparable to the proceeds of $71.2 million received from the sale of EME's ownership interest in B.C. Star in 1997. EME invested $87.7 million, $119.4 million and $192.8 million in 1997, 1996 and 1995, respectively, in new plant and equipment principally related to the Doga project in 1997 and the Loy Yang B Unit 2 and Kwinana projects in 1996 and 1995. At December 31, 1997, EME had cash and cash equivalents of $585.9 million and had available $388.6 million of borrowing capacity under a $500 million revolving credit facility that expires in 2001. The credit facility provides credit available in the form of cash advances or letters of credit, and bears interest on advances under the London Interbank Offered Rate plus the applicable margin as determined 31 by EME's long-term debt ratings (0.175% margin at December 31, 1997), the Base Rate (substantially similar to what is commonly known as the "prime" rate, which was 8.5% at December 31, 1997), or on a competitive auction basis. This borrowing capacity under the revolving credit facility may be reduced by borrowings for firm commitments to contribute project equity and to fund capital expenditures and construction costs of its project facilities. FIRM COMMITMENTS TO CONTRIBUTE PROJECT EQUITY
PROJECTS LOCAL CURRENCY U.S. (DOLLARS IN MILLIONS) - -------- -------------- -------------------------- Paiton (i) 136 ISAB (ii) 244 billion Italian Lira 138 Doga (iii) 21
(i) Paiton is a 1,230-MW coal-fired power plant under construction in East Java, Indonesia. A wholly owned subsidiary of EME owns a 40% interest. Equity contributions are currently being made and will continue until commercial operation, which is currently scheduled for the first half of 1999. (ii) ISAB is a 512-MW integrated gasification combined cycle power plant under construction near Siracusa in Sicily, Italy. A wholly owned subsidiary of EME owns a 49% interest. Equity will be contributed at commercial operation, which is currently scheduled for late 1999. (iii) Doga is a 180-MW gas-fired power plant under construction near Istanbul, Turkey. A wholly owned subsidiary of EME owns an 80% interest. Equity contributions are currently being made and will continue until commercial operation, which is currently scheduled for 1999. Firm commitments to contribute project equity could be accelerated due to certain events of default as defined in the non-recourse project financing facilities. Management has no reason to believe that these events of default will occur requiring acceleration of the firm commitments. CONTINGENT OBLIGATIONS TO CONTRIBUTE PROJECT EQUITY
PROJECTS U.S. (DOLLARS IN MILLIONS) - -------- -------------------------- Paiton (i) 141 Doga (i) 19 All Other 21
(i) Contingent obligations to contribute additional project equity to the project would be based on events principally related to capital cost overruns during the plant construction. Management has no reason to believe that these contingent obligations or any other contingent obligations to contribute project equity will be required. OTHER COMMITMENTS AND CONTINGENCIES Certain of EME's subsidiaries entered into indemnification agreements whereby the subsidiaries agreed to repay capacity payments to the projects' power purchasers, in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contract. Obligations under these indemnification agreements as of December 31, 1997, if 32 payment were required, would be $260 million. Management has no reason to believe that the projects will either terminate their performance or reduce their electric power producing capability during the term of the power contracts. Brooklyn Navy Yard is a 286-MW gas-fired cogeneration power plant in Brooklyn, New York. A wholly owned subsidiary of EME owns 50% of the project. On December 17, 1997, the Brooklyn Navy Yard project partnership completed a $407 million permanent, non-recourse financing for the project. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. (BNY) for damages in the amount of $136.8 million. BNY has asserted general monetary claims against the contractor. In connection with the 1997 refinancing, EME agreed to indemnify the partnership and its partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to the lenders. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations. EME's projected construction expenditures that will be funded utilizing non- recourse project financing are $80 million at December 31, 1997. EME and its subsidiaries may incur additional obligations to make equity and other contributions to projects in the future. EME believes that it will have sufficient liquidity on both a short and long-term basis to fund pre-financing project development costs, make equity contributions to partnerships, pay corporate debt obligations and pay other administrative and general expenses as they are incurred from (1) distributions from energy projects and dividends from investments in oil and gas, (2) proceeds from the repayment of loans to energy projects and (3) funds available from EME's revolving credit facility. CHANGES IN INTEREST RATES, CHANGES IN ELECTRICITY POOL PRICING, FOREIGN CURRENCY FLUCTUATIONS AND OTHER CONTRACTUAL OBLIGATIONS Changes in interest rates, changes in electricity pool pricing and fluctuations in foreign currency exchange rates can have a significant impact on EME's results of operations. Interest rate changes affect the cost of capital needed to construct and finance projects. EME has mitigated the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps or other hedging mechanisms for the majority of its project financing. Interest expense included $20.5 million, $6.2 million and $6.5 million for the years 1997, 1996 and 1995, respectively, as a result of interest rate hedging mechanisms. EME has entered into several interest rate swap agreements whereby the maturity date of the swaps occurs prior to the final maturity of the underlying debt. EME does not believe that interest rate fluctuations will have a materially adverse effect on its financial position or results of operations. Projects in the U.K. sell their electrical energy and capacity through a centralized electricity pool, which establishes a half-hourly clearing price (also referred to as the "pool price") for electrical energy. The pool price is extremely volatile and can vary by as much as a factor of ten or more over the course of a few hours, due to the large differentials in demand according to the time of day. First Hydro mitigates a significant portion of the market risk of the pool by entering into contracts for differences (electricity rate swap agreements), related to either the selling or purchasing price of power, whereby a contract specifies a price at which the electricity will be traded, and the parties to the agreement make payments, calculated based on the difference between the price in the contract and the pool price for the element of power under contract. These contracts can be sold in two structures: one-way contracts, where a specified monthly amount is received in advance and difference payments are made when the pool price is above the price specified in the contract, and two-way contracts, where the counterparty pays First 33 Hydro when the pool price is below that in the contract instead of a specified monthly amount. These contracts act as a means of stabilizing production revenues or purchasing costs by removing an element of First Hydro's net exposure to pool price volatility. First Hydro's electric revenues were increased by $36.9 million and decreased by $4.5 million for the years ended December 31, 1997 and 1996, respectively, and decreased by $29 million in December 1995, as a result of electricity rate swap agreements. Loy Yang B sells its electrical energy through a centralized electricity pool (the National Electricity Market) which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The Victorian Power Exchange, operator and administrator of the pool, determines a system marginal price each half hour. To mitigate exposure to price volatility of the electricity traded into the pool, Loy Yang B has entered into a number of financial hedges. From May 8, 1997 to December 31, 2000, approximately 53% to 64% of the plant output sold is hedged under "Vesting Contracts" with the remainder of the plant capacity hedged under the "State Hedge" described below. Vesting Contracts were put into place by the State, between each generator and each distributor, prior to the privatization of electric power distributors in order to provide more predictable pricing for those electricity customers that were unable to choose their electricity retailer. Vesting Contracts set base strike prices at which the electricity will be traded, and the parties to the agreement make payments, calculated based on the difference between the price in the contract and the half-hourly pool clearing price for the element of power under contract. These contracts can be sold as one-way or two-way contracts which are structured similar to the electricity rate swap agreements described above. These contracts are accounted for as electricity rate swap agreements. The State Hedge is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State guarantees SECV's obligations under the State Hedge. Loy Yang B's electric revenues were increased by $58.6 million for the year ended December 31, 1997 as a result of hedging contract arrangements. The State Hedge and Vesting Contracts were entered into in connection with the 49% acquisition of Loy Yang B in May 1997, and therefore electric revenues were not impacted prior to 1997. Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of EME's equity contributions to, and distributions from, its foreign projects. As EME continues to expand into foreign markets, fluctuations in foreign currency exchange rates can be expected to have a greater impact on EME's results of operations in the future. At times, EME has hedged a portion of its current exposure to fluctuations in foreign exchange rates where it deems appropriate through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to U.S. dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, EME has used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. There can be no assurance, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macro economic variables will behave in a manner that is consistent with historical or forecasted relationships. Foreign exchange considerations for three major international projects are discussed below. The First Hydro project in the U.K. and the Loy Yang B project in Australia have been financed in their local currency (pound sterling and Australian dollar, respectively) thereby hedging the majority of their acquisition costs against foreign exchange fluctuations. Furthermore, EME has evaluated the return on the remaining equity portion of the investments with regard to the likelihood of various foreign exchange scenarios. These analyses use market derived volatilities, statistical correlations between certain variables, and long-term forecasts to predict ranges of expected returns. Based upon these 34 analyses, management believes that the investment returns for First Hydro and Loy Yang B are adequately insulated from a broad range of foreign exchange scenarios at this time. In 1996, EME repaid a 200 million Australian dollar loan that was originally structured to hedge a portion of the foreign exchange risk associated with EME's equity investment in the Loy Yang B project in Australia. The decision to repay the loan was based on management's view that the cost of the hedge was high relative to the current and expected volatility of the Australian dollar. Construction on the two-unit Paiton project is approximately 85% completed, and commercial operation is expected in the first half of 1999. The tariff is higher in the early years and steps down over time, and the tariff for the Paiton project includes infrastructure to be used in common by other units at the Paiton complex. The plant's output is fully contracted with the state-owned electricity company, PT Perusahaan Listrik Negara (PLN), for payment in U.S. dollars. The projected rate of growth of the Indonesian economy and the exchange rate of Indonesian Rupiah into U.S. dollars have deteriorated significantly since the Paiton project was contracted, approved and financed with substantial finance and insurance support from the Export-Import Bank of the United States, The Export-Import Bank of Japan, the U.S. Overseas Private Investment Corporation and the Ministry of International Trade and Industry of Japan. The Paiton project's senior debt ratings have been reduced from investment grade to speculative grade based on the rating agencies' perceived increased risk that PLN might not be able to honor the electricity sales contract with Paiton. A Presidential decree has deemed some power plants, but not including the Paiton project, subject to review, postponement or cancellation. EME will continue to monitor its foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the future. The electric power generated by EME's domestic operating projects is generally sold to a limited number of electric utilities pursuant to long-term (typically, 15 to 30 year) power sales contracts and is expected to result in consistent cash flow under a wide range of economic and operating circumstances. To accomplish this, EME structures its long-term contracts so that fluctuations in fuel costs will produce similar fluctuations in electric and/or steam revenues and by entering into long-term fuel supply and transportation agreements. ENVIRONMENTAL MATTERS OR REGULATIONS EME is subject to environmental regulation by federal, state and local authorities in the U.S. and foreign regulatory authorities with jurisdiction over projects located outside the U.S. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operations. EME completed a review of some of its sites in 1995 and does not believe that a material liability exists as of December 31, 1997. The implementation of Clean Air Act Amendments is expected to result in increased operating expenses; however, these increased operating expenses are not expected to have a material impact on EME's financial position or results of operations. YEAR 2000 ISSUE During 1997, EME completed the financial and informational computer system review with no material costs incurred associated with resolving the issue. The operational review will continue at all EME's power projects. 35 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Financial Statements: Report of Independent Public Accountants. Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995. Consolidated Balance Sheets at December 31, 1997 and 1996. Consolidated Statements of Shareholder's Equity for the years ended December 31, 1997, 1996 and 1995. Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995. Notes to Consolidated Financial Statements. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 36 EDISON MISSION ENERGY AND SUBSIDIARIES REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Edison Mission Energy: We have audited the accompanying consolidated balance sheets of Edison Mission Energy (a California corporation) and subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income, shareholder's equity and cash flows for each of the three years in the period ended December 31, 1997. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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 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 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 Edison Mission Energy and subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. Arthur Andersen LLP Orange County, California March 16, 1998 37 EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS)
Years Ended December 31, ---------------------------------------- 1997 1996 1995 ---------- ---------- ---------- OPERATING REVENUES: Electric revenues $ 744,675 $ 650,838 $ 297,200 Equity in income from energy projects 151,306 128,823 125,880 Equity in income from oil and gas 38,079 25,090 9,939 Operation and maintenance services 40,931 38,867 34,327 --------- --------- --------- Total operating revenues 974,991 843,618 467,346 --------- --------- --------- OPERATING EXPENSES: Fuel 192,325 137,151 79,162 Plant operations 132,079 124,451 42,078 Operation and maintenance services 29,314 28,065 26,845 Depreciation and amortization 102,794 89,853 45,589 Administrative and general 124,576 96,954 70,354 --------- --------- --------- Total operating expenses 581,088 476,474 264,028 --------- --------- --------- Income from operations 393,903 367,144 203,318 --------- --------- --------- OTHER INCOME (EXPENSE): Interest and other income 27,306 20,766 30,034 Gain on sale of assets 26,642 19,986 3,144 Interest expense (210,311) (151,139) (83,050) Dividends on preferred securities (13,167) (13,100) (10,095) Minority interest (38,858) (69,547) (48,343) --------- --------- --------- Total other income (expense) (208,388) (193,034) (108,310) --------- --------- --------- Income before income taxes 185,515 174,110 95,008 Provision for income taxes 57,363 82,045 31,000 --------- --------- --------- INCOME BEFORE EXTRAORDINARY LOSS $ 128,152 $ 92,065 $ 64,008 --------- --------- --------- Extraordinary loss on early extinguishment of debt, net of income tax benefit (13,126) -- -- --------- --------- --------- NET INCOME $ 115,026 $ 92,065 $ 64,008 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 38 EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
December 31, -------------------------- 1997 1996 ---------- ----------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 585,883 $ 383,634 Accounts receivable - trade 76,935 71,046 Accounts receivable - affiliates 18,139 10,798 Prepaid expenses and other 13,630 13,747 ---------- ---------- Total current assets 694,587 479,225 ---------- ---------- INVESTMENTS Energy projects 852,688 794,646 Oil and gas 67,101 121,237 ---------- ---------- Total investments 919,789 915,883 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT 3,142,551 3,401,006 Less accumulated depreciation and amortization 201,564 152,458 ---------- ---------- Net property, plant and equipment 2,940,987 3,248,548 ---------- ---------- OTHER ASSETS Long-term receivables 25,957 91,567 Goodwill 312,606 334,481 Deferred financing costs and other 91,219 82,768 ---------- ---------- Total other assets 429,782 508,816 ---------- ---------- TOTAL ASSETS $4,985,145 $5,152,472 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 39 EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
December 31, ------------------------- 1997 1996 ------------ ---------- LIABILITIES AND SHAREHOLDER'S EQUITY CURRENT LIABILITIES Accounts payable - affiliates $ 13,381 $ 35,996 Accounts payable and accrued 208,411 118,824 liabilities Interest payable 42,627 35,076 Current maturities of long-term 75,383 80,994 obligations ---------- ---------- Total current liabilities 339,802 270,890 ---------- ---------- LONG-TERM OBLIGATIONS NET OF CURRENT 2,532,121 2,419,890 MATURITIES ---------- ---------- LONG-TERM DEFERRED LIABILITIES Deferred taxes and tax credits 517,391 545,449 Deferred revenue 541,176 -- Other 68,951 39,049 ---------- ---------- Total long-term deferred 1,127,518 584,498 liabilities ---------- ---------- Total liabilities 3,999,441 3,275,278 ---------- ---------- MINORITY INTERESTS 9,102 707,289 ---------- ---------- COMPANY-OBLIGATED MANDATORILY REDEEMABLE SECURITY OF PARTNERSHIP HOLDING SOLELY PARENT DEBENTURES 150,000 150,000 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 6, 11 and 12) SHAREHOLDER'S EQUITY Common stock, no par value; 10,000 shares authorized; 100 shares issued and outstanding 64,130 64,130 Additional paid-in capital 629,406 629,289 Retained earnings 102,620 262,594 Cumulative translation adjustments 30,446 63,892 ---------- ---------- Total shareholder's equity 826,602 1,019,905 ---------- ---------- TOTAL LIABILITIES AND SHAREHOLDER'S $4,985,145 $5,152,472 EQUITY ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 40 EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY (IN THOUSANDS)
Additional Cumulative Common Paid-in Retained Translation Shareholder's Stock Capital Earnings Adjustments Equity -------- ----------- ---------- ------------ -------------- BALANCE AT DECEMBER 31, 1994 $64,130 $285,789 $ 256,521 $ 15,807 $ 622,247 Net income -- -- 64,008 -- 64,008 Cash contributions -- 350,000 -- -- 350,000 Issuances of stock by a subsidiary -- (6,500) -- -- (6,500) Translation adjustments -- -- -- (1,218) (1,218) ------- -------- --------- -------- ---------- BALANCE AT DECEMBER 31, 1995 64,130 629,289 320,529 14,589 1,028,537 Net income -- -- 92,065 -- 92,065 Cash dividends -- -- (150,000) -- (150,000) Translation adjustments -- -- -- 49,303 49,303 ------- -------- --------- -------- ---------- BALANCE AT DECEMBER 31, 1996 64,130 629,289 262,594 63,892 1,019,905 Net income -- -- 115,026 -- 115,026 Cash dividends -- -- (197,000) -- (197,000) Non-cash dividend -- -- (78,000) -- (78,000) Non-cash contribution -- 117 -- -- 117 Translation adjustments -- -- -- (33,446) (33,446) ------- -------- --------- -------- ---------- BALANCE AT DECEMBER 31, 1997 $64,130 $629,406 $ 102,620 $ 30,446 $ 826,602 ======= ======== ========= ======== ==========
The accompanying notes are an integral part of these consolidated financial statements. 41 EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
Years Ended December 31, -------------------------------------- 1997 1996 1995 ----------- ---------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 115,026 $ 92,065 $ 64,008 Adjustments to reconcile net income to net cash provided by operating activities: Equity in income from energy projects (151,306) (128,823) (125,880) Equity in income from oil and gas (38,079) (25,090) (9,939) Distributions from energy projects 133,643 125,717 158,226 Dividends from oil and gas 47,849 50,576 19,500 Depreciation and amortization 102,794 89,853 45,589 Deferred taxes and tax credits (7,994) 3,378 (4,559) Gain on sale of assets (26,642) (19,986) (3,144) Extraordinary loss on early extinguishment of debt, net of tax 13,126 -- -- Decrease (increase) in accounts receivable (20,259) 31,356 (9,662) Decrease in prepaid expenses and other 1,752 4,193 190 Increase in interest payable 7,857 18,635 3,293 Increase (decrease) in accounts 66,031 10,869 (10,692) payable and accrued liabilities Other, net 15,679 41,723 22,920 ---------- --------- ----------- Net cash provided by operating activities 259,477 294,466 149,850 ---------- --------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Borrowing on long-term obligations 1,140,588 188,482 770,320 Payments on long-term obligations (882,446) (871,734) (67,643) Issuance of Guaranteed Secured Bonds -- 603,840 -- Issuance of debt securities -- 414,275 -- Issuance of preferred securities -- -- 62,500 Cash dividends to parent (197,000) (150,000) -- Capital contribution from parent -- -- 350,000 ---------- --------- ----------- Net cash provided by financing 61,142 184,863 1,115,177 activities ---------- --------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Investments in energy projects (62,034) (78,575) (98,403) Loans to energy projects (63,406) (106,443) (243,894) Payments of common stock of acquired companies (63,983) (34,640) (1,042,591) Capital expenditures (87,706) (119,407) (192,808) Proceeds from loan repayments 160,797 32,067 375,330 Proceeds from sale of assets 71,166 70,000 12,457 Other, net (51,965) (9,321) (1,358) ---------- --------- ----------- Net cash used in investing (97,131) (246,319) (1,191,267) activities ---------- --------- ----------- Effect of exchange rate changes on cash (21,239) 13,084 (365) ---------- --------- ----------- Net increase in cash and cash equivalents 202,249 246,094 73,395 Cash and cash equivalents at beginning of period 383,634 137,540 64,145 ---------- --------- ----------- Cash and cash equivalents at end of period $ 585,883 $ 383,634 $ 137,540 ========== ========= ===========
The accompanying notes are an integral part of these consolidated financial statements. 42 EDISON MISSION ENERGY AND SUBSIDIARIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS) NOTE 1. ORGANIZATION - --------------------- Edison Mission Energy (EME) is a wholly owned subsidiary of The Mission Group (TMG), a wholly owned, non-utility subsidiary of Edison International, the parent holding company of Southern California Edison Company (Edison). Through its subsidiaries, EME is engaged in the business of developing, acquiring, owning and operating electric power generation facilities worldwide. NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - --------------------------------------------------- Consolidations The consolidated financial statements include EME and its majority owned subsidiaries, partnerships and a special purpose corporation. All significant intercompany transactions have been eliminated. Certain prior year reclassifications have been made to conform to the current year financial statement presentation. Management's Use of Estimates 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 reported period. Actual results could differ from those estimates. Investments Cash equivalents include time deposits and other investments totaling $218.9 million at December 31, 1997, with maturities of three months or less. All investments are classified as available-for-sale. Investments in energy projects and oil and gas that are 50% or less owned are accounted for by the equity method. The majority of energy projects and all investments in oil and gas are accounted for under the equity method at December 31, 1997. Property, Plant and Equipment Property, plant and equipment, including leasehold improvements and construction in progress, are capitalized at cost and are principally comprised of five energy entities' plants and related facilities. Depreciation and amortization are computed by using the straight-line method over the useful life of the property, plant and equipment and over the lease term for leasehold improvements. Useful lives for property, plant and equipment are as follows: 43 Furniture and office equipment 3 - 10 years Building, plant and equipment 25 - 50 years Civil works 50 - 80 years Capitalized leased equipment 10 - 30 years Leasehold improvements Life of lease Goodwill Goodwill represents the cost incurred in connection with the purchase of First Hydro Company (First Hydro) in excess of the fair value of the net assets acquired in December 1995. This amount is being amortized over 40 years on a straight-line basis. Accumulated amortization was $17.2 million and $9.3 million at December 31, 1997 and 1996, respectively. Impairment of Investments and Long-Lived Assets EME periodically evaluates the potential impairment of its investments in projects and other long-lived assets (including goodwill) based on a review of estimated future cash flows expected to be generated. If the carrying amount of the investment or asset exceeds the amount of the expected future cash flows, an impairment loss is recognized accordingly. Effective January 1, 1996, EME adopted 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 statement requires, among other things, that an impairment loss shall only be recognized when the carrying amount of a long-lived asset exceeds the expected future cash flows (undiscounted and without interest charges) and that, when appropriate, the amount of loss to be recognized shall be measured as the amount by which the carrying value exceeds the fair value of the asset. The adoption of this statement did not have a material adverse effect on the consolidated financial position or results of operations of EME. Capitalized Interest Interest incurred on funds borrowed by EME to finance project construction is capitalized. Capitalization of interest is discontinued when the projects are completed and deemed operational. Such capitalized interest is included in investment in energy projects and property, plant and equipment. Capitalized interest is amortized over the depreciation period of the major plant and facilities for the respective project.
Years Ended December 31, ------------------------ 1997 1996 1995 ------ ------ ------ Interest incurred $222.8 $215.5 $144.2 Interest capitalized (12.5) (64.4) (61.1) ------ ------ ------ $210.3 $151.1 $ 83.1 ====== ====== ======
Income Taxes EME is included in the consolidated federal income tax and combined state franchise tax returns of Edison International. EME calculates its income tax provision on a separate company basis under a tax sharing arrangement with TMG, which in turn has an agreement with Edison International. Tax benefits 44 generated by EME and used in the Edison International consolidated tax return are recognized by EME without regard to separate company limitations. EME accounts for income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted rates. Investment and energy tax credits are deferred and amortized over the term of the power-purchase agreement of the respective project. Income tax accounting policies are discussed further in Note 8. Project Development Costs EME capitalizes only the direct costs incurred in developing new projects. These costs consist of professional fees, salaries, permits, bids and other directly related development costs incurred by EME before a partnership or joint venture is formed to develop the project. The capitalized costs are amortized over the life of operational projects or charged to expense if management determines the costs to be unrecoverable. Deferred Financing Costs Bank, legal and other direct costs incurred in connection with obtaining financing are deferred and amortized as interest expense on a basis which approximates the effective interest rate method over the term of the related debt. Accumulated amortization amounted to $1.7 million in 1997 and $6.9 million in 1996. Deferred Revenue Certain revenues on power sales contracts are deferred and amortized to income utilizing the unit-of-production method over the term of the contracts. Financial Instruments EME enters into interest rate swap, cap and collar agreements to manage its interest rate exposure. The related net interest rate differentials to be paid or received are recorded as adjustments to interest expense. In addition, EME enters into electricity rate swap agreements to manage its exposure to the U.K. and Australia market (pool) price volatilities. The related price differentials to be paid or received are currently recorded as adjustments to electric revenues or fuel expenses. Translation of Foreign Financial Statements Assets and liabilities of most foreign operations are translated at end of period rates of exchange and the income statements are translated at the average rates of exchange for the year. Gains or losses resulting from foreign currency transactions are normally included in other income in the consolidated statements of income. Foreign currency transaction gains and (losses) amounted to $(2.9) million, $0.6 million and $(0.4) million, for 1997, 1996 and 1995, respectively. Gains or losses from translation of foreign currency financial statements are included in shareholder's equity. 45 Stock-based Compensation EME measures compensation expense relative to stock-based compensation by the intrinsic-value method. NOTE 3. ACQUISITIONS - --------------------- In 1992, a subsidiary of EME (together with other wholly owned affiliates of EME) acquired 51% of the 1,000-MW Loy Yang B Power Station (Loy Yang B) from the State Government of Victoria (State). In May 1997, a subsidiary of EME acquired the State's 49% interest in Loy Yang B. In connection with the 1992 acquisition, the State Electricity Commission of Victoria (SECV) entered into a 30-year power purchase agreement with EME to purchase its share of the plant output. Loy Yang B's principal assets are two 500-MW units fired by brown coal located near Melbourne, Australia. Consideration for the State's 49% interest consisted of (1) a cash payment of approximately $64 million (84 million Australian dollars), (2) termination of the existing power purchase agreement and other related agreements and (3) entering into a new series of power sales-related contracts with the State resulting in a total transaction value of approximately $686 million (900 million Australian dollars). In December 1995, an indirect subsidiary of EME purchased all of the outstanding shares of First Hydro for approximately $1 billion (653 million pounds sterling). First Hydro's principal assets are two pumped-storage electric power stations located in North Wales at Dinorwig and Ffestiniog, which have a combined capacity of 2,088 MW. This acquisition was funded through a combination of (i) a $621 million (400 million pounds sterling) credit facility with a bank (see Note 6) and (ii) a $455 million (295.3 million pounds sterling) equity investment funded from a combination of a $350 million capital contribution from Edison International and from EME's working capital and credit lines. Each of the acquisitions has been accounted for utilizing the purchase method. The purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair market values with the excess being allocated to goodwill. The excess of the purchase price over the carrying value of the net assets acquired relating to the Loy Yang B acquisition was allocated to property, plant and equipment. The consolidated statement of income for 1995 includes operating results of First Hydro beginning in December 1995 and the consolidated statement of income for 1997 reflects the operations under the new contracts and the elimination of the minority interest of Loy Yang B beginning on May 9, 1997. The following unaudited pro forma data summarizes the consolidated results of operations for the periods indicated as if the acquisition of First Hydro had occurred at the beginning of 1995 and the acquisition of the 49% interest in Loy Yang B had occurred at the beginning of 1996 and 1997. The pro forma data gives effect to certain adjustments including electric revenues, fuel expense, depreciation and amortization, interest expense and related income tax adjustments. These results have been prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisitions been made at the beginning of 1997, 1996 or 1995, or of the results which may occur in the future. 46
(Unaudited) Years Ended December 31, ------------------------ 1997 1996 1995 ---- ---- ---- Operating revenues $939.9 $731.2 $690.4 Income before extraordinary loss 143.9 88.4 80.8 Net income 130.8 88.4 80.8
The table below summarizes additional stock acquisitions by EME or its wholly owned subsidiaries during 1997, 1996 and 1995.
Percentage Purchase Date Acquired By Acquisition Acquired Price - ---- ----------- ----------- ---------- -------- Energy Projects January 31, 1996 MEC Indonesia B.V. P.T. Paiton Energy Company 7.5% $10.2 January 23, 1996 MEC International B.V. Iberian Hy-Power Amsterdam B.V. 66.0% 19.5 August 8, 1995 MEC Indo Coal B.V. P.T. Adaro Indonesia 10.0% 19.0 Oil and Gas August 1, 1996 Edison Mission Energy Oil Four Star Oil & Gas Company 4.4% 4.9 & Gas (EMEO&G) (Four Star) January 1, 1995 EMEO&G Four Star 6.0% 8.8
NOTE 4. INVESTMENTS - -------------------- Investments in Energy Projects Investments in energy projects, generally 50% or less owned partnerships and corporations, accounted for by the equity method are as follows:
December 31, ------------ 1997 1996 ---- ---- Domestic energy projects: Equity investment $411.5 $419.6 Notes receivable 145.3 202.6 ------ ------ Subtotal 556.8 622.2 International energy projects: Equity investment and advances 295.9 172.4 ------ ------ Total $852.7 $794.6 ====== ======
EME's subsidiaries have provided loans or advances related to certain projects. One loan totaled $96.2 million and bears interest at a 10% rate. Another loan amounting to $26.3 million, comprising promissory notes bearing interest at 5% payable semiannually, is due in April 2008. Loans to three other domestic projects amounted to $22.8 million at December 31, 1997, and bear interest at variable rates (8.5% to 12.5%). 47 The following table presents summarized financial information of the investments in energy projects accounted for by the equity method:
Years Ended December 31, ------------------------------- 1997 1996 1995 -------- -------- -------- Revenue $1,593.4 $1,383.3 $1,128.9 Expenses 1,294.7 1,083.1 862.4 -------- -------- -------- Net income $ 298.7 $ 300.2 $ 266.5 ======== ======== ======== December 31, ------------------- 1997 1996 -------- -------- Current assets $ 507.7 $ 480.0 Noncurrent assets 4,523.7 3,653.9 -------- -------- Total assets $5,031.4 $4,133.9 ======== ======== Current liabilities $ 750.9 $ 614.0 Noncurrent liabilities 2,986.2 2,341.7 Equity 1,294.3 1,178.2 -------- -------- Total liabilities and equity $5,031.4 $4,133.9 ======== ========
The majority of noncurrent liabilities are comprised of project financing arrangements that are non-recourse to EME. The following table presents, as of December 31, 1997, the energy projects accounted for by the equity method that represent at least five percent (5%) of EME's income before tax or in which EME has an investment balance greater than $50 million.
Energy Project Location Investment Operating Status - -------------- -------- ---------- ---------------- Paiton East Java, Indonesia $230.1 Coal-fired facility under construction Watson Carson, CA 121.4 Operating cogeneration facility Brooklyn Navy Yard Brooklyn, NY 98.5 Operating cogeneration facility Sycamore Bakersfield, CA 69.2 Operating cogeneration facility Kern River Bakersfield, CA 51.3 Operating cogeneration facility Midway-Sunset Fellows, CA 40.8 Operating cogeneration facility
Investments in Oil and Gas At December 31, 1997, EME had one 46.85% owned and one 50% owned investments in oil and gas. These investments are accounted for utilizing the equity method. The difference between the carrying value of one oil and gas investment and the underlying equity in the net assets amounted to $42.9 million at December 31, 1997. The difference is being amortized on a unit of production basis 48 over the life of the reserves. The following table presents summarized financial information of the investments in oil and gas:
Years Ended December 31, -------------------------------- 1997 1996 1995 ---- ---- ---- Operating revenues $304.7 $313.7 $230.5 Operating expenses 197.4 222.3 187.5 ------ ------ ------ Operating income 107.3 91.4 43.0 Provision for income taxes 18.5 17.2 2.9 ------ ------ ------ Net income (before non-operating items) 88.8 74.2 40.1 Non-operating expense, net (12.8) (12.0) (12.5) ------ ------ ------ Net income $ 76.0 $ 62.2 $ 27.6 ====== ====== ====== December 31, ------------ 1997 1996 ------ ------ Current assets $ 94.3 $109.1 Noncurrent assets 417.6 526.8 ------ ------ Total assets $511.9 $635.9 ====== ====== Current liabilities $ 49.5 $ 46.2 Noncurrent liabilities 309.4 336.2 Deferred income taxes and other liabilities 64.5 59.0 Equity 88.5 194.5 ------ ------ Total liabilities and equity $511.9 $635.9 ====== ======
The undistributed earnings of investments accounted for by the equity method were $150.1 million in 1997 and $138.9 million in 1996. Long-Term Receivables Long-term receivables include notes receivable from EME's former partner in the Carbon II power plant. In December 1997, EME's former partner made a prepayment of $65 million reducing notes receivable to $21.2 million at December 31, 1997. These notes are secured by a surety bond. Interest on these notes is payable quarterly at LIBOR plus 2% (7.8% at December 31, 1997), with the remaining principal due in November 1999. 49 NOTE 5. PROPERTY, PLANT AND EQUIPMENT - -------------------------------------- Property, plant and equipment consist of the following:
December 31, -------------------- 1997 1996 -------- -------- Buildings, plant and equipment $1,857.8 $2,198.9 Civil works 1,002.2 996.0 Construction in progress 83.8 0.6 Capitalized leased equipment 198.8 205.5 -------- -------- 3,142.6 3,401.0 Less accumulated depreciation and amortization 201.6 152.5 -------- -------- $2,941.0 $3,248.5 ======== ========
NOTE 6. FINANCIAL INSTRUMENTS - ------------------------------ Long-Term Obligations Long-term obligations include both corporate debt and non-recourse project debt, whereby lenders rely on specific project assets to repay such obligations. Long-term obligations consist of the following:
December 31, ------------------------- 1997 1996 ------------- --------- EME (parent only): Senior Notes, net: due 1999 (7.75%) $ 99.8 $ 99.7 due 2002 (8.125%) 99.3 99.1 Edison Mission Energy Funding Corp.: Series A Notes, net due 1997-2003 (6.77%) 231.5 258.4 Series B Bonds, net due 2004-2008 (7.33%) 188.7 188.7 First Hydro Finance Plc (First Hydro Finance): 400 million pounds sterling Guaranteed Secured Bonds due 2021 (9%) 657.1 684.9 Iberian Hy-Power project: Project credit facilities due 2003 (MIBOR + 1.5 to 2%) (7.836% to 8.336% at 12/31/96) -- 85.7
50 Term Loan due 2012 (MIBOR + 0.75%) (5.594% at 12/31/97) 78.1 -- Project Credit Facility due 2003 (9.408%) 26.5 -- Loy Yang B project: Latrobe Project Facilities Agreement due 2008 (BER + 1.75 to 1.95%) (7.737% to 7.937% at 12/31/96) -- 744.6 Energy Capital Partnership Credit Agreement due 2012-2017 (BBR + 0.3 to 1.0%) (5.398% to 6.098% at 12/31/97) 823.6 -- Roosecote project: Capital lease obligation (see Note 12) 68.2 90.3 Term Loan and Guarantee Facility due 2005 (sterling LIBOR + 0.6%) (8.288% at 12/31/97) 83.1 58.0 Kwinana project: Kwinana Bank Debt due 2012 (BER + 1.2%) (6.265% at 12/31/97) 67.2 104.2 Doga project: Doga Bank Debt due 2010 (LIBOR + 3.08%) (8.889% at 12/31/97) 59.3 -- Other long-term obligations 125.1 87.3 -------- -------- Subtotal 2,607.5 2,500.9 Current maturities of long-term (75.4) (81.0) obligations -------- -------- Total $2,532.1 $2,419.9 ======== ========
At December 31, 1997, EME had available $388.6 million of borrowing capacity and approximately $111.4 million in letters of credit issued under a $500 million revolving credit facility that expires in 2001. On December 20, 1996, Edison Mission Energy Funding Corp., 99% owned by Broad Street Contract Services, Inc. and 1% owned by EME, completed a sale of $450 million of senior notes and bonds to institutional investors pursuant to the Rule 144A exemption under the U.S. Securities Act of 1933 for non-public sales. The senior notes and bonds are secured by the pledge of (i) notes issued by four EME subsidiaries that own interests in four California cogeneration projects, (ii) 99% of the capital 51 stock of Edison Mission Energy Funding Corp. and (iii) a guarantee issued by the four EME subsidiaries. The financing structure was designed to pool and cross- collateralize available cash flow to the four EME subsidiaries from the four projects thus providing for repayment of the senior notes and bonds with available cash flow from the four projects. The obligations of the four EME subsidiaries are non-recourse to EME. The $450 million of securities issued by Edison Mission Energy Funding Corp. consist of $260 million of Series A Notes and $190 million of Series B Bonds which mature in September 2003 and September 2008, respectively. The Series A Notes and Series B Bonds bear an interest rate of 6.77% and 7.33%, respectively. The principal and interest payments under the notes issued by the four EME subsidiaries are identical in terms to the Series A Notes and Series B Bonds. The net proceeds from the sale of securities were used by EME to repay borrowings under its $500 million revolving credit facility, retire EME's 200 million Australian dollar credit facility, defease other project debt and for other general corporate purposes. In January 1996, First Hydro Finance issued 400 million pounds sterling of 9% Guaranteed Secured Bonds (Bonds) at par due on July 31, 2021. First Hydro Finance will commence funding a redemption reserve for principal repayment beginning in 2017 with interest payments due on a semi-annual basis beginning July 1996. The Bonds are secured by the two pumped-storage electric power stations located in North Wales. The net proceeds of $604 million (396 million pounds sterling) received, along with other funds held by First Hydro Finance, were used to repay the borrowings under the 400 million pounds sterling credit facility entered into by First Hydro Finance in December 1995 in connection with the First Hydro acquisition. EME has two letters of credit under its corporate credit facility in the amount of $29.6 million (18 million pounds sterling) to meet a requirement for six months of interest in a bond interest reserve account and $19.7 million (12 million pounds sterling) revenue support letter of credit due to expire in 1998. In May 1997, EME closed financing of $964 million (1.265 billion Australian dollars) in connection with the acquisition of the remaining 49% interest, the proceeds received were used to repay Loy Yang B's existing debt facilities of $713 million (935.5 million Australian dollars) with the balance used to finance the Loy Yang B 49% acquisition and to return funds to various affiliates of EME. The financing consists of (1) a $373 million (490 million Australian dollars) 15-year interest only term facility, (2) a $583 million (765 million Australian dollars) 20-year amortizing term facility with principal and interest payments scheduled quarterly commencing September 30, 1998 and (3) an $8 million (10 million Australian dollars) working capital facility with a term equal to that of the 20-year amortizing term facility. The financing was structured on a non- recourse basis. Lenders look solely to the operating cash proceeds of Loy Yang B to repay the debt and have taken a security interest in the Loy Yang B project assets. The early repayment of Loy Yang B's existing debt facilities of $713 million resulted in an extraordinary loss of $13.1 million (net of income tax benefit of $8.6 million) attributable to the write-off of unamortized debt issue costs. Annual maturities on long-term debt at December 31, 1997, for the next five years, excluding capital leases (see Note 12) are summarized as follows: 1998 - $54.9 million; 1999 - $183.2 million; 2000 - $82.2 million; 2001 - $81.3 million; 2002 - $189.7 million. Certain cash balances are restricted from being used primarily to pay or dividend to EME amounts required for debt payments, letter of credit expenses and permitted project costs. The total restricted cash was $59.5 million at December 31, 1997 and $17.8 million at December 31, 1996. 52 Debt service reserves classified in Other Assets (including reserves for interest on annual lease payments) were $44.7 million at December 31, 1997 and $13.2 million at December 31, 1996. Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Any asset of any such subsidiary may not be available to satisfy the obligations of EME or any of its other such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or affiliates thereof. Other Financial Instruments Projects in the U.K. and a project in Australia sell their electrical energy and capacity through a centralized electricity pool, which establishes a half- hourly clearing price (also referred to as the "pool price") for electrical energy. The pool price is extremely volatile and in the U.K. can vary by as much as a factor of 10 or more over the course of a few hours, due to the large differentials in demand according to the time of day. First Hydro mitigates a significant portion of the market risk of the pool by entering into contracts for differences (electricity rate swap agreements), related to either the selling or purchasing price of power, whereby a contract specifies a price at which the electricity will be traded, and the parties to the agreement make payments, calculated based on the difference between the price in the contract and the pool price for the element of power under contract. These contracts can be sold in two structures: one-way contracts, where a specified monthly amount is received in advance and difference payments are made when the pool price is above the price specified in the contract, and two-way contracts, where the counterparty pays First Hydro when the pool price is below that in the contract instead of a specified monthly amount. These contracts act as a means of stabilizing production revenues or purchasing costs by removing an element of First Hydro's net exposure to pool price volatility. The Roosecote project has avoided the pool price volatility by entering into a long-term power sales contract that provides for contract pricing. Loy Yang B has entered into a number of financial hedges to mitigate exposure to price volatility of the electricity traded into the pool. From May 8, 1997 to December 31, 2000, approximately 53% to 64% of the plant output sold is hedged under "Vesting Contracts" with the remainder of the plant capacity hedged under the "State Hedge" described below. Vesting Contracts were put into place by the State, between each generator and each distributor, prior to the privatization of electric power distributors in order to provide more predictable pricing for those electricity customers that were unable to choose their electricity retailer. Vesting Contracts set base strike prices at which the electricity will be traded, and the parties to the agreement make payments, calculated based on the difference between the price in the contract and the half-hourly pool clearing price for the element of power under contract. These contracts can be sold as one-way or two-way contracts which are structured similar to the electricity rate swap agreements described above. These contracts are accounted for as electricity rate swap agreements. The State Hedge is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State guarantees SECV's obligations under the State Hedge. EME's risk management policy allows for the use of these contracts and other derivative financial instruments to limit financial exposure on its investments and to manage exposure to fluctuations in interest rates, foreign exchange rates and energy prices but prohibits the use of these instruments for speculative investment purposes. EME does not hold or issue financial instruments for trading purposes. 53 EME had the following derivative financial instruments at December 31, 1997 and 1996, except where noted:
Category Contract Amount/Terms Purpose - -------- --------------------- ------- INTEREST RATE SWAPS EME (parent only): $200 million Convert fixed-rate expiring in 1999 debt of 7.75% and ($100 million) and 8.125% to a floating 2002 ($100 million) rate, such floating rate capped at 9.0% $45 million Convert fixed-rate expiring in 1999, debt of 9.875% to a corresponding floating rate preferred securities due 2024 Iberian Hy-Power project: 10.9 billion Change floating-rate Spanish pesetas debt to fixed rates (12/31/96) (U.S. ranging from 8.4% to $84 million) 11.38% expired in November 1997 Roosecote project: 45 million pounds Change floating-rate sterling (12/31/96) debt to a fixed rate (U.S. $77 million) of 12.4% expired in July 1997 Kwinana project: 40.8 million Change floating-rate Australian dollars debt to a fixed rate (12/31/97) (U.S. of 10.98% $27 million); 41.9 million Australian dollars (12/31/96) (U.S. $33 million); expiring in 2007 Loy Yang B project: 1.2 billion Change floating-rate Australian dollars debt to fixed rates (U.S. $781 million) ranging from 7.51% to expiring 2002-2007 7.93% INTEREST RATE COLLAR Iberian Hy-Power project: 11.7 billion Change interest rate Spanish pesetas exposure to float (U.S. $77 million) within range from 4.5% expiring in 1999 minimum to 7.5% maximum ELECTRICITY RATE SWAPS First Hydro project: Approximately 1,685 Change the variable MW related to market electricity winter months sales rates to fixed (October through rates March) and 759 MW related to summer months (April through September) of electrical generation under selling pricing contracts (12/31/97); 1,735 MW related to winter months and 1,185 MW related to summer months (12/31/96) expiring at various dates through 2000
54 Approximately 410 Change the variable MW related to market electricity winter months and rates to fixed rates 200 MW related to summer months of electricity under purchasing pricing contracts (12/31/97); 416 MW related to both winter and summer months (12/31/96) expiring at various dates through 1999 Loy Yang B project: Approximately 920 Change the variable MW of electrical market electricity generation under sales rates to fixed selling pricing rates contracts (12/31/97) expiring at various dates through 2016 Fair values of financial instruments were:
December 31, -------------------------------------------- 1997 1996 ------------------ -------------------- Carrying Fair Carrying Fair Instruments: Amount Value Amount Value ------ ----- ------ ----- Long-term receivables $ 26.0 $ 27.6 $ 91.6 $ 99.9 Electricity rate swap agreements -- 77.1 -- 26.8 Long-term obligations 2,532.1 2,715.6 2,419.9 2,434.4 Interest rate swap/collar agreements -- (68.1) -- (17.6)
The fair values for long-term receivables, interest rate swap agreements, the interest rate collar agreement and long-term obligations are based primarily on quoted market prices. The carrying amounts reported for cash equivalents approximate fair value due to their short maturities. The fair value of the electricity rate swap agreements entered into by First Hydro and Loy Yang B has been estimated by discounting the future cash flows on the difference between the average aggregate contract price per MW and a forecasted market price per MW, multiplied by the amount of MW sales remaining under contract. In addition, Iberian Hy-Power has entered into a forward-starting interest rate swap in order to fix the interest rate on a portion of the long-term debt outstanding. The swap period commences on December 15, 1999 and matures on December 15, 2007. The notional amount of the swap is based on an amortizing loan profile. The notional amount at December 15, 1999 is 10.8 billion Spanish pesetas (U.S. $71 million). As of December 31, 1997, the fair value of this swap was a negative one million dollars which has been reflected in the table above. 55 Credit Risk EME's financial instruments and power sales contracts involve elements of credit risk. Credit risk relates to the risk of loss that EME would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The counterparties to financial instruments and contracts consist of a number of major financial institutions and domestic and foreign utilities. EME attempts to mitigate this risk by entering into contracts with counterparties that have a strong capacity to meet their contractual obligations and by monitoring the credit quality of these financial institutions and utilities. In addition, EME enters into contracts whereby the structure of the contracts minimizes its credit exposure. Accordingly, EME does not anticipate any material impact to its financial position or results of operations as a result of counterparty nonperformance. The electric power generated by EME's domestic operating projects that are generally sold to a limited number of electric utilities pursuant to long-term (typically, 15 to 30 year) power sales contracts (see Note 13) are expected to result in consistent cash flows under a wide range of economic and operating circumstances. To accomplish this, EME structures its long-term contracts so that fluctuations in fuel costs will produce similar fluctuations in electric and/or steam revenues and by entering into long-term fuel supply and transportation agreements. In addition, EME has plants located in different geographic areas in order to mitigate the effects of regional markets, economic downturns or unusual weather conditions. NOTE 7. COMPANY-OBLIGATED MANDATORILY REDEEMABLE SECURITY OF PARTNERSHIP - ------------------------------------------------------------------------- HOLDING SOLELY PARENT DEBENTURES - -------------------------------- During November 1994, Mission Capital, L.P., a limited partnership in which EME is the sole general partner and a wholly owned subsidiary of EME is the limited partner, issued 3.5 million of 9-7/8% Cumulative Monthly Income Preferred Securities, Series A, at a price of $25 per security. These securities are redeemable at the option of Mission Capital, L.P., in whole or in part, beginning November 1999 with mandatory redemption in 2024 at a redemption price of $25 per security plus accrued and unpaid distributions. During August 1995, Mission Capital, L.P., issued 2.5 million of 8-1/2% Cumulative Monthly Income Preferred Securities, Series B, at a price of $25 per security. These securities are redeemable at the option of Mission Capital, L.P., in whole or in part, beginning August 2000 with mandatory redemption in 2025 at a redemption price of $25 per security plus accrued and unpaid distributions. NOTE 8. INCOME TAXES - --------------------- Current and Deferred Taxes Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. The components of the net accumulated deferred income tax liability were: 56
December 31, ----------------- 1997 1996 ------- ------ Deferred tax assets: Reserves and other items not currently deductible $ 92.0 $ 64.5 Loss carryforwards 8.9 129.9 Deferred income 191.6 -- Dividends in excess of equity earnings 22.4 22.6 Other 17.1 10.0 ------ ------ Total 332.0 227.0 ------ ------ Deferred tax liabilities: Basis differences 820.0 741.3 Tax credits, net 29.0 30.7 Other 0.4 0.4 ------ ------ Total 849.4 772.4 ------ ------ Deferred taxes and tax credits, net $517.4 $545.4 ====== ====== Loss carryforwards, primarily Australian, total $45 million at December 31, 1997, with no expiration date. The components of income before income taxes are as follows: Years Ended December 31, --------------------------- 1997 1996 1995 ------ ------ ------ U.S. $ 39.0 $ 40.6 $ 50.6 Foreign 146.5 133.5 44.4 ------ ------ ------ Total $185.5 $174.1 $ 95.0 ====== ====== ====== The provision for income taxes is comprised of the following: Years Ended December 31, -------------------------------- 1997 1996 1995 ------ ------ ------ Current Federal $ (2.4) $ 33.1 $ 23.9 State (10.2) 6.7 4.5 Foreign 78.3 38.8 7.2 ------ ------ ------ Total current 65.7 78.6 35.6 ------ ------ ------ Deferred Federal 14.3 (17.9) (13.0) State 9.0 0.4 (2.4) Foreign (31.6) 20.9 10.8 ------ ------ ------ Total deferred (8.3) 3.4 (4.6) ------ ------ ------ Provision for income taxes $ 57.4 $ 82.0 $ 31.0 ====== ====== ======
57 The components of the deferred tax provision (credit), which arise from tax credits and timing differences between financial and tax reporting, are presented below:
Years Ended December 31, --------------------------- 1997 1996 1995 -------- ------- ------- Basis differences $ 102.6 $ 55.3 $ 47.1 Loss carryforwards 121.0 (41.2) (23.4) Deferred income (197.9) -- -- State tax deduction (0.2) (2.9) 2.1 Reserves and other items not currently deductible (27.6) 8.7 (24.1) Elimination of book income (7.0) (10.0) (6.8) Dividends in excess of equity earnings 0.2 (9.2) (0.5) Other 0.6 2.7 1.0 ------- ------ ------ Total deferred provision (credit) $ (8.3) $ 3.4 $ (4.6) ======= ====== ======
Variations from the 35% federal statutory rate are as follows:
Years Ended December 31, --------------------------- 1997 1996 1995 -------- ------- ------- Expected provision for federal income taxes $ 64.9 $ 60.9 $ 33.2 Increase (decrease) in the provision for taxes resulting from: State tax - net of federal deduction (0.8) 4.4 1.4 Dividends received deduction (8.2) (7.9) (4.0) Amortization of tax credits (1.7) (8.6) (1.6) Production tax credits -- -- (1.0) Taxes on foreign operations at 2.0 17.3 2.5 different rates Book and tax basis differences 3.5 15.4 -- Other (2.3) 0.5 0.5 ------- ------ ------ Total provision for income taxes $ 57.4 $ 82.0 $ 31.0 ======= ====== ====== Effective tax rate 30.9% 47.1% 32.6% ======= ====== ======
NOTE 9. EMPLOYEE BENEFIT PLANS - ------- ---------------------- U.S. employees of EME are eligible for various benefit plans of Edison International. Certain EME Australian, U.K. and Spanish subsidiaries also participate in their own respective defined benefit pension plans. Pension Plans The noncontributory, defined benefit pension plans, administered by trustees, cover employees who fulfill minimum service requirements. Benefits are based on years of credited service and average base salary. Annual contributions meet the minimum legal funding requirements and do not exceed the maximum deductible for income taxes. Prior service costs from pension plan amendments are funded 58 over 30 and 15 years for the U.S. plan and Australian plan, respectively. There are no prior service costs included in the U.K. and Spanish plans. Plan assets are primarily U.S., U.K. and Australian common stock, corporate and government bonds and short-term investments. In 1996, EME recorded special termination benefits in connection with its special voluntary early retirement program. The special termination benefit was paid directly from the employer's assets and plan assets. Funded status of pension plans:
December 31, ------------------------------------------------------- 1997 1996 1997 1996 -------- ------- -------- -------- U.S. Plan Non U.S. Plans -------------------- ------------------------- Actuarial present value of benefit obligations: Vested benefits $10.3 $ 7.4 $26.8 $23.3 Nonvested benefits 3.5 1.7 1.1 0.8 ----- ----- ----- ----- Accumulated benefit obligation 13.8 9.1 27.9 24.1 Value of projected future compensation levels 6.7 5.6 2.2 2.0 ----- ----- ----- ----- Projected benefit obligation $20.5 $14.7 $30.1 $26.1 ===== ===== ===== ===== Fair value of plan assets $16.6 $ 4.9 $28.3 $24.1 ===== ===== ===== ===== Assets less than projected benefit obligations (3.9) (9.8) (1.8) (2.0) Unrecognized net loss (gain) (0.8) 5.4 0.7 (0.2) Unrecognized prior service cost 0.5 0.6 -- -- Unrecognized net obligation 1.4 1.5 -- -- ----- ----- ----- ----- Pension liability $(2.8) $(2.3) $(1.1) $(2.2) ===== ===== ===== ===== Discount rate 7.0% 7.75% 5.0% - 6.75% 6.5% - 8.0% Rate of increase in future compensation 5.0% 5.5% 3.5% - 4.75% 4.5% - 5.5% Expected long-term rate of return on plan assets 8.0% 8.0% 5.0% - 9.0% 8.5% - 9.0%
Components of pension expense were:
Years Ended December 31, ----------------------------------------------------------- 1997 1996 1995 1997 1996 1995 ------ ------ ------ ------ ------ ------ U.S. Plan Non U.S. Plans ------------------------ ------------------------- Service cost for benefits earned $ 1.8 $ 2.0 $ 2.3 $ 3.5 $ 3.5 $ 0.5 Interest cost on projected benefit obligation 1.1 1.5 1.1 1.9 1.7 0.1 Actual return on plan assets (1.1) (1.7) (0.8) (3.4) (1.5) (0.2) Net amortization and deferral 0.2 0.9 0.1 (0.6) (2.4) 0.1 ----- ----- ----- ----- ----- ----- Pension expense 2.0 2.7 2.7 1.4 1.3 0.5 Special termination benefits -- 0.9 -- -- -- -- ----- ----- ----- ----- ----- ----- Net pension expense $ 2.0 $ 3.6 $ 2.7 $ 1.4 $ 1.3 $ 0.5 ===== ===== ===== ===== ===== =====
59 In 1995, First Hydro employees were included as part of The National Grid Company plc (NGC) defined benefit pension plan (Electricity Supply Pension Scheme), administered by a trustee, which provides pension and other related benefits. Effective April 1, 1996, First Hydro employees were transferred into the First Hydro Group of the Electricity Supply Pension Scheme. An actuarial valuation for the U.K. plan, separate from NGC, was first completed for 1996 and, therefore, comparative amounts for 1995 were not included in the table above. Pension expense totaled $0.1 million for December 1995. Postretirement Benefits Other Than Pensions U.S. employees retiring at or after age 55 who have at least 10 years of service, are eligible for postretirement health care, dental, life insurance and other benefits. Health care benefits are subject to deductibles, copayment provisions and other limitations. The components of postretirement benefits other than pension expense were:
Years Ended December 31, ------------------------------ 1997 1996 1995 ----- ------ ------ Service costs for benefits earned $ 1.2 $ 1.2 $ 1.2 Interest cost on benefit obligation 0.7 0.7 0.6 Amortization of transition obligation 0.1 0.2 0.2 ----- ----- ----- Net expense 2.0 2.1 2.0 Special termination benefits -- 0.5 -- ----- ----- ----- Total expense $ 2.0 $ 2.6 $ 2.0 ===== ===== =====
A reconciliation of the plan's funded status with the recorded liability is presented below:
December 31, --------------- 1997 1996 ------ ------ Accumulated benefit obligation $11.7 $11.4 ===== ===== Fair value of plan assets $ -- $ -- ===== ===== Accumulated benefit obligation in excess of plan assets $11.7 $11.4 Unrecognized transition obligation (2.0) (2.2) Unrecognized net loss (1.1) (4.1) ----- ----- Recorded liability $ 8.6 $ 5.1 ===== ===== Discount rate 7.0% 7.75%
The assumed rate of future increases in the per capita cost of health care benefits is 8.5% for 1998, gradually decreasing to 5.25% for 2004 and beyond. Employee Stock Plans - -------------------- A 401(k) plan is maintained to supplement eligible U.S. employees' retirement income. The plan received EME contributions of $0.7 million in 1997, 1996 and 1995. 60 In addition to the defined benefit plans described above, certain U.K. subsidiaries of EME sponsor a defined contribution plan. Annual contributions are based on 8 to 8.6 percent of covered employees' salaries. Contribution expense for the subsidiaries totaled approximately $0.3 million in 1997 and $0.2 million in 1996 and 1995. NOTE 10. STOCK COMPENSATION PLANS - ---------------------------------- Under Edison International Officer's Long-Term Incentive Compensation Plan (LTIP), shares of Edison International common stock were reserved for potential issuance to key EME employees in various forms, including the exercise of stock options. Under these programs, there are currently outstanding to officers and senior managers of EME, options on 320,590 shares of Edison International Common Stock of which 61,300, 57,900 and 31,700 were granted in 1997, 1996 and 1995, respectively. Options on Edison International stock include a dividend equivalent feature. Compensation expense recorded under the stock-compensation program was $0.5 million, $0.7 million and $0.3 million for 1997, 1996 and 1995, respectively. The weighted-average fair value of options granted during 1997, 1996 and 1995 was $7.62 per share option, $6.27 per share option and $6.92 per share option, respectively. The weighted-average remaining life of options outstanding as of December 31, 1997, 1996 and 1995 was seven years. The fair value for each option granted during 1997, 1996 and 1995, reflecting the basis for the pro forma disclosures, was determined on the date of grant using the Black-Scholes option-pricing model. The following assumptions were used in determining fair value through the model:
1997 1996 1995 -------- -------- -------- Expected life 7 years 7 years 8 years Risk-free interest rate 6.5% 5.5% 7.9% Expected volatility 17% 17% 17%
The recognition of dividend equivalents results in no dividends assumed for purposes of fair-value determination. Stock-based compensation expense under the "fair-value" method of accounting prescribed by SFAS No. 123 "Stock-Based Compensation" would have resulted in no material change to EME's reported net income for 1997, 1996 and 1995, but is not necessarily indicative of future income statement effects. Phantom Stock Options EME, as a part of the LTIP, issued "phantom stock" option performance awards to key employees commencing in 1994. Each phantom stock option may be exercised to realize any appreciation in the value of one hypothetical share of EME stock over its exercise price. Exercise prices for EME phantom stock are escalated on an annually-compounded basis over the grant price by 12%. The value of the phantom stock is recalculated annually as determined by a formula linked to the value of its portfolio of investments less general and administrative costs. The options have a 10-year term with one-third of the total award vesting in each of the first three years of the award term. Compensation expense recorded with respect to phantom stock options was $70 million, $16.1 million and $0.8 million in 1997, 1996 and 1995, respectively. 61 NOTE 11. COMMITMENTS AND CONTINGENCIES - --------------------------------------- Firm Commitments to Contribute Project Equity
Projects Local Currency U.S. Currency - -------- -------------- ------------- Paiton (i) $136 ISAB (ii) 244 billion Italian Lira 138 Doga (iii) 21
(i) Paiton is a 1,230-MW coal-fired power plant under construction in East Java, Indonesia. A wholly owned subsidiary of EME owns a 40% interest. Equity contributions are currently being made and will continue until commercial operation, which is currently scheduled for the first half of 1999. (ii) ISAB is a 512-MW integrated gasification combined cycle power plant under construction near Siracusa in Sicily, Italy. A wholly owned subsidiary of EME owns a 49% interest. Equity will be contributed at commercial operation, which is currently scheduled for late 1999. (iii) Doga is a 180-MW gas-fired power plant under construction near Istanbul, Turkey. A wholly owned subsidiary of the Company owns an 80% interest. Equity contributions are currently being made and will continue until commercial operation, which is currently scheduled for 1999. Firm commitments to contribute project equity could be accelerated due to certain events of default as defined in the non-recourse project financing facilities. Management has no reason to believe that these events of default will occur requiring acceleration of the firm commitments. Contingent Obligations to Contribute Project Equity
Projects U.S. Currency - -------- ------------- Paiton (i) $141 Doga (i) 19 All Other 21
(i) Contingent obligations to contribute additional project equity to the project would be based on events principally related to capital cost overruns during the plant construction. Management has no reason to believe that these contingent obligations or any other contingent obligations to contribute project equity will be required. Other Commitments and Contingencies Certain of EME's subsidiaries entered into indemnification agreements whereby the subsidiaries agreed to repay capacity payments to the projects' power purchasers, in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contract. Obligations under these indemnification agreements as of December 31, 1997, if payment were required, would be $260 million. Management has no reason to believe that the projects 62 will either terminate their performance or reduce their electric power producing capability during the term of the power contracts. Brooklyn Navy Yard is a 286-MW gas-fired cogeneration power plant in Brooklyn, New York. A wholly owned subsidiary of EME owns 50% of the project. On December 17, 1997, the Brooklyn Navy Yard project partnership completed a $407 million permanent, non-recourse financing for the project. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. (BNY) for damages in the amount of $136.8 million. BNY has asserted general monetary claims against the contractor. In connection with the 1997 refinancing, EME agreed to indemnify the partnership and its partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to the lenders. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations. EME's projected construction expenditures that will be funded utilizing non- recourse project financing are $80 million at December 31, 1997. Litigation EME is routinely involved in litigation arising in the normal course of business. While the results of such litigation cannot be predicted with certainty, management, based on advice of counsel, does not believe that the final outcome of any pending litigation will have a material adverse effect on EME's financial position or results of operations. Environmental Matters or Regulations EME is subject to environmental regulation by federal, state and local authorities in the U.S. and foreign regulatory authorities with jurisdiction over projects located outside the U.S. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operations. EME completed a review of some of its sites in 1995 and does not believe that a material liability exists as of December 31, 1997. The implementation of Clean Air Act Amendments is expected to result in increased operating expenses; however, these increased operating expenses are not expected to have a material impact on EME's financial position or results of operations. NOTE 12. LEASE COMMITMENTS - --------------------------- EME leases office space, property and equipment under noncancelable lease agreements that expire in various years through 2063. The capital lease obligation is primarily for a project located in the U.K. A group of banks provides a guarantee on the performance of the capital lease obligation under a term loan and guarantee facility agreement. The facility agreement provides for an aggregate of $188.5 million in a guarantee to the lessor and in loans to the project. As of December 31, 1997, the loan obligation stands at $83.1 million, which is secured by the plant assets of $19 million owned by the project and a debt service reserve of $5.5 million. Future minimum payments for operating and capital leases at December 31, 1997, are: 63
Year Ending December 31: Operating Capital Leases Leases --------- ------- 1998 $ 6.7 $27.0 1999 5.4 27.1 2000 4.1 27.0 2001 3.9 0.2 2002 3.6 0.2 Thereafter 18.9 0.5 ----- ----- Total future commitments $42.6 82.0 ===== Amount representing interest (9.65%) 13.8 ----- Net Commitments $68.2 =====
Operating lease expense amounted to $6.7 million in 1997, $6.3 million in 1996 and $3.9 million in 1995. NOTE 13. RELATED PARTY TRANSACTIONS - ------------------------------------ Certain administrative services such as payroll and employee benefit programs, all performed by Edison International or Edison employees, are shared among all affiliates of Edison International and the costs of these corporate support services are allocated to all affiliates, including EME. Costs are allocated based on one of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of employees). In addition, services of Edison International or Edison employees are sometimes directly requested by EME and such services are performed for EME's benefit. Labor and expenses of these directly requested services are specifically identified and billed at cost. Management believes the allocation methodologies utilized are reasonable. EME made reimbursements for the cost of these programs and other services, which amounted to $23.4 million, $18.3 million and $15.9 million in 1997, 1996 and 1995, respectively. EME records accruals for tax liabilities and/or tax benefits which are settled quarterly according to a series of tax sharing agreements as described in Note 2. Under these agreements, EME recognized a tax benefit of $12.6 million for 1997 and tax liabilities of $39.8 million and $28.4 million for 1996 and 1995, respectively (see Note 8). Certain EME subsidiaries have ownership in partnerships that sell electricity generated by their project facilities to Edison and others under the terms of long-term power-purchase agreements. Sales by such partnerships to Edison under these agreements amounted to $579.6 million in 1997, $517.1 million in 1996, and $657.3 million in 1995. 64 NOTE 14. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION - -----------------------------------------------------------
Years Ended December 31, ------------------------- 1997 1996 1995 ------ ------ ------ Cash paid: Interest (net of amount capitalized) $218.1 $131.5 $ 76.4 Income taxes $ 62.3 $ 45.9 $ 41.6 Years Ended December 31, ------------------------- 1997 1996 1995 ------ ------ ------ Details of companies acquired: Fair value of assets acquired $667.1 $152.7 $1,761.1 Liabilities assumed 603.1 118.1 718.5 ------ ------ -------- Net cash paid for acquisitions $ 64.0 $ 34.6 $1,042.6 ====== ====== ========
Non-Cash Investing and Financing Activities The amount of construction in progress financed by the minority owner in the Loy Yang B joint venture was $0.1 million in 1997, $32.7 million in 1996 and $77.4 million in 1995. In June 1997, EME made a noncash dividend of $78 million to its parent company, TMG, a wholly owned, non-utility subsidiary of Edison International. The noncash dividend is in the form of a promissory note with interest at LIBOR plus 0.275% (6.09% at December 31, 1997) paid on quarterly basis and principal due on June 30, 2007. NOTE 15. GEOGRAPHIC AREAS - FINANCIAL DATA - ------------------------------------------- EME operates predominately in one industry segment: electric power generation. Electric power and steam generated domestically is sold primarily under long-term contracts to electric utilities and industrial steam users located in the U.S. Excluding the U.K. and a project in Australia, electric power generated overseas is sold primarily under long-term contracts to electric utilities located in the country where the power is generated. Projects located in the U.K. and a project in Australia sell their energy and capacity production through a centralized electricity pool. These projects enter into short - and/or long-term contracts to hedge against the volatility of price fluctuations in the pool.
Asia Corporate/ U.S. Pacific Europe Other(1) Total ------ -------- --------- ----------- -------- 1997 - ---- Electric & operating revenues $ 8.9 $ 312.8 $ 463.9 $ -- $ 785.6 Equity in income from investments 182.7 3.5 0.2 3.0 189.4 ------ -------- -------- ------ -------- Total operating revenues $191.6 $ 316.3 $ 464.1 $ 3.0 $ 975.0 ====== ======== ======== ====== ======== Net income (loss) $ 72.8 $ 11.1 $ 47.8 $(16.7) $ 115.0 ====== ======== ======== ====== ========
65 Identifiable assets $301.8 $ 948.0 $2,813.9 $ 1.6 $4,065.3 Equity investments and advances 623.9 252.7 42.9 0.3 919.8 ------ -------- -------- ------ -------- Total assets $925.7 $1,200.7 $2,856.8 $ 1.9 $4,985.1 ====== ======== ======== ====== ======== 1996 - ---- Electric & operating revenues $ 16.8 $ 245.1 $ 427.8 $ -- $ 689.7 Equity in income (loss) from investments 153.3 3.0 2.0 (4.4) 153.9 ------ -------- -------- ------ -------- Total operating revenues $170.1 $ 248.1 $ 429.8 $ (4.4) $ 843.6 ====== ======== ======== ====== ======== Net income (loss) $ 68.2 $ 22.5 $ 28.8 $(27.4) $ 92.1 ====== ======== ======== ====== ======== Identifiable assets $239.5 $1,512.7 $2,397.1 $ 87.3 $4,236.6 Equity investments and advances 709.2 141.3 30.8 34.6 915.9 ------ -------- -------- ------ -------- Total assets $948.7 $1,654.0 $2,427.9 $121.9 $5,152.5 ====== ======== ======== ====== ======== 1995 - ---- Electric & operating revenues $ 13.9 $ 170.8 $ 146.8 $ -- $ 331.5 Equity in income (loss) from investments 143.1 -- (2.7) (4.6) 135.8 ------ -------- -------- ------ -------- Total operating revenues $157.0 $ 170.8 $ 144.1 $ (4.6) $ 467.3 ====== ======== ======== ====== ======== Net income (loss) $ 57.0 $ 15.8 $ 7.9 $(16.7) $ 64.0 ====== ======== ======== ====== ======== Identifiable assets $112.9 $1,302.7 $1,988.6 $ 89.0 $3,493.2 Equity investments and advances 729.4 69.0 31.8 50.6 880.8 ------ -------- -------- ------ -------- Total assets $842.3 $1,371.7 $2,020.4 $139.6 $4,374.0 ====== ======== ======== ====== ========
(1) Includes corporate net interest expense and Mexico and Canada investments. NOTE 16. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS PRODUCING - ---------------------------------------------------------------------- ACTIVITIES (UNAUDITED) - ---------------------- This section provides information required by SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." All of EME's oil and gas operations are carried on by investees accounted for by the equity method. These investees all follow the successful efforts method of accounting. 66 EME's proportionate interest in net quantities of proved reserves at December 31, 1997, 1996 and 1995, and results of operations for the years then ended related to equity method investees are shown in the following tables:
Oil Natural Gas Million of Barrels Billion of Cubic Feet ------------------ --------------------- U.S. Canada Total U.S. Canada Total Proved developed and 1997 21.6 -- 21.6 189.3 -- 189.3 undeveloped reserves 1996 23.7 1.8 25.5 182.0 105.5 287.5 1995 23.1 2.0 25.1 180.6 118.5 299.1 U.S. Canada Total Costs incurred in oil and 1997 $ 18.9 $ -- $ 18.9 gas property acquisition 1996 13.4 4.2 17.6 exploration, and 1995 37.2 6.5 43.7 development activities Aggregate amounts of 1997 $194.9 $ -- $194.9 capitalized costs 1996 206.6 42.4 249.0 (including construction in 1995 202.1 46.6 248.7 progress) for proved and unproved properties Results of operations 1997 $ 39.2 $ -- $ 39.2 1996 39.2 (2.6) 36.6 1995 16.7 (2.5) 14.2 Standardized measure of 1997 $249.2 $ -- $249.2 discounted future net cash 1996 435.8 63.6 499.4 flows 1995 246.5 33.4 279.9
In 1997, EME completed a sale of its ownership interest in B.C. Star Partners which operated eleven producing properties in British Columbia, Canada. The increase in 1996 in U.S. results of operations and total standardized measure resulted primarily from higher oil and gas prices in 1996. NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED) - ----------------------------------------------
1997 First(d) Second Third(d) Fourth(d) Total -------- ----------- -------- --------- ------- Operating revenues $285.0 $ 221.5/(c)/ $234.5 $234.0 $975.0 Income from operations 133.6 86.6 91.2 82.5 393.9 Net income 32.6 19.4/(a)//(b)/ 46.1 16.9 115.0
67
1996 First(d) Second Third(d) Fourth(d)(f) Total ------- ------ ------- ----------- ----- Operating revenues $190.7 $184.3 $212.0 $256.6 $843.6 Income from operations 85.2 73.3 107.5 101.1 367.1 Net income 22.0 31.0/(e)/ 31.0 8.1 92.1
(a) Includes a $14 million gain on sale of ownership interest in an oil and gas investment. (b) Includes a $13.1 million extraordinary loss on early extinguishment of debt. (c) Decline in revenues as a result of restructuring agreements associated with the 49% acquisition of Loy Yang B in May 1997. (d) Reflects EME's seasonal pattern, in which the majority of earnings from domestic projects are recorded in the third quarter of each year and higher electric revenues from certain international projects are recorded during the winter months of each year. (e) Includes a $15.5 million gain on the sale of four operating geothermal facilities. (f) Includes operating revenues and income for Loy Yang B Unit 2 and the Kwinana project which both commenced operations in the fourth quarter of 1996. 68 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT POSITIONS WITH EME The following table sets forth the names and ages of, the positions held with EME by, and the terms of office of, the directors and executive officers of EME as of March 1, 1998.
DIRECTOR POSITION HELD CONTINUOUSLY TERM CONTINUOUSLY TERM NAME, POSITION AND AGE SINCE EXPIRES SINCE EXPIRES - ---------------------- ------------ ------- ------------- ------- Alan J. Fohrer, 47................................................................ 1992 1998 -- -- Chairman of the Board Bryant C. Danner, 60.............................................................. 1993 1998 -- -- Director Robert M. Edgell, 51.............................................................. 1993 1998 1988 1998 Director, Executive Vice President and Division President of EME, Asia Pacific Edward R. Muller, 45.............................................................. 1993 1998 1993 1998 Director, President and Chief Executive Officer S. Linn Williams, 51.............................................................. -- -- 1994 1998 Senior Vice President and General Counsel Terry V. Charlton, 51............................................................. -- -- 1997 1998 Senior Vice President and Division President of EME, Europe, Central Asia, Middle East and Africa James V. Iaco, Jr., 53............................................................ -- -- 1994 1998 Senior Vice President and Chief Financial Officer Division President of EME, Americas Georgia R. Nelson, 48............................................................. -- -- 1996 1998 Senior Vice President, Worldwide Operations
BUSINESS EXPERIENCE Set forth below is a description of the principal business experience during the past five years of each of the individuals named above and the name of each public company in which any director named above is a director. MR. FOHRER has been Chairman of the Board of EME since January 30, 1998. From 1993 to 1998, Mr. Fohrer served as Vice Chairman of the Board. Mr. Fohrer has been Executive Vice President and Chief Financial Officer of Edison International and SCE since June 1995. Effective February 1996 and June 1995, Mr. Fohrer also served as Treasurer of SCE and Edison International, respectively, until August 1996. Mr. Fohrer was Senior Vice President, Treasurer and Chief Financial Officer of Edison International, and Senior Vice President and Chief Financial Officer of SCE from January 1993 until May 1995. Mr. Fohrer was interim Chief Executive Officer of EME between May 1993 and August 1993. From 1991 until 1993, Mr. Fohrer was Vice President, Treasurer and Chief Financial Officer of Edison International and SCE. MR. DANNER has been Executive Vice President and General Counsel of Edison International and SCE since June 1995. Mr. Danner was Senior Vice President and General Counsel of Edison International and SCE from July 1992 until May 1995. 69 MR. EDGELL has been Executive Vice President of EME since april 1988. Mr. Edgell was named Division President of EME'S Asia Pacific region in January 1995. MR. MULLER has been President and Chief Executive Officer of EME since August 1993. Prior to joining EME, Mr. Muller served as vice president, chief administrative officer, general counsel and secretary of Whittaker Corporation, an aerospace firm, from 1988 until 1992 and as vice president, chief financial officer, general counsel and secretary of Whittaker Corporation from 1992 until 1993. from 1991 until 1993, Mr. Muller also served as vice president, secretary and general counsel of BioWhittaker, Inc., a biotechnology company. Mr. Muller is a director of Whittaker Corporation, Oasis Residential, Inc. and Global Marine Inc. MR. WILLIAMS has been Senior Vice President and General Counsel of EME since November 1994. From 1985 through 1989 and 1992-1993, Mr. Williams was a partner with the law firm of Gibson, Dunn and Crutcher. From 1993-1994, Mr. Williams was a partner with the law firm of Jones, Day, Reavis and Pogue. MR. CHARLTON has been Senior Vice President and Division President, Europe, Central Asia, Middle East and Africa since September 8, 1997. Prior to joining EME, Mr. Charlton worked as a consultant for EME. Mr. Charlton served as Group General Manager - Water, Oil and Gas Industries Group for Tubemakers of Australia Limited from 1993 until 1996. MR. IACO has been Senior Vice President and Chief Financial Officer of EME since January 1994 and Division President of EME's Americas region since January 26, 1998. From September 1993 until December 1993, Mr. Iaco was self-employed and provided consulting services, specializing in restructuring, finance, crisis management and other management services. From October 1992 until September 1993, Mr. Iaco served as senior vice president and chief financial officer of Phoenix Distributors, Inc., a distributor of industrial gas and welding supplies. MS. NELSON has been Senior Vice President, Worldwide Operations since January 1996. Ms. Nelson was Division President of EME's Americas region from January 1996 to January 26, 1998. Prior to joining EME, Ms. Nelson served as Senior Vice President of SCE from June 1995 until December 1995 and Vice President of SCE from March 1993 until June 1995. From 1992 to 1993, Ms. Nelson served as a Special Assistant to the Chairman of Edison International. Ms. Nelson is a director of CalMat Company. 70 ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE The following table provides information concerning compensation paid by EME to each of the named executive officers during the years 1997, 1996 and 1995 for services rendered by such persons in all capacities to EME and its subsidiaries. SUMMARY COMPENSATION TABLE
LONG-TERM COMPENSATION ANNUAL COMPENSATION AWARDS ----------------------------------------- ------------- OTHER ANNUAL SECURITIES ALL OTHER SALARY BONUS COMPENSATION UNDERLYING COMPENSATION NAME AND PRINCIPAL POSITION YEAR ($) ($) ($) OPTIONS (#)(2) ($)(3) - ---------------------------------------- ---- ------- ------- ------------- -------------- ------------ Edward R. Muller 1997 400,000 456,000 3,478 33,300 28,587 President and Chief Executive Officer 1996 370,000 444,000 2,621 41,000 23,148 1995 335,000 331,700 2,646 53,190 17,521 Robert M. Edgell 1997 317,000 325,000 -- 23,300 33,600(4) Executive Vice President 1996 292,000 275,000 133 25,700 88,071(4) 1995 252,000 250,000 700 30,770 8,492 S. Linn Williams 1997 300,000 240,000 1,643 15,400 18,568 Senior Vice President 1996 275,000 220,000 734 20,100 13,148 and General Counsel 1995 250,000 180,000 1,028 24,390 141 Georgia R. Nelson (1) 1997 290,000 206,000 7,125 15,400 17,829 Senior Vice President, Worldwide 1996 270,000 190,000 1,337 23,700 14,446 Operations James V. Iaco, Jr. 1997 280,000 224,000 4,913 15,400 14,962 Senior Vice President and Chief 1996 250,000 200,000 2,906 19,800 10,416 Financial Officer 1995 190,000 140,000 2,223 19,710 0
(1) Ms. Nelson was appointed Senior Vice President, Operations and Division President of EME, Americas in January 1996. (2) No Stock Appreciation Rights (SARs) were granted. Amounts shown are comprised of Edison International nonqualified stock options and EME "phantom stock" options. For 1997, Mr. Muller, Mr. Edgell, Mr. Williams, Ms. Nelson and Mr. Iaco received 10,500; 7,500; 5,500; 5,500 ; and 5,500 Edison International stock options, respectively; and 22,800; 15,800; 9,900; 9,900; and 9,900 EME phantom stock options, respectively. For 1996, Mr. Muller, Mr. Edgell, Mr. Williams, Ms. Nelson and Mr. Iaco received 10,200; 6,600; 5,400; 9,000; and 5,100 Edison International stock options, respectively; and 30,800; 19,100; 14,700; 14,700; and 14,700 EME phantom stock options, respectively. For 1995, Mr. Muller, Mr. Edgell, Mr. Williams and Mr. Iaco received 10,000; 5,200; 4,500; and 3,800 Edison International stock options, respectively; and 43,190; 25,570; 19,890; and 15,910 EME phantom stock options, respectively. Each Edison International nonqualified stock option gives the named 71 executive officer the right to purchase one share of Edison International Common Stock, and each EME phantom stock option may be exercised to realize any appreciation in the value of one hypothetical share of EME stock over annually escalated exercise prices, on the terms described in the notes to the Option Grants in the 1997 Option Grant Table below. (3) Includes the following company contributions to a defined contribution plan, Stock Savings Plus Plan (SSPP) and a supplemental plan for eligible participants who are affected by SSPP participation limits imposed on higher-paid individuals by federal tax law: For 1997, Mr. Muller, $25,305; Mr. Edgell $13,000; Mr. Williams, $15,599; Ms. Nelson, $14,384; and Mr. Iaco, $14,376. For 1996, Mr. Muller, $11,455; Mr. Edgell, $4,500; Mr. Williams, $6,301; Ms. Nelson, $7,913; and Mr. Iaco, $6,077. For 1995, Mr. Muller, $15,988; Mr. Edgell, $8,220; Mr. Williams, $0; and Mr. Iaco, $0. Also includes the following amounts of interest accrued on deferred compensation of the named individuals, which is considered under the rules of the Securities and Exchange Commission to be at an above-market rate: For 1997, Mr. Muller, $3,283; Mr. Edgell, $458; Mr. Williams, $2,969; Ms. Nelson, $3,445; and Mr. Iaco, $586. For 1996, Mr. Muller, $1,508; Mr. Edgell, $239; Mr. Williams, $926; Ms. Nelson, $1,882; and Mr. Iaco, $139. For 1995, Mr. Muller, $1,533; Mr. Edgell $272; Mr. Williams, $141; and Mr. Iaco, $0. (4) Includes an overseas service allowance of $20,142 and $75,832 in 1997 and 1996, respectively. For each employee serving in an overseas site, the allowance calculation depends on base pay, family size and location. EXECUTIVE STOCK OPTIONS The following table sets forth certain information concerning Edison International stock options and EME phantom stock options granted pursuant to the Edison International Officer's Long-Term Incentive Compensation Plan (LTIP) to the executive officers named in the Summary Compensation Table above during 1997.
OPTION GRANTS IN 1997(1) Individual Grants ---------------------------------------------------------- Exercise Options Percent of Total or Base Grant Date Granted Options Granted to Price Expiration Present Name (#) Employees in 1997 ($/Sh) Date Value ($) ---- ------- ------------------ -------- ---------- --------- (2)(3) (4)(5) (6) Edward R. Muller Edison International 10,500 17% 19.75 01/02/2007 61,005 EME 22,800 10% 120.55 01/02/2007 230,964 Robert M. Edgell Edison International 7,500 12% 19.75 01/02/2007 43,575 EME 15,800 7% 120.55 01/02/2007 160,054 S. Linn Williams Edison International 5,500 9% 19.75 01/02/2007 31,955 EME 9,900 4% 120.55 01/02/2007 100,287 Georgia R. Nelson Edison International 5,500 9% 19.75 01/02/2007 31,955 EME 9,900 4% 120.55 01/02/2007 100,287 James V. Iaco, Jr. Edison International 5,500 9% 19.75 01/02/2007 31,955 EME 9,900 4% 120.55 01/02/2007 100,287
72 (1) No SARs were granted. This table reflects all awards made under the LTIP ("LTIP Options") during 1997. In addition to Edison International stock options, it includes EME "phantom stock" options. (2) Each Edison International nonqualified stock option represents the right to purchase one share of common stock of Edison International. The Edison International stock options include dividend equivalents equal to the dividends that would have been paid on an equal number of shares of Edison International Common Stock. Dividend equivalents will be credited following the first three years of the option term if certain Edison International performance criteria discussed below are met. Dividend equivalents accumulate without interest. Once earned and vested, the dividend equivalents are payable in cash (i) upon the request of the holder prior to the final year of the option term, (ii) upon the exercise of the related option, or (iii) at the end of the option term regardless of whether the related option is exercised. After such payment, however, no additional dividend equivalents will accrue on the related option. The dividend equivalent performance criteria is measured by Edison International Common Stock total shareholder return. If the average quarterly percentile ranking is less than the 60th percentile of that of the companies comprising the Dow Jones Electric Utilities Group Index, the dividend equivalents are reduced; if the Edison International total shareholder return ranking is less than the 25th percentile, the dividend equivalents are canceled. For rankings between the 60th and 25th percentiles, the dividend equivalents are prorated. The total shareholder return is measured at the end of the initial three-year period and will set the percentage payable for the entire term. If less than 100% of the dividend equivalents are earned, the unearned portion may be restored later in the option term if Edison International's cumulative total shareholder return ranking for the option term attains at least the 60th percentile. (3) Each EME phantom stock option represents a right to exercise an option to realize any appreciation in the value of one hypothetical share of EME stock. The value of the stock is determined by a formula linked to project values, which are determined annually, and is based on 10 million total shares. Project values are determined based on economic models whose assumptions have been approved by Edison International Phantom Plan Management and Valuation Committees. The valuation is consistent with the bases on which EME invests, acquires, finances, refinances and otherwise makes capital decisions for new investments and value-maximizing decisions for existing investments. The exercise price is initially set equal to the value of the stock on the date of grant escalated on a compound basis (12% per year) thereafter by a factor reflecting the approximate cost of capital during the year as determined by the Compensation and Executive Personnel Committee (CEP Committee) of Edison International. The annual escalation factor will be adjusted prospectively by the CEP Committee for significant changes in the cost of capital. If the value of a share of EME stock exceeds the exercise price for any subsequent year, the executive may exercise his option right with respect to any portion of his vested units during the 60-day exercise window in the second quarter of the following year and be paid in cash the difference between the exercise price and the value of the shares. (4) The LTIP Options become exercisable in three equal installments beginning on the first anniversary of their date of grant. Each option has a term of 10 years, subject to earlier expiration upon termination of employment as described below. The options are not transferable except upon death. Effective January 1, 1998, outstanding LTIP Options were amended to allow certain senior officers to transfer LTIP Options to a spouse, child or grandchild. If an executive retires, dies, or is permanently and totally disabled during the three-year vesting period, the unvested LTIP Options will vest and be exercisable to the extent of 1/36 of the grant for each full month of service during the vesting period. Unvested LTIP Options of any person who has served in the past on the Edison International or SCE Management Committee will vest and be exercisable upon the member's retirement, death, or permanent and total disability. None of the named officers have served on either of the two committees. Upon retirement, death or permanent and total disability, the vested LTIP Options may continue to be exercised within their original term by the recipient or beneficiary. If an executive is terminated other than by retirement, death or permanent and total disability, LTIP Options which had vested as of the prior anniversary date of the grant are forfeited unless exercised within 180 days of the 73 date of termination in the case of Edison International options, or during the next 60-day exercise window in the case of EME phantom stock options. All unvested LTIP Options are forfeited on the date of termination. Appropriate and proportionate adjustments may be made by the Edison International CEP Committee to outstanding Edison International stock options to reflect any impact resulting from various corporate events such as reorganizations, stock splits and so forth. If Edison International is not the surviving corporation in such a reorganization, all LTIP Options then outstanding will become vested and be exercisable unless provisions are made as part of the transaction to continue the LTIP or to assume or substitute stock options of the successor corporation with appropriate adjustments as to the number and price of the options. The Edison International CEP Committee administers the LTIP and has sole discretion to determine all terms and conditions of any grant, subject to plan limits. It may substitute cash equivalent in value to the LTIP Options and, with the consent of the executive, may amend the terms of any award agreement, including the price of any option, the post-termination term, and the vesting schedule. (5) The expiration date of the LTIP Options is January 2, 2007; however, the final 60-day exercise period of EME phantom stock options will occur during the second quarter of that year. The LTIP Options are subject to earlier expiration upon termination of employment as described in footnote (4) above. (6) The grant date present value of each Edison International stock option was calculated as the sum of (i) the option value and (ii) the dividend equivalent value. The option value was calculated to be approximately $2.56 per option share using the Black-Scholes stock option pricing model. For purposes of this calculation, it was assumed that options would be outstanding for an average of seven years prior to exercise, the volatility rate was assumed to be 17%, the risk-free rate of return was assumed to be 6.45%, the historic average dividend yield was assumed to be 5.89% and the stock price and exercise price were $19.75. The dividend equivalent value of each Edison International stock option granted in 1997 was calculated to be $3.25. The grant date value of the dividend equivalent rights included with respect to each Edison International stock option was determined by (i) adding the dividends (without reinvestment) that would be received on a number of shares of Edison International common stock equal to the number of shares subject to the option for a period of seven years from the date on which the option was granted, based on the annual dividend rate at grant of $1.00 per share and (ii) discounting that amount to its present value assuming a discount rate of 11.6%, which was Edison's authorized return on common equity in 1997. This calculation does not reflect any reduction in value for the risk that Edison International performance measures may not be met. The value of an EME option was calculated to be $10.13 using the Black- Scholes stock option pricing model assuming an average exercise period of seven years, a volatility rate of 19.22%, a risk-free rate of return of 6.37%, a dividend yield of 0% and an exercise price of $266.50. These assumptions are based on average values of a group of peer companies adjusted for differences in capital structure. The actual value that an executive may realize will depend on various factors on the date the option is exercised, so there is no assurance the value realized by an executive will be at or near the grant date value estimated by the Black-Scholes model. The estimated values under that model are based on certain assumptions and are not a prediction as to future stock price. 74 The following table sets forth certain information with respect to the exercise during 1997 by the executive officers named in the Summary Compensation Table above of options to purchase shares of common stock of Edison International and exercise hypothetical shares of stock of EME and option values as of December 31, 1997. AGGREGATED OPTION EXERCISES IN 1997 AND YEAR-END OPTION VALUES
NUMBER OF VALUE OF UNEXERCISED UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS AT FISCAL YEAR-END (#) FISCAL YEAR-END ($)(1) ---------------------- ----------------------- SHARES ACQUIRED ON EXERCISABLE/ EXERCISABLE/ NAME EXERCISE (#) VALUE REALIZED ($) UNEXERCISABLE UNEXERCISABLE - ---- ------------------ ------------------ ------------- ------------- Edward R. Muller Edison International -- -- 44,167/20,633 270,383/185,198 EME -- -- 56,880/57,730 2,688,213/1,487,610 Robert M. Edgell Edison International -- -- 41,717/13,633 286,876/119,735 EME -- -- 34,634/37,056 1,630,303/900,457 S. Linn Williams Edison International -- -- 4,800/10,600 55,088/94,269 EME -- -- 18,160/26,330 889,867/696,864 Georgia R. Nelson Edison International 38,600 193,165(2) 4,800/22,300 21,975/234,631 EME -- -- 4,900/19,700 167,954/335,908 James V. Iaco, Jr. Edison International 6,534 35,835(3) 0/10,166 0/89,402 EME -- -- 22,547/25,003 1,049,102/624,618
(1) Edison International options are treated as "in-the-money" if the fair market value of the underlying shares at December 31, 1997, exceeded the exercise price of the options. The dollar amounts shown for Edison International options are the differences between (i) the fair market value of the Edison International Common Stock underlying all unexercised "in-the- money" options at year-end 1997 and (ii) the exercise prices of those options. The aggregate value at year-end 1997 of all accrued dividend equivalents, exercisable and unexercisable, for Mr. Muller, Mr. Edgell, Mr. Williams, Ms. Nelson and Mr. Iaco was $144,572/$0, $248,882/$0, $0/$0, $30,288/$0 and $0/$0, respectively. EME phantom stock options are considered "in-the-money" if the value of EME phantom stock, which is determined annually by a formula linked to project values, exceeds prescribed exercise prices. The value at year-end is not available until the second quarter of the following year. Therefore, amounts shown reflect the value at fiscal year-end for 1996, the most recent data available. (2) Includes $27,790 of value realized from dividend equivalents. (3) Includes $4,565 of value realized from dividend equivalents. 75 RETIREMENT BENEFITS - ------------------- The following table sets forth estimated gross annual benefits payable upon retirement at age 65 to the executive officers named in the Summary Compensation Table above in the remuneration and years of service classifications indicated. PENSION PLAN TABLE(1)
YEARS OF SERVICE -------------------------------------------------------------------------- REMUNERATION 10 15 20 25 30 35 40 - --------------- -------- -------- -------- -------- -------- -------- -------- $ 100,000 $ 25,000 $ 33,750 $ 42,500 $ 51,250 $ 60,000 $ 65,000 $ 70,000 150,000 37,500 50,625 63,750 76,875 90,000 97,500 105,000 200,000 50,000 67,500 85,000 102,500 120,000 130,000 140,000 250,000 62,500 84,375 106,250 128,125 150,000 162,500 175,000 300,000 75,000 101,250 127,500 153,750 180,000 195,000 210,000 350,000 87,500 118,125 148,750 179,375 210,000 227,500 245,000 400,000 100,000 135,000 170,000 205,000 240,000 260,000 280,000 450,000 112,500 151,875 191,250 230,625 270,000 292,500 315,000 500,000 125,000 168,750 212,500 256,250 300,000 325,000 350,000 550,000 137,500 185,625 233,750 281,875 330,000 357,500 385,000 600,000 150,000 202,500 255,000 307,500 360,000 390,000 420,000
(1) Estimates are based on the provisions of the retirement plan (the "Retirement Plan"), a qualified defined benefit employee retirement plan, currently covering EME's executive officers with the following assumptions: (i) the present Retirement Plan will be maintained, (ii) optional forms of payment that reduce benefit amounts have not been selected, and (iii) any benefits in excess of limits contained in the Internal Revenue Code of 1986 (the "Code") and any incremental retirement benefits attributable to consideration of the annual bonus or participation in EME's deferred compensation plans will be paid out of the general assets of EME under a nonqualified supplemental executive retirement plan (an "ERP"). Amounts in the Pension Plan Table include neither the Income Continuation Plan nor the Survivor Income/Retirement Income plans, which provide postretirement death benefits and supplemental retirement income benefits. These plans are discussed in "Other Retirement Benefits". The Retirement Plan and ERP provide monthly benefits at normal retirement age (65 years) based on a unit benefit for each year of service plus a benefit determined by a percentage ("Service Percentage") of the executive's average highest 36 consecutive months of regular salary and, in the case of the ERP, the average highest three bonuses in the last five years prior to attaining age 65. Compensation used to calculate combined benefits under the Retirement Plan and ERP is based on base salary and bonus as reported in the Summary Compensation Table. The Service Percentage is based on 1-3/4% per year for the first 30 years of service (52-1/2% upon completion of 30 years' service) and 1% for each year in excess of 30. The actual benefit determined by the Service Percentage would take into account the unit benefit and be offset by up to 40% of the executive's primary Social Security benefits. The normal form of benefit is a life annuity with a 50% survivor benefit following the death of the participant. Retirement benefits are reduced for retirement prior to age 61. The amounts shown in the 76 Pension Plan Table above do not reflect reductions in retirement benefits due to the Social Security offset or early retirement. Mr. Edgell has elected to retain coverage under a previous benefit program. This program provided, among other benefits, the post-retirement benefits discussed in the following section. The ERP benefits provided in the previous program are less than the benefits shown in the Pension Plan Table. To determine these reduced benefits, multiply the dollar amounts shown in each column by the following factors: 10 years of service -- 70%, 15 years -- 78%, 20 years -- 82%, 25 years -- 85%, 30 years -- 88%, 35 years -- 88%, and 40 years -- 89%. At December 31, 1997, Mr. Muller had completed 4 years of service; Mr. Edgell, 27 years; Mr. Williams, 3 years; Ms. Nelson, 27 years; Mr. Iaco, 3 years. OTHER RETIREMENT BENEFITS Additional post-retirement benefits are provided pursuant to the Survivor Income Continuation Plan and the Survivor Income/Retirement Income Plan under the Executive Supplemental Benefit Program. The Survivor Income Continuation Plan provides a post-retirement survivor benefit payable to the beneficiary of the executive officer following his or her death. The benefit is approximately 24% of final compensation (salary at retirement and the average of the three highest bonuses paid in the five years prior to retirement) payable for ten years certain. If a named executive officer's final annual compensation were $600,000 (the highest compensation level in the Pension Plan Table above), the beneficiary's estimated annual survivor benefit would be approximately $144,000. Mr. Edgell has elected coverage under this program. The Supplemental Survivor Income/Retirement Income Plan provides a post- retirement survivor benefit payable to the beneficiary of the executive officer following his or her death. The benefit is 25% of final compensation (salary at retirement and the average of the three highest bonuses paid in the five years prior to retirement) payable for ten years certain. At retirement, an executive officer has the right to elect the retirement income benefit in lieu of the survivor income benefit. The retirement income benefit is 10% of final compensation (salary at retirement and the average of the three highest bonuses paid in the five years prior to retirement) payable to the executive officer for ten years certain immediately following retirement. If a named executive officer's final annual compensation were $600,000 (the highest compensation level in the Pension Plan Table above), the beneficiary's estimated annual survivor benefit would be approximately $150,000. If a named executive officer were to elect the retirement income benefit in lieu of survivor income and had final annual compensation of approximately $600,000 (the highest compensation level in the Pension Plan Table above), the named executive officer's estimated annual benefit would be approximately $60,000. Mr. Edgell has elected coverage under this program. The 1985 Deferred Compensation Plan provides a post-retirement survivor benefit. This plan allowed eligible participants in September 1985 to elect voluntarily to defer until retirement a portion of annual salary and annual bonuses otherwise earned and payable for the period October 1985 through January 1990. The post-retirement survivor benefit is 50% of the annual deferred compensation payable from the participant's account. Survivor benefit payments begin following completion of the participant's deferred compensation payments. If the named beneficiary is the executive's spouse, then survivor benefits are paid as a life annuity, five years certain; the benefit amount will be reduced actuarially if the 77 spouse is more than five years younger than the executive at the time of the executive's death. If the beneficiary is not the spouse, then benefits are paid for five years only. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT CERTAIN BENEFICIAL OWNERS - -------------------------- Set forth below is certain information regarding each person who is known to EME to be the beneficial owner of more than five percent of EME's common stock.
Title of Class Name and Amount and Percent of -------------- Address of Nature of Class Beneficial Beneficial ------------ Owner Ownership ---------- ---------- Common Stock, no par value The Mission 100 shares 100% Group held directly 18101 Von and with Karman Avenue, exclusive Suite 1700 voting and Irvine, investment California power 92612
MANAGEMENT - ---------- Set forth below is certain information about the beneficial ownership in equity securities of Edison International by all directors of EME, the executive owners of EME named in the Summary Compensation Table in Item 6 and all directors and executive officers of EME as a group.
Amount and Nature of Beneficial Ownership as of Company and December 31, Name Class of Stock 1997(a)(b)(c)(d)(e) - ----- --------------------- ------------------------------ John E. Bryson Edison International Common Stock 504,128(f) Alan J. Fohrer Edison International Common Stock 143,239 Bryant C. Danner Edison International Common Stock 140,030 Robert M. Edgell Edison International Common Stock 62,877 Edward R. Muller Edison International Common Stock 56,200 Mission Capital Preferred Securities 2,198 S. Linn Williams Edison International Common Stock 9,998 Georgia R. Nelson Edison International Common Stock 35,187 James V. Iaco, Jr. Edison International Common Stock 4,800 Mission Capital Preferred Securities 1,700 All directors and Edison International executive officers as Common Stock 956,459 a group Mission Capital Preferred Securities 3,898
(a) Unless otherwise indicated, each named person has voting and investment power over the listed shares and such voting and investment power is exercised solely by the named person or shared with a spouse. No named person or group owns more than 1% of the outstanding shares of the class. (b) Includes the following number of Edison International shares owned under the SSPP: Mr. Bryson, 14,127 shares; Mr. Fohrer, 12,238 shares; Mr. Danner, 1,829 shares; Mr. Edgell, 14,727 shares; Mr. Muller, 0 shares; Mr. Williams, 64 shares; Ms. Nelson, 14,753 shares; Mr. Iaco, 0 shares; and all directors and executive officers as a group, 57,738 shares. Each such person and group may be deemed to share voting power with the trustee appointed under the SSPP. (c) Includes the following number of Edison International shares with respect to which the right exists to acquire beneficial ownership within 60 days through the exercise of options granted under an employee benefit plan 78 known as the 1987 Long-Term Incentive Compensation Plan as amended and restated by the Edison International Officer Long-Term Incentive Compensation Plan effective April 16, 1992: Mr. Bryson, 477,801 shares; Mr. Fohrer, 130,501 shares; Mr. Danner, 136,201 shares; Mr. Edgell, 48,150 shares; Mr. Muller, 54,400 shares; Mr. Williams, 9,934 shares; Ms. Nelson, 20,434 shares; Mr. Iaco, 4,800 shares; and all directors and executive officers as a group, 882,221 shares. (d) Includes Edison International shares held in own name by Mr. Fohrer, 500 shares; spouse's name by Mr Bryson, 200 shares; held with another person by Mr. Bryson, 6,000 shares; held as trustee by Mr. Bryson, 6,000 shares; held as custodian by Mr. Muller, 400 shares; and held in broker's name by Mr. Danner, 2,000 shares, and Mr. Muller, 1,400 shares. (e) Includes the following number of shares of Monthly Income Preferred Securities of Mission Capital, a limited partnership of which EME is the sole general partner: Mr. Muller, 280 shares held in spouse's name, 390 shares held in custodial names and 8 shares held as co-trustee of trust with shared voting and investment power; Mr. Iaco, 750 shares held in spouse's name; all directors and executive officers as a group, 1,030 shares held in spouses' names and 390 shares held in custodial names. (f) Mr. Bryson retired as Chairman of EME's Board effective January 30, 1998. SECTION 16 (a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE - -------------------------------------------------------- Pursuant to Item 405 of Regulation S-K, EME is required to disclose the following recently elected officers who each had one delinquent Form 3 "Initial Statement of Beneficial Ownership of Securities" filing which is required to be filed within 10 days of being elected for fiscal year 1997: NAME DATE ELECTED ---- ------------ Cynthia S. Dubin, Vice President July 15, 1997 Edward J. Kania, Vice President July 15, 1997 William P. von Blasingame, Vice President July 15, 1997 Stephen P. Barrett, Vice President July 15, 1997 Michael P. Childers, Vice President December 1, 1997 Steven R. Schuler, Vice President December 16, 1997 79 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS In April 1994, EME made a loan to S. Daniel Melita, Vice President of EME, in the amount of $150,000 in exchange for a note executed by Mr. Melita and payable to EME at seven percent (7%) annual interest. The entire note, together with accrued interest, was paid in December 1996. The largest aggregate amount of indebtedness outstanding under the loan during 1996 was $171,000. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a)(1) LIST OF FINANCIAL STATEMENTS See Index to Consolidated Financial Statements at Item 8 of this report. (2) LIST OF FINANCIAL STATEMENT SCHEDULES The following item is filed as a part of this report pursuant to Item 14(d) of Form 10-K: The Cogeneration Group Combined Financial Statements as of December 31, 1997, 1996 and 1995. Schedules pursuant to Item 8 of Form 10-K are omitted because the required information is either presented in the financial statements or notes thereto, or is not applicable, required or material. (3) LIST OF EXHIBITS (a) EXHIBIT NO. DESCRIPTION - ----------- ----------- 2.1 Agreement for the sale and purchase of shares in First Hydro Limited, dated December 21, 1995 between PSB Holding Limited and First Hydro Finance Plc, incorporated by reference to Exhibit 2.1 to EME's Current Report on Form 8-K, No. 1-13434 dated January 4, 1996. 2.2 Transaction Implementation Agreement, dated March 29, 1997 between The State Electricity Commission of Victoria, Edison Mission Energy Australia Limited, Loy Yang B Power Station Pty Ltd, Loy Yang Power Limited, The Honourable Alan Robert Stockdale, Leanne Power Pty Ltd and EME, incorporated by reference to Exhibit 2.2 to EME's Current Report on Form 8-K, No. 1-13434 dated May 22, 1997. 3.1 Amended and Restated Articles of Incorporation of EME incorporated by reference to Exhibit 3.1 to EME's Current Report on Form 8-K, No. 1-13434 dated January 30, 1996. Originally filed with EME's Registration Statement on Form 10 to the Securities and Exchange Commission on September 30, 1994 and amended by Amendment No. 1 thereto dated November 19, 1994 and Amendment No. 2 thereto dated November 21, 1994 (as so amended, the "Form 10"). 3.2 By-Laws of EME, incorporated by reference to Exhibit 3.2 to EME's Form 10. 4.1 Copy of the Global Debenture representing EME's 9-7/8% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2024. 80 EXHIBIT NO. DESCRIPTION - ----------- ----------- 4.2 Conformed copy of the Indenture dated as of November 30, 1994 between EME and The First National Bank of Chicago, as trustee. 4.2.1 First Supplemental Indenture dated as of November 30, 1994 to Indenture dated as of November 30, 1994 between EME and The First National Bank of Chicago, as trustee. 10.2 Power Purchase Contract between Southern California Edison Company and Champlin Petroleum Company, dated March 8, 1985, incorporated by reference to Exhibit 10.2 to EME's Form 10. 10.2.1 Amendment to Power Purchase Contract between Southern California Edison Company and Champlin Petroleum Company, dated July 29, 1985, incorporated by reference to Exhibit 10.2.1 to EME's Form 10. 10.2.2 Amendment No. 2 to Power Purchase Contract between Southern California Edison Company and Champlin Petroleum Company, dated October 29, 1985, incorporated by reference to Exhibit 10.2.2 to EME's Form 10. 10.4 Power Purchase Contract between Southern California Edison Company and Imperial Energy Company, dated February 22, 1984, incorporated by reference to Exhibit 10.4 to EME's Form 10. 10.4.1 Amendment to Power Purchase Contract between Southern California Edison Company and Imperial Energy Company, dated November 13, 1984, incorporated by reference to Exhibit 10.4.1 to EME's Form 10. 10.6 Power Purchase Contract between Southern California Edison Company and Imperial Energy Company Niland No. 2, dated April 16, 1985, incorporated by reference to Exhibit 10.6 to EME's Form 10. 10.7 Power Purchase Contract between Southern California Edison Company and Chevron U.S.A. Inc., dated November 9, 1984, incorporated by reference to Exhibit 10.7 to EME's Form 10. 10.7.1 Amendment No. 1 to Power Purchase Contract between Southern California Edison Company and Chevron U.S.A. Inc., dated March 29, 1985, incorporated by reference to Exhibit 10.7.1 to EME's Form 10. 10.7.2 Amendment No. 2 to Power Purchase Contract between Southern California Edison Company and Chevron U.S.A. Inc., dated November 21, 1985, incorporated by reference to Exhibit 10.7.2 to EME's Form 10. 10.7.3 Amendment No. 3 to Power Purchase Contract between Southern California Edison Company and Chevron U.S.A. Inc., dated November 21, 1985, incorporated by reference to Exhibit 10.7.3 to EME's Form 10. 10.8 Power Purchase Contract between Southern California Edison Company and Arco Petroleum Products Company (Watson Refinery), incorporated by reference to Exhibit 10.8 to EME's Form 10. 10.9 Power Supply Agreement between State Electricity Commission of Victoria, Loy Yang B Power Station Pty. Ltd. and the Company Australia Pty. Ltd., as managing partner of the Latrobe Power Partnership, dated December 31, 1992, incorporated by reference to Exhibit 10.9 to EME's Form 10. 10.10 Power Purchase Agreement between P.T. Paiton Energy Company as Seller and Perusahaan Umum Listrik Negara as Buyer, dated February 12, 1994, incorporated by reference to Exhibit 10.10 to EME's Form 10. 10.11 Amended and Restated Power Purchase Contract between Southern California Energy Company and Midway-Sunset Cogeneration Company, dated May 5, 1988, incorporated by reference to Exhibit 10.11 to EME's Form 10. 81 EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.12 Parallel Generation Agreement between Kern River Cogeneration Company and Southern California Energy Company, dated January 6, 1984, incorporated by reference to Exhibit 10.12 to EME's Form 10. 10.13 Parallel Generation Agreement between Kern River Cogeneration (Sycamore Project) Company and Southern California Energy Company, dated December 18, 1984, incorporated by reference to Exhibit 10.13 to EME's Form 10. 10.14 Amendment No. 2 to Power Purchase Agreement between Southern California Energy Company and Vulcan/BN Geothermal Power Company, dated April 1, 1986, incorporated by reference to Exhibit 10.14 to EME's Form 10. 10.15 U.S. $325 million Bank of Montreal Revolver, dated October 29, 1993, incorporated by reference to Exhibit 10.15 to EME's Form 10. 10.15.1 U.S. $400 million Bank of America National Trust and Savings Association Credit Agreement, dated October 27, 1994, incorporated by reference to Exhibit 10.15.1 to EME's Form 10. 10.15.2 Conformed copy of the Amended and Restated U.S. $400 million Bank of America National Trust and Savings Association Credit Agreement, dated as of November 17, 1994, incorporated by reference to Exhibit 10.15.2 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.15.3 Conformed copy of the Second Amended and Restated U.S. $400 million Bank of America National Trust and Savings Association Credit Agreement, dated as of October 11, 1996, incorporated by reference to Exhibit 10.15.3 to EME's Annual Report on Form 10-K for the year ended December 31, 1996. 10.16 Amended and Restated Ground Lease Agreement between Texaco Refining and Marketing Inc. and March Point Cogeneration Company, dated August 21, 1992, incorporated by reference to Exhibit 10.16 to EME's Form 10. 10.16.1 Amendment No. 1 to Amended and Restated Ground Lease Agreement between Texaco Refining and Marketing Inc. and March Point Cogeneration Company, dated August 21, 1992, incorporated by reference to Exhibit 10.16 to EME's Form 10. 10.17 Memorandum of Agreement between Atlantic Richfield Company and Products Cogeneration Company, dated September 17, 1987, incorporated by reference to Exhibit 10.17 to EME's Form 10. 10.18 Memorandum of Ground Lease between Texaco Producing Inc. and Sycamore Cogeneration Company, dated January 19, 1987, incorporated by reference to Exhibit 10.18 to EME's Form 10. 10.19 Amended and Restated Memorandum of Ground Lease between Getty Oil Company and Kern River Cogeneration Company, dated November 14, 1984, incorporated by reference to Exhibit 10.19 to EME's Form 10. 10.20 Memorandum of Lease between Sun Operating Limited Partnership and Midway-Sunset Cogeneration Company, incorporated by reference to Exhibit 10.20 to EME's Form 10. 10.21 Executive Supplemental Benefit Program, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313). 10.22 1981 Deferred Compensation Agreement, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313). 10.23 1985 Deferred Compensation Agreement for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313). 10.24 1987 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K 82 EXHIBIT NO. DESCRIPTION - ----------- ----------- filed by SCEcorp (File No. 1-2313). 10.25 1988 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1- 2313). 10.26 1989 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1- 9936). 10.27 1990 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1- 9936). 10.28 Annual Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1- 9936). 10.29 Executive Retirement Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1- 2313). 10.30 Long-Term Incentive Plan for Executive Officers, incorporated by reference to the Registration Statement (File No. 33-19541) under which SCEcorp registered securities to be offered pursuant to the Plan under the Securities Act of 1933. 10.31 Estate and Financial Planning Program for Executive Officers, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936). 10.32 Letter Agreement with Edward R. Muller, incorporated by reference to Exhibit 10.32 to EME's Form 10. 10.33 Agreement with James S. Pignatelli, incorporated by reference to Exhibit 10.33 to EME's Form 10. 10.34 Conformed copy of the Guarantee Agreement dated as of November 30, 1994, incorporated by reference to Exhibit 10.34 to EME's Form 10. 10.35 Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated as of December 18, 1989, incorporated by reference to Exhibit 10.35 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.35.1 First Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated November 1, 1991, incorporated by reference to Exhibit 10.35.1 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.35.2 Second Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated June 3, 1994, incorporated by reference to Exhibit 10.35.2 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.35.3 Third Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated December 12, 1994, incorporated by reference to Exhibit 10.35.3 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.36 Conformed copy of A$200 million Bank of America National Trust and Savings Association Credit Agreement dated November 22, 1994, incorporated by reference to Exhibit 10.36 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.36.1 Conformed copy of the Amended and Restated A$200 million Bank of America National Trust and Savings Associated Credit Agreement dated December 12, 1994, incorporated by reference to Exhibit 10.36.1 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.36.2 Conformed copy of First Amendment to Amended and Restated A$200 million Bank of America National Trust and Savings Associated Credit Agreement dated June 7, 1995, incorporated by reference to Exhibit 10.36.2 to EME's Form 10-Q for the quarter ended September 30, 1995. 83 EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.37 Amended and Restated Limited Partnership Agreement of Mission Capital, L.P. dated as of November 30, 1994, incorporated by reference to Exhibit 10.37 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.38 Action of General Partner of Mission Capital, L.P. creating the 9- 7/8% Cumulative Monthly Income Preferred Securities, Series A, dated as of November 30, 1994, incorporated by reference to Exhibit 10.38 to EME's Annual Report on Form 10-K for the year ended December 31, 1994. 10.39 Action of General Partner of Mission Capital, L.P. creating the 8- 1/2% Cumulative Monthly Income Preferred Securities, Series B, dated as of August 8, 1995, incorporated by reference to Exhibit 10.39 to EME's Form 10-Q for the quarter ended June 30, 1995. 10.40 Power Purchase Contract between ISAB Energy, S.r.l. as Seller and Enel, S.p.A. as Buyer, dated June 9, 1995, incorporated by reference to Exhibit 10.40 to EME's Form 10-Q for the quarter ended June 30, 1995. 10.41 400 million sterling pounds Barclays Bank Plc Credit Agreement, dated December 18, 1995, incorporated by reference to Exhibit 10.41 to EME's Current Report on Form 8-K, No. 1-13434. 10.42 Guarantee by EME dated December 1, 1995 supporting Letter of Credit issued by Bank of America National Trust and Savings Association to secure payment of bonds issued pursuant to the Brooklyn Navy Yard project tax-exempt bond financing, incorporated by reference to Exhibit 10.42 to EME's Annual Report on Form 10-K for the year ended December 31, 1995. 10.43 Guarantee by EME dated December 1, 1995 supporting Letter of Credit issued by Bank of America National Trust and Savings Association to secure Brooklyn Navy Yard's indemnity to the New York City Industrial Development Agency pursuant to the Brooklyn Navy Yard project tax-exempt bond financing, incorporated by reference to Exhibit 10.43 to EME's Annual Report on Form 10-K for the year ended December 31, 1995. 10.44 Guarantee by EME dated December 20, 1996 in favor of The Fuji Bank, Limited, Los Angeles Agency, to secure Camino Energy Company's payments pursuant to Camino Energy Company's Credit Agreement and Defeasance Agreement, incorporated by reference to Exhibit 10.44 to EME's Annual Report on Form 10-K for the year ended December 31, 1996. 10.45 Power Purchase Agreement between National Power Corporation and San Pascual Cogeneration Company International B.V., dated September 10, 1997.* 10.46 Power Purchase Agreement between Gulf Power Generation Co., LTD., and Electricity Generating Authority of Thailand, dated December 22, 1997.* 21 List of Subsidiaries.* 27 Financial Data Schedule.* *Filed herewith (b) REPORTS ON FORM 8-K No reports on Form 8-K were filed during the fourth quarter of 1997. (c) EXHIBITS 84 The Exhibits filed with this report are listed in Item 14(a)(3) above. (d) FINANCIAL STATEMENT SCHEDULES The financial statement schedules filed with this report are listed in Section 14(a)(2) above. Financial information for the Cogeneration Group for the years ended December 31, 1997, 1996 and 1995. The financial statements of the Cogeneration Group present the combination of those entities that are 50% or less owned by EME and that met the requirements of Rule 3-09 of Regulation S-X in 1995. There were no entities which were 50% or less owned by EME that met the requirements of Rule 3-09 of Regulation S-X in 1997 and 1996. 85 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Edison Mission Energy: We have audited the accompanying combined statements of income, partners' equity and cash flows of Kern River Cogeneration Company (a general partnership between Getty Energy Company and Southern Sierra Energy Company), Sycamore Cogeneration Company (a general partnership between Texaco Cogeneration Company and Western Sierra Energy Company) and Watson Cogeneration Company (a general partnership between Camino Energy Company and Products Cogeneration Company), (collectively the Cogeneration Group) for the year ended December 31, 1995. These financial statements are the responsibility of the Group's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the combined financial statements referred to above present fairly, in all material respects, the results of the Cogeneration Group's operations and cash flows for the year ended December 31, 1995, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Los Angeles, California March 15, 1996 86 THE COGENERATION GROUP COMBINED STATEMENTS OF INCOME (IN THOUSANDS)
YEARS ENDED DECEMBER 31, ------------------------------------- 1997 1996 1995 ---------- -------- --------- (Unaudited) (Unaudited) OPERATING REVENUES Sales of energy to SCE $402,839 $347,537 $318,964 Sales of energy to TEPI 11,715 9,406 8,405 Sales of energy to ARCO Products 26,423 23,631 19,249 Sales of steam to TEPI 89,682 72,038 64,150 Sales of steam to ARCO Products 48,216 43,121 35,018 -------- -------- -------- Total operating revenues 578,875 495,733 445,786 -------- -------- -------- OPERATING EXPENSES Fuel 294,277 234,509 181,219 Plant operations 53,377 56,662 62,657 Depreciation and amortization 24,194 24,151 24,661 Administrative and general 8,014 5,733 6,824 -------- -------- -------- Total operating expenses 379,862 321,055 275,361 -------- -------- -------- Income from operations 199,013 174,678 170,425 -------- -------- -------- OTHER INCOME (EXPENSE) Interest and other income 5,041 2,031 2,706 Interest expense (4,197) (5,673) (9,454) -------- -------- -------- Total other income (expense) 844 (3,642) (6,748) -------- -------- -------- NET INCOME $199,857 $171,036 $163,677 ======== ======== ========
The accompanying notes are an integral part of these combined financial statements. 87 THE COGENERATION GROUP COMBINED BALANCE SHEETS (IN THOUSANDS)
(UNAUDITED) DECEMBER 31, ------------------------ 1997 1996 ---------- ---------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 36,305 $ 48,334 Trade receivables - affiliates 62,800 57,051 Other receivables 603 825 Inventories 15,327 16,632 Prepaid expenses and other assets 2,963 3,009 -------- -------- Total current assets 117,998 125,851 -------- -------- PROPERTY, PLANT AND EQUIPMENT 672,082 652,534 Less accumulated depreciation and amortization 257,436 236,517 -------- -------- Net property, plant and equipment 414,646 416,017 -------- -------- OTHER ASSETS Emission credits, net 17,488 19,584 Intangible assets, net 22,822 23,950 Other 168 890 -------- -------- Total other assets 40,478 44,424 -------- -------- TOTAL ASSETS $573,122 $586,292 ======== ========
The accompanying notes are an integral part of these combined financial statements. 88 THE COGENERATION GROUP COMBINED BALANCE SHEETS (IN THOUSANDS)
(UNAUDITED) DECEMBER 31, ------------------------- 1997 1996 ---------- ---------- LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Accounts payable - affiliates $ 47,410 $ 46,680 Accounts payable and accrued liabilities 20,680 32,077 Current maturities of loans payable 13,404 13,404 -------- -------- Total current liabilities 81,494 92,161 -------- -------- LOANS PAYABLE, net of current maturities 55,966 69,370 -------- -------- MAINTENANCE ACCRUAL 10,505 9,160 -------- -------- Total liabilities 147,965 170,691 -------- -------- COMMITMENTS AND CONTINGENCIES (Note 7) PARTNERS' EQUITY 425,157 415,601 -------- -------- TOTAL LIABILITIES AND PARTNERS' EQUITY $573,122 $586,292 ======== ========
The accompanying notes are an integral part of these combined financial statements. 89 THE COGENERATION GROUP COMBINED STATEMENTS OF PARTNERS' EQUITY (IN THOUSANDS)
EME Texaco ARCO Total Affiliates Affiliates Affiliates Equity ---------- ----------- ---------- ------ Balances at December 31, 1994 $196,456 $ 94,129 $106,503 $ 397,088 Cash distributions (79,550) (42,800) (38,250) (160,600) Net income 81,182 49,010 33,485 163,677 -------- -------- -------- --------- Balances at December 31, 1995 198,088 100,339 101,738 400,165 Cash distributions (Unaudited) (77,060) (40,800) (37,740) (155,600) Net income (Unaudited) 84,865 52,845 33,326 171,036 -------- -------- -------- --------- Balances at December 31, 1996 (Unaudited) 205,893 112,384 97,324 415,601 Cash distributions (Unaudited) (94,326) (53,900) (42,075) (190,301) Net Income (Unaudited) 99,139 60,466 40,252 199,857 -------- -------- -------- --------- Balances at December 31, 1997 (Unaudited) $210,706 $118,950 $ 95,501 $ 425,157 ======== ======== ======== =========
The accompanying notes are an integral part of these combined financial statements. 90 THE COGENERATION GROUP COMBINED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEARS ENDED DECEMBER 31, ---------------------------------------- 1997 1996 1995 ---------- ---------- ---------- (Unaudited) (Unaudited) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 199,857 $ 171,036 $ 163,677 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 24,194 24,151 24,661 (Increase) decrease in receivables (5,527) (7,180) 5,595 Decrease (increase) in inventories 1,305 1,177 (1,519) (Decrease) increase in payables (5,572) 27,800 (1,053) (Decrease) increase in maintenance accrual (3,750) 3,673 5,456 Other, net 47 (1,630) (411) --------- --------- --------- Net cash provided by operating activities 210,554 219,027 196,406 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (19,548) (11,512) (7,386) --------- --------- --------- Net cash used in investing activities (19,548) (11,512) (7,386) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from escrow account 670 1,534 1,488 Loan repayments (13,404) (24,951) (25,100) Distribution to partners (190,301) (155,600) (160,600) --------- --------- --------- Net cash used in financing activities (203,035) (179,017) (184,212) --------- --------- --------- NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (12,029) 28,498 4,808 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 48,334 19,836 15,028 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 36,305 $ 48,334 $ 19,836 ========= ========= ========= SUPPLEMENTAL CASH FLOW INFORMATION Interest paid $ 4,257 $ 5,997 $ 9,553 ========= ========= ========= SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES Additions to property, plant and equipment received in settlement of certain receivables $ -- $ -- $ 778 ========= ========= =========
The accompanying notes are an integral part of these combined financial statements. 91 THE COGENERATION GROUP NOTES TO COMBINED FINANCIAL STATEMENTS DECEMBER 31, 1997 (UNAUDITED), 1996 (UNAUDITED) AND 1995 NOTE 1. GENERAL - ---------------- Principles of Combination Edison Mission Energy (EME), a wholly owned subsidiary of The Mission Group, a wholly owned non-utility subsidiary of Edison International, the parent holding company of Southern California Edison Company (SCE), has a general partnership interest in Kern River Cogeneration Company (Kern River), Sycamore Cogeneration Company (Sycamore) and Watson Cogeneration Company (Watson) (jointly referred to herein as the Group). SSEC, WSEC and CEC (as defined below) are separate legal entities from EME. The accompanying combined financial statements have been prepared for purposes of EME complying with certain requirements of the Securities and Exchange Commission. Kern River is a general partnership between Getty Energy Company (GEC), a wholly owned subsidiary of Texaco Inc. (Texaco), and Southern Sierra Energy Company (SSEC), a wholly owned subsidiary of EME. Kern River owns and operates a 300-MW natural gas-fired cogeneration facility located near Bakersfield, California, which sells electricity to SCE and which sells electricity and steam to Texaco Exploration and Production Inc. (TEPI), a wholly owned subsidiary of Texaco, for use in TEPI's enhanced oil recovery operations in the Kern River Oil Field. Partnership income (loss) is allocated equally to the partners. Sycamore is a general partnership between Texaco Cogeneration Company (TCC), a wholly owned subsidiary of Texaco, and Western Sierra Energy Company (WSEC), a wholly owned subsidiary of EME. Sycamore owns and operates a 300-MW natural gas-fired cogeneration facility located near Bakersfield, California, which sells electricity to SCE and which sells steam to TEPI for use in TEPI's enhanced oil recovery operations in the Kern River Oil Field. Partnership income (loss) is allocated equally to the partners. Watson is a general partnership between Carson Cogeneration Company (CCC), a wholly owned subsidiary of CH-Twenty, Inc., a majority owned subsidiary of Atlantic Richfield Company (ARCO), Products Cogeneration Company (PCC), a wholly owned subsidiary of ARCO and Camino Energy Company (CEC), a wholly owned subsidiary of EME. CCC, PCC and CEC own 49 percent, 2 percent and 49 percent, respectively. Watson owns and operates a 385-MW natural gas-fired cogeneration facility located in Carson, California, which sells electricity to SCE and which sells electricity and steam to ARCO Products Company (ARCO Products) for use at ARCO Products' refinery. Partnership income (loss) is allocated based upon the partners' respective ownership percentage. NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - --------------------------------------------------- Basis of Presentation 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 92 reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Inventories Inventories are comprised of materials and supplies, and are stated at their lower of average cost or market. Property, Plant and Equipment All costs, including interest and field overhead expenses, incurred during construction and the precommission phase of the facilities were capitalized as part of the cost of the facilities. Revenue earned during the precommission phase was offset against the costs of the facilities. The facilities and related equipment are being depreciated on a straight-line basis over approximately 30 years, which is the estimated useful lives of the facilities. Emission Credits Two of the Group's facilities were required to obtain assignments of emission offset credits in order to be certified by the California Energy Commission. These credits were required to meet the current environmental regulations as they relate to the emissions being produced from the operation of these facilities. The cost of these emission credits are stated net of accumulated amortization of $23.2 million and $21.1 million at December 31, 1997 and 1996, respectively (see Note 5). The emission credits are being amortized on a straight-line basis over 21 years. Intangible Assets Intangible assets are stated net of accumulated amortization of $13 million and $11.9 million at December 31, 1997 and 1996, respectively, and consist of outside boundary limit facilities, refinery infrastructure, environment permits and land use, as outlined in the various partnership agreements, contributed to the Group. All of the intangible assets relate to the operations of the various facilities, and as a result, are being amortized on a straight-line basis over the estimated useful life of the facilities. Statements of Cash Flows For purposes of reporting cash flows, the Group considers short-term temporary cash investments with an original maturity of three months or less to be cash equivalents. Maintenance Accruals The Group performs scheduled inspections and major overhauls periodically over the life of their combustion turbines. Generally, expenses for these events are accrued for on a straight-line basis over the expected operating-hour interval between each like maintenance event. Expenditures for minor maintenance, repairs and renewals are charged to expense as incurred. Expenditures for additions and improvements are capitalized. The accruals for repair and maintenance events are based on management's estimates of what these events will cost at the time the events occur. Due to fluctuations in prices and changes in the timing of the scheduled events, the estimated costs of these events can differ from actual costs incurred. 93 Fair Value of Financial Instruments The carrying amount of the short-term investments approximates fair value due to the short maturities of such investments. The estimated fair value of loans payable is discussed in Note 4. Reclassifications Certain prior year amounts have been reclassified to conform with current year presentation. NOTE 3. PROPERTY, PLANT AND EQUIPMENT - -------------------------------------- Plant and equipment consist of the following:
(Unaudited) December 31, ----------------- 1997 1996 ------ ------ (in millions) Plant and equipment Power plant facilities $649.0 $644.8 Building, furniture and office equipment 23.0 7.7 ------ ------ 672.0 652.5 Less -- Accumulated depreciation and amortization 257.4 236.5 ------ ------ $414.6 $416.0 ====== ======
NOTE 4. LOANS PAYABLE - ----------------------
(Unaudited) December 31, ----------------- 1997 1996 ------ ------ (in millions) Watson project: Note payable to ARCO (5% at 12/31/97) (5% at 12/31/96) $ 27.4 $ 27.4 Note payable to CEC (5% at 12/31/97) (5% at 12/31/96) 26.3 26.3 Sycamore project: $165 million Loan and Credit Agreement due 1999 (Eurodollar rate + 0.625%) (6.4% at 12/31/97) (6.2% at 12/31/96) 15.7 29.1 ------ ------ Subtotal 69.4 82.8 Current maturities of loans payable (13.4) (13.4) ------ ------ Total $ 56.0 $ 69.4 ====== ======
The above agreement for the Sycamore project is secured by certain assets of Sycamore, and places certain restrictions on capital distributions. In addition, this agreement requires Sycamore to maintain escrow deposits based upon outstanding loan amounts. Based upon borrowing rates currently available to Sycamore for long-term debt with similar terms and maturity, the fair value of the amount outstanding under this agreement approximates the carrying value. 94 The fair value of the two Watson project notes was approximately $53 million at December 31, 1997 and 1996. In February 1996, the interest rates on the two Waston project notes were reduced to 5% and the maturity dates extended to April 2008. Annual maturities on the loans payable at December 31, 1997 are as follows (dollars in millions): YEAR ---- 1998 $13.4 1999 2.2 2000 -- 2001 -- 2002 -- Thereafter 53.8 ----- Total $69.4 ===== NOTE 5. RELATED-PARTY TRANSACTIONS/CONTRACTUAL OBLIGATIONS - ----------------------------------------------------------- Operating and Other Costs The amounts incurred by EME, Texaco and their respective affiliates for operating and other costs charged to the Group, which are not disclosed elsewhere, were as follows:
(in millions) 1997 1996 1995 ---- ---- ---- (unaudited) (unaudited) Texaco and affiliates $ 4.4 $ 4.6 $ 4.5 EME and affiliates 1.2 2.4 2.8
Emission Credits Certain affiliates of Texaco assigned their rights to certain emission offset credits to certain of the Group for a period of 21 years. These emission offset credits were earned by the Texaco affiliates by reducing specified emissions at other of their operations. Such credits are used by the Group to allow certain of the Group's facilities to operate under current environmental regulations. The credits were required by those facilities in order to be certified by the California Energy Commission and are required to be maintained throughout the period of operations of those facilities. The credits were reflected as a capital contribution by such entities at the fair market value of $40.8 million. Fuels Management Agreement Certain of the Group are party to agreements with Texaco Natural Gas, Inc. (TNGI), whereby TNGI is to procure and manage all fuel-gas supplies and transportation for two of the facilities (except fuel-gas supplies procured and delivered under tariff-gas contracts, provided under an excepted contract or otherwise excluded from these agreements by the mutual consent of the partners). The original termination date of the agreements with TNGI was December 31, 1995. TNGI received a fixed service fee of $.0075 per MMBtu of fuel gas supplied to certain of the Group, and a variable 95 incentive fee based on the utility fuel cost applicable to such Group. The agreements include a minimum annual fee of $.015 per MMBtu of fuel gas utilized if the total of the fixed service fee and variable incentive fee is less than the minimum annual fee. The amounts incurred under these agreements were $118.5 million, which included fees earned by TNGI of $3.7 million, for the year ended December 31, 1995. As of January 1, 1996, the Amended and Restated Fuel Management Agreement, terminating on October 1, 2002, was entered into such that TNGI will receive a fixed service fee of $.0375 per MMBtu of fuel gas supplied to certain of the Group. The amounts incurred under the amended agreements were $183.5 million and $147.7 million which included fees earned by TNGI of $0.4 million and $2.6 million, for the two years ended December 31, 1997. One of the Group has entered into a fuel (refinery gas and butane) purchase agreement with a subsidiary of ARCO. Such Group's purchases under this agreement amounted to $40.9 million, $38.4 million and $24.2 million for the three years ended December 31, 1997, 1996 and 1995, respectively. Operation and Maintenance Agreement Two of the Group have agreements with Edison Mission Operation & Maintenance, Inc. (EMOM), a wholly owned subsidiary of EME, whereby EMOM shall perform all operation and maintenance activities necessary for the production of electricity and steam by such Group facilities. The agreements will continue until terminated by either party. EMOM is paid for all costs incurred in connection with operating and maintaining the facility. EMOM may also earn incentive compensation as set forth in the agreements. The amounts incurred by the Group under these agreements were $6.3 million, $6 million and $6.2 million which included incentive compensation earned by EMOM of $0.9 million for each of the three years ended December 31, 1997, 1996 and 1995, respectively. One of the Group has an agreement with a subsidiary of ARCO, whereby such subsidiary shall perform all operation and maintenance activities necessary for the production of electricity and steam by such Group's facility. The agreement will continue until termination of the Power Purchase Agreement in April 2008. The ARCO subsidiary is reimbursed for all costs incurred in connection with operating and maintaining the facility. The amounts incurred under this agreement were $5 million, $4.9 million and $5.4 million for the three years ended December 31, 1997, 1996 and 1995, respectively. Additionally, ARCO provides other ancillary services under a service contract for a fee. Total service fees earned by ARCO were $1.4 million, $1.3 million and $1.3 million for the three years ended December 31, 1997, 1996 and 1995, respectively. Steam Purchase and Sale Agreements Certain of the Group have agreements with TEPI for the sale of steam generated by such Group's facilities. The agreements terminate 20 years from the date of the first sale of steam thereunder. TEPI pays such Group a steam fuel charge based upon the quantity and quality of steam delivered during the month, which is priced at the lesser of the current Southern California Gas Company Border Gas Price, or the weighted average posted price of Kern River Crude, less any severance, excise or windfall profit taxes, and a processing charge per MMBtu as defined in the agreements. The quantity of steam sold under this contract is expected to be sufficient for such Group to maintain qualifying facility status. Total sales of steam under these agreements amounted to approximately $89.7 million, $72 million and $64.2 million for the three years ended December 31, 1997, 1996 and 1995, respectively. 96 These agreements have been amended whereby such Group will reduce a portion of steam prices beginning in 1999 and to a limited extent in 1997. The amount of future reductions in annual revenues could total approximately $25 million. Additionally, one of the Group has contracted to sell steam and power generated by its facility to the ARCO subsidiary's Los Angeles refinery under separate agreements. Total sales under these contracts amounted to approximately $74.6 million, $66.8 million and $54.3 million for the three years ended December 31, 1997, 1996 and 1995, respectively. Power Purchase Agreements One of the Group has an agreement with TEPI for the sale of contract capacity and net energy. This agreement will remain in effect until August 8, 2005. The amounts paid for the contract capacity and net energy are based on the same terms as provided for in the agreements with SCE (discussed below). Total sales of power under the agreement with TEPI amounted to approximately $11.7 million, $9.4 million and $8.4 million for the three years ended December 31, 1997, 1996 and 1995, respectively. The Group has agreements with SCE for the sale of contract capacity and net energy generated by the facilities. These agreements will remain in effect 20 years from the Firm Operation Date of the relevant facility. SCE pays the Group for energy based upon the price of SCE's Avoided Fuel Cost, the quantity of kilowatts delivered, the contracted heat rate allocated to on-peak, mid-peak and off-peak hours and a factor as defined in the agreements to account for system line loss at the point of delivery. SCE also pays the Group for firm capacity based upon a contracted amount per kilowatt year. Total sales of energy under these agreements amounted to $402.8 million, $347.5 million and $319 million for the three years ended December 31, 1997, 1996 and 1995, respectively. As discussed above, the electric power generated by the Group is primarily sold to SCE pursuant to long-term power sales contracts. When negotiating power sales contracts, EME negotiates contracts which are expected to result in consistent cash flow under a wide range of economic and operating circumstances. To accomplish this end, EME structures its long-term contracts so that fluctuations in fuel costs will produce similar fluctuations in electric revenues and by entering into long-term fuel supply and transportation agreements. In addition, the operation of the facilities involves many risks including the breakdown or failure of equipment or processes, performance below expected levels of output, interruptions in fuel supply, pipeline disruptions, disruptions in the supply of electrical energy, violation of permit requirements, operator error, the inability to meet expected efficiency standards and catastrophic events. The occurrence of any of these events could result in extended unavailability under the power sales contracts which may entitle the purchaser thereunder to terminate the relevant power sales contracts. Natural Gas Supply and Transportation Agreements The Group purchases gas on the spot market. As such, the Group may be exposed, in the short-term, to fluctuations in the price of natural gas. Fluctuations in the prices paid for gas are implicitly tied to the revenues received for either power or steam under the agreements. 97 NOTE 6. INCOME TAXES - --------------------- Income taxes are not recorded by the Group because the net income or loss allocated to the partners is included in their respective income tax returns. NOTE 7. COMMITMENTS AND CONTINGENCIES - -------------------------------------- Future Obligations Pursuant to amendments made in 1990 to the Federal Clean Air Act and the California Clean Air Act, the Group is required to reduce its nitrogen oxide (NOx) emissions. To fulfill these requirements one of the Group retrofitted its combustion turbines to employ a Dry-Lo NOx (DLN) technology. One of the Group is scheduled to complete the retrofit of its combustion turbines to coincide with maintenance overhauls scheduled through 1999. Such Group's management estimates the future obligations of these DLN conversions will be $22.4 million. The Group will capitalize $11.6 million of these costs related to the DLN conversions. It is further anticipated that operating cash flows will be used to fund the DLN conversions. Ship-or-Pay Pursuant to the Master Agreement, entered into as of December 1, 1994, certain of the Group executed a Security of Supply Agreement with an affiliated partnership of EME and Texaco. Such Group has agreed to accept and underwrite, on a pro-rata basis, a portion of Texaco's commitment pursuant to the transportation agreement (the Transportation Agreement) between Texaco, the Mojave Pipeline Company (Mojave) and the El Paso Pipeline Company (El Paso), dated February 15, 1989 and extending through March 31, 2008. The Company has agreed that Mojave and El Paso shall be the exclusive means of delivery for certain of the Group of the lesser of 75% of the annual total natural gas fuel requirements for such Group and 52,012,500 MMBtu per year. Except upon the occurrence of certain permissible events, two of the Group are subject to certain terms and conditions, whereby failure to transport the required quantity of natural gas on the Mojave Pipeline will result in the Group paying $0.63 per deficit MMBtu. Such Group will share any ship-or-pay liabilities on a pro-rata basis (as defined in the Transportation Agreement) with the affiliated partnership. For each of the years in the three-year period ended December 31, 1997, the transportation quantities required under the Transportation Agreement were met. It is the opinion of the relevant Group's management that these commitments will continue to be met based upon current projections for the operations of such Group's facilities. 98 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. EDISON MISSION ENERGY (Registrant) By: /s/ James V. Iaco, Jr. --------------------------------------------------------------------- JAMES V. IACO, JR., SENIOR VICE PRESIDENT and CHIEF FINANCIAL OFFICER Date: March 30, 1998 -------------------------------------------------------------------------- Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ---- Principle Executive Officer: /s/ Edward R. Muller President and Chief Executive Officer March 30, 1998 Controller or Principal Accounting Officer: /s/ Thomas E. Legro Vice President and Controller March 30, 1998 Majority of Board of Directors: /s/ Alan J. Fohrer Chairman of the Board March 30, 1998 /s/ Robert M. Edgell Director March 30, 1998 /s/ Bryant C. Danner Director March 30, 1998
99 EX-10.45 2 POWER PURCHASE AGREEMENT BETWEEN "SPCC" & "NPC" EXHIBIT 10.45 ================================================================================ POWER PURCHASE AGREEMENT between National Power Corporation and San Pascual Cogeneration Company International B.V. SAN PASCUAL COGENERATION POWER PRODUCTION FACILITY PROJECT September 10, 1997 ================================================================================ TABLE OF CONTENTS -----------------
Page No. RECITALS........................................................... 1 ARTICLE 1 - DEFINITIONS AND INTERPRETATION......................... 2 1.1 DEFINITIONS............................................ 2 ----------- 1.2 HEADINGS............................................... 9 -------- 1.3 INTERPRETATION......................................... 9 -------------- 1.4 ABBREVIATIONS.......................................... 10 ------------- ARTICLE 2. - SCOPE OF AGREEMENT.................................... 11 2.1 THE COGENERATION POWER PRODUCTION FACILITY............. 11 ------------------------------------------ 2.2 CONSTRUCTION........................................... 11 ------------ 2.3 COST OF CONSTRUCTION................................... 11 -------------------- 2.4 THE SITE............................................... 11 -------- 2.5 CONSENTS............................................... 11 -------- 2.6 SUPPLY OF ELECTRICITY.................................. 11 --------------------- 2.7 TRANSMISSION LINE...................................... 12 ----------------- 2.8 OPERATION.............................................. 13 --------- 2.9 POWER AND ENERGY....................................... 13 ---------------- 2.10 STEAM.................................................. 13 ----- 2.11 COSTS OF NPC........................................... 13 ------------ 2.12 OWNERSHIP OF COGENERATION POWER PRODUCTION FACILITY.... 13 --------------------------------------------------- 2.13 CERTAIN RESPONSIBILITIES OF SPCC....................... 14 -------------------------------- 2.14 CERTAIN RESPONSIBILITIES OF NPC........................ 14 ------------------------------- 2.15 MUTUAL COOPERATION..................................... 14 ------------------ 2.16 FUEL SUPPLY............................................ 15 ----------- ARTICLE 3 - CONSTRUCTION........................................... 15 3.1 PROJECT MILESTONE DATES................................ 15 ----------------------- 3.2 DELAY IN ACHIEVING MILESTONE........................... 17 ---------------------------- 3.3 SPCC'S RIGHTS.......................................... 17 ------------- 3.4 LOCAL CONTRACTS........................................ 17 --------------- 3.5 MONITOR PROGRESS....................................... 18 ---------------- 3.6 DISCLAIMER............................................. 19 ---------- 3.7 CONSULTATION........................................... 19 ------------ 3.8 DRAWINGS AND TECHNICAL DETAILS......................... 19 ------------------------------ 3.9 CONFIDENTIALITY........................................ 20 --------------- 3.10 BOND................................................... 21 ---- ARTICLE 4 - TESTING................................................ 23 4.1 TESTING PROCEDURES..................................... 23 ------------------ 4.2 WITNESSING OF TESTS.................................... 24 ------------------- 4.3 GUARANTEE TEST......................................... 24 -------------- 4.4 PERFORMANCE TEST....................................... 25 ---------------- 4.5 COST OF TESTING AND PURCHASE OF ELECTRICITY............ 26 ------------------------------------------- 4.6 CERTIFICATION.......................................... 26 ------------- 4.7 DEEMED COMPLETION...................................... 26 ----------------- ARTICLE 5 - OPERATION OF THE COGENERATION POWER PRODUCTION FACILITY 27 5.1 SPCC'S RESPONSIBILITIES................................ 27 ----------------------- 5.2 DOWNTIME............................................... 28 -------- 5.3 AVAILABILITY........................................... 28 ------------
Page No. 5.4 OPERATION.............................................. 28 --------- 5.5 SPCC'S RIGHTS.......................................... 29 ------------- 5.6 NPC'S OBLIGATIONS...................................... 29 ----------------- 5.7 ENVIRONMENTAL IMPACT................................... 29 -------------------- 5.8 SAFETY AND TECHNICAL GUIDELINES/ GRID CODE............. 29 ------------------------------------------ ARTICLE 6 - SALE OF ELECTRICITY.................................... 30 6.1 SUPPLY TO NPC.......................................... 30 ------------- 6.2 QUANTITY............................................... 30 -------- 6.3 DELIVERY............................................... 30 -------- 6.4 FEES................................................... 30 ---- 6.5 INVOICES............................................... 31 -------- 6.6 PAYMENT BY NPC......................................... 31 -------------- 6.7 NO SET-OFF............................................. 31 ---------- 6.8 DISPUTES............................................... 31 -------- 6.9 DOLLAR PAYMENTS........................................ 31 --------------- 6.10 COST OF PAYMENTS....................................... 31 ---------------- 6.11 PESO PAYMENTS.......................................... 32 ------------- 6.12 PAYMENTS TO NPC........................................ 32 --------------- 6.13 DOLLAR DEFICIENCY...................................... 32 ----------------- 6.14 CHANGE IN CIRCUMSTANCES................................ 32 ----------------------- 6.15 CONVERSION TO OTHER FUEL............................... 33 ------------------------ ARTICLE 7 - TERM AND TERMINATION................................... 34 7.1 TERM................................................... 34 ---- 7.2 TERMINATION BY NPC..................................... 34 ------------------ 7.3 TERMINATION BY SPCC.................................... 34 ------------------- 7.4 EXERCISE OF TERMINATION PAYMENT BY NPC................. 34 -------------------------------------- 7.5 PRE-COMPLETION TERMINATION AND PAYMENT................. 35 -------------------------------------- 7.6 POST-FACILITY COMPLETION TERMINATION AND PAYMENT....... 35 ------------------------------------------------ 7.7 DEDUCTIONS............................................. 36 ---------- ARTICLE 8 - REPRESENTATIONS, WARRANTIES AND COVENANTS OF SPCC...... 36 8.1 CORPORATE EXISTENCE.................................... 36 ------------------- 8.2 GOVERNMENT AUTHORIZATIONS.............................. 36 ------------------------- 8.3 COMPLIANCE WITH STANDARDS.............................. 36 ------------------------- 8.4 COMPLIANCE WITH LAWS................................... 36 -------------------- 8.5 SPCC'S WARRANTY AGAINST CORRUPTION..................... 36 ---------------------------------- ARTICLE 9 - REPRESENTATIONS, WARRANTIES AND COVENANTS OF NPC....... 37 9.1 CORPORATE EXISTENCE.................................... 37 ------------------- 9.2 GOVERNMENT AUTHORIZATIONS.............................. 37 ------------------------- ARTICLE 10- TAXES.................................................. 37 10.1 RESPONSIBILITY FOR TAXES............................... 37 ------------------------ 10.2 PAYMENT RESPONSIBILITIES............................... 38 ------------------------ 10.3 PAYMENTS FREE AND CLEAR................................ 38 ----------------------- 10.4 LATE PAYMENT........................................... 39 ------------ ARTICLE 11- INSURANCE.............................................. 39 11.1 INSURANCE.............................................. 39 --------- 11.2 ENDORSEMENTS........................................... 39 ------------ ARTICLE 12- TRANSMISSION LINE...................................... 39 12.1 OWNERSHIP AND RESPONSIBILITIES......................... 39 ------------------------------ 12.2 FAILURE TO TIMELY COMPLETE............................. 40 -------------------------- 12.3 TRANSFER OF OBLIGATION TO SPCC......................... 40 ------------------------------
Page No. ARTICLE 13 - FORCE MAJEURE......................................... 40 13.1 FORCE MAJEURE.......................................... 40 ------------- 13.2 EXCEPTIONS............................................. 42 ---------- 13.3 PROCEDURE.............................................. 42 --------- 13.4 CONSULTATION........................................... 43 ------------ 13.5 EXTENSION OF TIME...................................... 43 ----------------- ARTICLE 14 - EXPERT................................................ 43 14.1 APPLICATION OF ARTICLE................................. 43 ---------------------- 14.2 APPOINTMENT............................................ 43 ----------- 14.3 ELIGIBILITY............................................ 44 ----------- 14.4 PROCEDURES............................................. 44 ---------- ARTICLE 15 - SEVERAL OBLIGATIONS................................... 46 ARTICLE 16 - NOTICES............................................... 46 16.1 WRITING................................................ 46 ------- 16.2 ADDRESSES.............................................. 46 --------- ARTICLE 17 - WAIVER................................................ 47 ARTICLE 18 - BENEFIT OF AGREEMENT.................................. 47 18.1 ASSIGNMENT BY NPC...................................... 47 ----------------- 18.2 NPC PRIVATIZATION...................................... 47 ----------------- 18.3 ASSIGNMENT BY SPCC..................................... 47 ------------------ 18.4 SPCC PHILIPPINES....................................... 48 ---------------- 18.5 EFFECT OF ASSIGNMENT................................... 48 -------------------- ARTICLE 19 - DISPUTE RESOLUTION.................................... 48 19.1 REGULAR MEETINGS....................................... 48 ---------------- 19.2 AMICABLE SETTLEMENT.................................... 48 ------------------- ARTICLE 20 - ENTIRE AGREEMENT...................................... 49 ARTICLE 21 - GOVERNING LAW......................................... 49 ARTICLE 22 - DISCLAIMER............................................ 49 ARTICLE 23 - ARBITRATION........................................... 49 ARTICLE 24 - IMMUNITY.............................................. 50 ARTICLE 25 - EFFECT OF ARTICLE HEADINGS............................ 50 ARTICLE 26 - SEVERABILITY.......................................... 50 ARTICLE 27 - LIABILITY............................................. 50 27.1 LIMIT OF LIABILITY..................................... 50 ------------------ 27.2 NPC INDEMNITY.......................................... 51 ------------- 27.3 CROSS INDEMNITY........................................ 51 --------------- ARTICLE 28 - EFFECTIVE DATE AND CONDITIONS PRECEDENT 51 28.1 EFFECTIVE DATE......................................... 51 -------------- 28.2 CONDITIONS PRECEDENT................................... 53 -------------------- 28.3 TERMINATION FOR FAILURE TO OBTAIN CERTAIN GOVERNMENT ---------------------------------------------------- APPROVALS.............................................. 54 --------- ARTICLE 29 - COUNTERPART EXECUTION................................. 55
POWER PURCHASE AGREEMENT ------------------------ KNOW ALL MEN BY THESE PRESENTS This Power Purchase Agreement ("Agreement") is made and entered into the 10th day of September, 1997 by and between: SAN PASCUAL COGENERATION COMPANY INTERNATIONAL B.V. ("SPCC"), a private corporation duly organized and existing under the laws of the Netherlands with its principal address at 8/F 8750 Ayala Avenue, 1226 Makati City, Philippines, represented by its Managing Directors Martin D. Considine and Robert E. Driscoll who are duly authorized to represent it in this Agreement - and - The NATIONAL POWER CORPORATION ("NPC"), a government owned and controlled corporation duly organized and existing under and by virtue of Republic Act No. 6395, as amended, with its principal office at the corner of Agham Road and Quezon Avenue, Diliman, Quezon City, Philippines, represented herein by its President, Guido Alfredo A. Delgado, who is duly authorized to represent it in this Agreement. RECITALS WHEREAS, NPC has called for the development of new power facilities to support and maintain the Philippines' economic growth; WHEREAS, On July 27, 1993, the Department of Energy of the Republic of the Philippines issued a Certificate of Conditional Accreditation to SPCC's Cogeneration Project as a Private Sector Generation Facility ("PSGF") pursuant to Article 12, paragraphs c.1 and c.3 of Republic Act No. 7638 and Executive Order No. 215, which Certificate of Accreditation was renewed on December 28, 1994 and March 6, 1995, and was subsequently extended on the following dates: March 7, 1996, March 7, 1997, and most recently on March 19, 1997, which last extension is valid up to December 1, 1997 and will be replaced by a final Certificate of Accreditation to be obtained by SPCC after this Agreement has been signed; WHEREAS, pursuant to the conditions of the Certificate of Conditional Accreditation, SPCC submitted a Project proposal for a Cogeneration Plant to NPC; WHEREAS, NPC, after having evaluated the Project proposal and accepting the same, submitted the proposal to the National Economic and Development Authority (NEDA) for approval; WHEREAS, on August 5, 1997, the NEDA Board approved the Project; WHEREAS, NPC has issued to the public a notice inviting interested parties to offer a competing proposal (Price Test) for the Project; WHEREAS, NPC, having received no competing proposals during the price test and after NPC Board and NEDA/ICC Board approval, issued a letter of award to SPCC on August 21, 1997; WHEREAS, pursuant to NPC's acceptance of the Project proposal and NEDA's approval of the Project, SPCC has agreed to build, operate and own the Cogeneration Power Production Facility and NPC has agreed to accept electricity generated by the Cogeneration Power Production Facility upon the terms and subject to the conditions hereinafter set forth; WHEREAS, the proponents of the Project are Texaco Inc. and Edison Mission Energy; WHEREAS, SPCC has caused or will cause the formation of a Philippine entity known or to be known as the San Pascual Cogeneration Company Philippines Limited duly organized and existing under the laws of the Republic of the Philippines with its principal address at 6750 Ayala Avenue 8F, Makati, Metro Manila for the purpose of undertaking certain work in respect of the building and operating the Cogeneration Power Production Facility as defined herein. NOW IT IS HEREBY AGREED as follows: ARTICLE 1 - DEFINITIONS AND INTERPRETATION 1.1 DEFINITIONS. In this Agreement and the Recitals hereto and when used with ------------ capital initial letters: "Abandon", "Abandoned", and "Abandonment" shall have the meaning ascribed thereto in Article 3.10(d); "Accession Undertaking" means an agreement substantially in the form set out in the Twelfth Schedule (Form of Accession Undertaking) pursuant to which SPCC Philippines agrees to become a party hereto as therein provided; "Affiliate" means, in respect of a Party, any person which controls (directly or indirectly) that Party and any other person controlled (directly or indirectly) by such first mentioned person, including, where the Party is a company, the ultimate holding company of such Party and any subsidiary (direct or indirect) of such holding company; "Agreed Interest Rate" means, in respect of Dollars, the overnight United States Federal Funds rate plus two percentage points per annum and, in respect of Pesos, the T-Bill Rate plus two percentage points per annum, in each case compounded every thirty days; for the purposes of the foregoing, "T-Bill Rate" means, in respect of any day for which interest based on such rate is being calculated under this Agreement, the rate per annum at which Philippine Treasury Bills (with terms of thirty days or, if no such bill is issued, such bill which is issued having the term nearest to thirty days) issued by the Government of the Republic of the Philippines on the Monday immediately preceding such day or, if there were no Treasury Bills issued on such Monday, on the day immediately preceding such Monday on which Treasury Bills were issued; "Agreement" means this Power Purchase Agreement (PPA), and all schedules, attachments and exhibits, as amended from time to time by instrument in writing duly signed by or on behalf of the Parties; "Ambient Conditions" shall mean 32 degrees Centigrade ambient air temperature at ambient air pressure (1013 mbar), 85% relative humidity and 28 degrees Centigrade cooling water inlet temperature and 0.85 lagging power factor; "Ancillary Services" has the meaning ascribed to it in the Second Schedule; "Appointor" has the meaning ascribed to it in Article 14.2.3; "Availability" means, at any time and from time to time during the Cooperation Period, the capability of the Cogeneration Plant to generate electricity in accordance with this Agreement; "Available" means capable of generating electricity in accordance with this Agreement; "Availability Fees" means Capital Recovery Fees and Fixed Operating and Maintenance Fees; "Bangko Sentral ng Pilipinas" means the Bangko Sentral ng Pilipinas or any governmental authority which succeeds to the functions thereof; "Base Energy Rate" has the meaning ascribed to it in the Eighth Schedule; "Billing Period" means a period commencing immediately after the taking of a photograph of the electricity meters on the twenty-fifth day of a Calendar Month pursuant to the Seventh Schedule and ending upon the taking of such a photograph on the twenty-fifth day of the next Calendar Month; however, the first Billing Period shall commence on the taking of such a photograph as soon as practicable after the Commercial Operation Date and end on the next twenty-fifth day of a Calendar Month, and the last Billing Period shall end upon the taking of such a photograph on the last day of the Cooperation Period; "Black Start" means the capability of the Cogeneration Power Production Facility to start up and supply electricity to the NPC grid in accordance with this Agreement without the need to import from NPC electricity to the Cogeneration Power Production Facility; "BOI" means the Board of Investments of the Republic of the Philippines or any governmental authority which succeeds to the functions thereof; "Bond" means a confirmed standby letter of credit as mentioned in Article 3.10; "Business Day" shall mean any Day (other than Saturday or Sunday) on which banks are authorized to be open for business in Manila; "Calendar Month" means a month commencing on the first day of a month; "Calendar Year" means a year commencing on January 1; "Caltex" means Caltex (Philippines) Inc., and its successors or assignees; "Capital Recovery Fees" or "CRF" has the meaning ascribed to it in the Eighth Schedule (Delivery of Power and Energy); "Cocochem" means United Coconut Chemicals, Inc., and its successors or assignees; "Cogeneration Power Production Facility" means a combined cycle cogenerating plant and all other facilities built or to be built in respect thereof by SPCC to enable SPCC to fulfill its obligations under this Agreement, including the Switchyard Facilities; "Commercial Operation Date" means subject to the Cogeneration Power Production Facility having otherwise been built in accordance with this Agreement, the date on which SPCC and NPC jointly certify (NPC's certification not to be unreasonably withheld) that the Cogeneration Power Production Facility is capable of operating in accordance with the Operating Parameters set forth in the Second Schedule and has successfully completed the Guarantee Test in accordance with the Fourteenth Schedule, but not before the Target Commercial Operation Date; "Competent Authority" means: (a) the Departments of Energy, Environment and Natural Resources, Finance and Justice of the Government of the Republic of the Philippines, the National Electrification Administration, Energy Regulatory Board, National Economic and Development Authority, Board of Investments and Regional Development Council of the Republic of the Philippines, Bangko Sentral ng Pilipinas, Bureau of Internal Revenue, and the relevant Barangay, Municipal and Provincial Councils; and (b) the Government of the Republic of the Philippines or of any subdivision thereof and any other minister or governmental, quasi- governmental, electricity supply industry or other regulatory department, body, instrumentality, agency or authority of the Republic of the Philippines or of any subdivision thereof having jurisdiction over this Agreement, a Party or any asset or transaction mentioned in or contemplated by this Agreement; "Consent" means any permission, license, authority, approval, certification, registration, exemption or consent of any Competent Authority (including advice that there is no objection to a particular proposal or that a particular proposal is not inconsistent with the policy or guidelines of any Competent Authority) and, where a Competent Authority is authorized to prohibit a proposal, the passing of the time limited for such prohibition without the proposal being prohibited; "Contract Signing Date" means the date this Agreement is executed by the Parties; "Contract Year" means a period of one Year commencing on the first day of the Cooperation Period or any anniversary thereof; provided that the last Contract Year shall end upon termination of this Agreement; 4 "Contracted Capacity" or "CC" means 304 MW of total net generating capacity on a continuous and reliable basis, measured at the Delivery Point with all GTGs and the STG operating in a steady state condition at the Site, adjusted to Ambient Conditions while delivering steam to the Thermal Hosts; "Cooperation Period" means the period commencing on the Commercial Operation Date and ending on the date twenty-five (25) Years thereafter (unless earlier terminated pursuant to this Agreement); "Day" means calendar day, commencing at 12:00:01 a.m. Manila time, and ending at 12:00:00 a.m. Manila time; "Deemed Completion Date" has the meaning ascribed thereto in Article 4.7.1; "Delivery Point" means the metering point on the 230 kV side of the main transformer(s) referred to in the Seventh Schedule (Measurement and Recording of Electricity); "Emergency" means a failure in the continuous supply of electricity to the grid after the Commercial Operation Date which reasonably requires NPC to request SPCC to supply it with power as soon as possible; "Energy Fees" or "EF" has the meaning ascribed thereto in the Eighth Schedule; "Energy Report" means the reports submitted in accordance with the Eighth Schedule with the Department of Energy reporting energy input (fuel) to the Cogeneration Power Production Facility and energy outputs (steam, electricity) from the Cogeneration Power Production Facility; "Environmental Compliance Certificate" or "ECC" means the certification issued by the Department of Environment and Natural Resources of the Republic of the Philippines (or any governmental authority which succeeds to the functions thereof) for the Cogeneration Power Production Facility; "Expert" means a party appointed pursuant to Article 14 to resolve technical disputes related to the Project; "Financial Closing" has the meaning ascribed to it in Article 3.1.1.2; "Fixed Operating and Maintenance Fees" or "FOMF" has the meaning ascribed to it in the Eighth Schedule; "Force Majeure" has the meaning ascribed to it in Article 13.1; "Forced Outage" has the meaning ascribed to it in the Sixth Schedule (Electricity Delivery Procedures); "Foreign Component" means that portion of the Fixed Operating and Maintenance Fees and the Energy Fees, calculated on the basis of U.S. Indices; "Fuel" means Low Sulfur Waxy Residual Oil ("LSWR") or such other fuel as shall be agreed between NPC and SPCC used for running the Cogeneration Power 5 Production Facility which meets the Specifications set forth in the Fourth Schedule or such other specifications as shall be agreed between NPC and SPCC; "Fuel Fees" has the meaning ascribed to it in the Eighth Schedule (Delivery of Power and Energy); "Generating Assets" has the meaning ascribed to it in the First Schedule (Project Scope and Specifications), Article VI; "Good Operating Procedures" means the relevant practices, procedures and methods generally applied in or approved by the international electric power supply industry in the course of operating and maintaining private power generation systems that, at any particular time, in the exercise of reasonable judgment in the light of the facts which are known or which reasonably could have been known at the time a decision is made, would be expected to accomplish the desired result in a manner consistent with safety, Law, reliability, environmental protection, economy and expedition; Good Operating Procedures may evolve over time but generally modified procedures, practices and methods shall be applied only with prospective effect and as shall be appropriate for a power station of the age and condition of the Cogeneration Power Production Facility; "Government Force Majeure" has the meaning ascribed to it in Article 13; "Grid Code" means the embodiment of the rules governing the operation, maintenance and development of the power transmission network; "GTG" means Combustion Turbine Generator; "Guaranteed Heat Rate" or "GHR" means 7160 Btu/kWh, representing the fuel heat input required to generate a kWh (measured at the high voltage side of the main transformer) , upon which the Cogeneration Power Production Facility's Fuel Fees are calculated for MW capacities delivered equal to or greater than 200 MW, below which a different Guaranteed Heat Rate shall apply as provided for in the Eighth Schedule and the Ninth Schedule; "Guarantee Test" has the meaning ascribed to it in the Fourteenth Schedule; "Internationally Accepted Engineering Standards" means those practices, methods and acts set forth in the First Schedule (Project Scope and Specifications); "Industrial Rate" means the latest published schedule setting forth the energy and demand charge made by NPC to its industrial users adjusted from time to time in accordance with NPC's applicable automatic power cost adjustment factors; "Law" means all laws, ordinances, statutes, rules, orders, decrees, injunctions, international agreements and regulations of law in the Republic of the Philippines or any other Competent Authority, and any and all Consents; "Lender" means a bank, financial institution or other entity which provides loans or other financing to SPCC for the construction, operation and/or maintenance of the Cogeneration Power Production Facility under a Lending Agreement, and its successors or assigns; 6 "Lending Agreement" means a loan agreement, note, bond, indenture, security agreement, swap agreement or any other instrument relating to the financing or refinancing of the construction, operation and/or maintenance of the Cogeneration Power Production Facility; "Local Component" means that portion of the Fixed Operating and Maintenance Fees and Energy Fees calculated on the basis of Philippine Indices; "Milestone" means each of the activities listed in Article 3.1 hereof; "NEDA" means the National Economic and Development Authority of the Republic of the Philippines or any governmental authority which succeeds to the functions thereof; "Net Available Capacity" means the actual net generating capacity of the Cogeneration Power Production Facility (expressed in kW) measured at the Delivery Point when all GTG's and the STG are operating in a steady state condition at the Site adjusted to Ambient Conditions, demonstrated by the Performance Test nominated by SPCC in respect of a Contract Year or part thereof. This value shall be adjusted to account for capacity degradation due to site ambient conditions (temperature other than 32 degrees Centigrade) as per vendor furnished data and/or curves; "Operating Parameters" means the operating parameters of the Cogeneration Power Production Facility described in the Second Schedule (Operating Parameters); "Party" means either NPC or SPCC and "Parties" means both NPC and SPCC; "Performance Tests" has the meaning ascribed to it in the Fourteenth Schedule (Tests and Test Procedures); "Performance Undertaking" means the agreements substantially in the form set out in the Eleventh Schedule: Exhibit A (Agreement as to Fundamental Rights), Exhibit B (Guarantee of Project Agreements) and Exhibit C (Foreign Exchange Convertibility Agreement); "Philippine Indices" means the indices utilized in the calculation of the Adjustment Factor (P) pursuant to the Eighth Schedule (Delivery of Power and Energy); "Pioneer Status" means the status conferred by the Board of Investments of the Republic of the Philippines (or any governmental authority which succeeds to the functions thereof), evidenced by a Certificate of Registration in relation to the development, construction, operation and maintenance of the Cogeneration Power Production Facility confirming that SPCC is a registered pioneer enterprise under the Omnibus Investments Code of 1987; "Project" means the design, financing, construction, equipping, completion, testing, commissioning, operation and maintenance of the Cogeneration Power Production Facility and associated Switchyard Facilities at the Refinery, accredited by the Department of Energy of the Republic of the Philippines and 7 capable of delivering reliable electrical power to NPC and of delivering reliable steam to the Thermal Hosts; "Proponents" means the persons mentioned in the ninth Recital; "Proponents' Agreement" means the agreement between NPC and the Proponents substantially in the form set out in the Twenty-First Schedule; "Refinery" means the refinery owned by Caltex located in Batangas Province, the Republic of the Philippines as more fully described in the First Schedule (Project Scope and Specifications); "San Pascual Cogeneration Company International B.V." or "SPCC" means the Netherlands corporation formed by special purpose subsidiaries of Texaco Inc. and Edison Mission Energy for the purpose of developing and signing this Agreement; "San Pascual Cogeneration Company" or "SPCC Philippines" means the Philippine limited partnership formed by Batangas Energy Corporation, a wholly owned subsidiary of Caltex, and SPCC for the purpose of undertaking certain responsibilities in relation to the Project pursuant to the Twelfth Schedule; "Shareholders" means, with respect to SPCC, the shareholders in SPCC from time to time; and, with respect to SPCC Philippines, the partners in SPCC Philippines from time to time; "Site" means the site of the Cogeneration Power Production Facility as more particularly described in the First Schedule (Project Scope and Specifications); "Specifications" means the specifications of the Cogeneration Power Production Facility described in the First Schedule (Project Scope and Specifications); "Steam Assets" means the equipment primarily used in the generation of steam as more definitively stated in the First Schedule (Project Scope and Specifications) Article VII; "STG" means Steam Turbine Generator; "Switchyard Facilities" means those Facilities necessary to interconnect the Cogeneration Power Production Facility with NPC's grid including the switch yard, protective relays, protection control equipment, communications facilities and other related equipment as more fully described in the First Schedule; "Target Commercial Operation Date" means that date which is set forth in Article 3.1 as the same may be extended from time to time pursuant to this Agreement; "Target Transmission Line Completion Date" means the date which is forty (40) Calendar Months after the Contract Signing Date; "Test" means any test of the Cogeneration Power Production Facility (or any part thereof, wherever situated and whether or not then incorporated therein) required by the Fourteenth Schedule or otherwise by this Agreement, and, unless the 8 context otherwise requires, the test procedure, test documentation, criteria of satisfaction, procedures, standards, protective settings, duration and programme; "Thermal Efficiency Standards" means those standards set forth in SPCC's Department of Energy Certificate of Accreditation; "Thermal Hosts" shall mean Caltex, Cocochem, and any other entities purchasing steam from SPCC; "Transmission Line" means the transmission line and other related equipment described in the Fifth Schedule (Transmission Line Specifications); "Transmission Line Completion Date" means that date upon which the Transmission Line is capable of supplying start up power and allowing the Cogeneration Power Production Facility to operate in parallel to NPC's grid at its Contracted Capacity but not before the Target Transmission Line Completion Date unless the parties otherwise agree; "U.S. Indices" means the indices utilized in the calculation of the Adjustment Factor (US$) pursuant to the Eighth Schedule; and "Year" means a period of one year according to the Gregorian calendar commencing on any day of a year. 1.2 HEADINGS. As used herein, headings are for convenience and do not --------- form part of, and shall not affect the interpretation of, this Agreement. 1.3 INTERPRETATION. In this Agreement, unless the context otherwise --------------- requires: (a) the singular includes the plural and vice versa; (b) any gender includes the other; (c) reference to a statute, by-law, regulation, rule, delegated legislation or order is to the same as amended, modified or replaced from time to time and to any by-law, regulation, rule, delegated legislation or order made thereunder; (d) reference to a Consent is to the same as amended, modified or replaced from time to time, and to any proper order, instruction, requirement or decision of any Competent Authority thereunder; (e) reference to an agreement or instrument is to the same as amended, novated, modified or replaced from time to time; (f) reference to a Party is to a Party to this Agreement, its successors and permitted assigns; (g) reference to a Recital, Article, or Schedule is to a recital, article, or schedule of or to this Agreement; (h) reference to "above" or "below" is to the first occurrence above or below the reference; 9 (i) reference to a document or agreement in the "agreed form" is to a document or agreement in the form and terms agreed by the parties; (j) where a word or expression is defined, cognate words and expressions shall be construed accordingly; (k) "including" shall not be construed as being by way of limitation and "otherwise" shall not be construed as limited by words with which it is associated; (l) any reference to a governmental ministry, department, authority or agency shall be construed as being to any governmental ministry, department, authority, or agency which succeeds to the functions thereof; (m) the word "reasonable" appearing before "approval", "consent", "satisfaction" or any similar word shall mean that the approval, consent, expression of satisfaction or other decision to be made as to the particular matter or thing concerned shall not unreasonably be withheld or delayed. Conversely, if the word "reasonable" does not so appear, the approval, consent, expression of satisfaction or other decision to be made may be given or made solely at the unfettered discretion of the Party concerned; and (n) the expression "to the best of its knowledge" shall mean to the best of the knowledge and belief of the Party concerned, having made all due and reasonable inquiry. 1.4 ABBREVIATIONS. In this Agreement: -------------- (a) "US$" and "Dollar(s)" denote lawful currency of the United States of America; (b) "Ps", "PHP" and "Peso(s)" denote lawful currency of the Republic of the Philippines; (c) "MW" denotes a megawatt; (d) "kW" denotes a kilowatt; (e) "kWh" or "KWHR" denotes a kilowatt hour; (f) "kW-Month" denotes a kilowatt month; (g) "kV" denotes a kilovolt; (h) "kVA" denotes a Kilovolt-ampere; (i) "Btu" denotes a British Thermal Unit; and (j) "mmBtu" denotes a million British Thermal Units. 10 ARTICLE 2 - SCOPE OF AGREEMENT 2.1 THE COGENERATION POWER PRODUCTION FACILITY. SPCC shall cause and be ------------------------------------------ responsible for the financing, design, development, permitting, site survey, development and investigation, construction, completion, testing, commissioning, operation and maintenance of the Cogeneration Power Production Facility and Switchyard Facilities in accordance with the First (Project Scope and Specifications), Second (Operating Parameters), Sixth (Electricity Delivery Procedures), Fourteenth (Tests and Test Procedures) and Sixteenth (Environmental Criteria) Schedules and otherwise as provided in this Agreement at its cost, expense and risk (except as otherwise provided in this Agreement) and so that: (a) the Commercial Operation Date occurs on the Target Commercial Operation Date; (b) Contracted Capacity, Net Electrical Output and Ancillary Services are supplied to NPC at the Delivery Point during the Cooperation Period; and (c) Plant overall annual thermal efficiency is not less than 60%. Notwithstanding the foregoing, the only consequence to SPCC should the Net Available Capacity be less than the Contracted Capacity shall be the penalties calculated pursuant to the Eighth Schedule. 2.2 CONSTRUCTION. The Cogeneration Power Production Facility and Switchyard ------------ Facilities shall be constructed and equipped in accordance with the First Schedule (Project Scope and Specifications). 2.3 COST OF CONSTRUCTION. Except as otherwise set forth in this Agreement, all -------------------- costs of SPCC in the performance of its obligations in connection with the construction of the Cogeneration Power Production Facility as provided in Articles 2.1 and 2.2 shall be borne by SPCC. All necessary funding including any available preferential credits shall be arranged by and be the responsibility of SPCC. 2.4 THE SITE. Locating, acquiring and developing the Site shall be the -------- responsibility of, and for the account of SPCC. 2.5 CONSENTS. SPCC shall at all material times obtain, maintain and comply -------- with the terms of all Consents required to be obtained by it to fulfill its obligations under this Agreement. 2.6 SUPPLY OF ELECTRICITY. NPC shall, subject to relevant regulations, --------------------- endeavor to supply electricity to SPCC at such times and in such quantities as SPCC may from time to time reasonably request on reasonable notice to NPC and shall be paid for by SPCC at the Industrial Rate, or such substitute rate as shall be approved by the Energy Regulatory Board, for the purposes set forth below: 2.6.1 During Construction: SPCC shall be responsible to tie in to NPC's ------------------- grid system at the nearest source of supply to the Site; 11 2.6.2 During Start-up: At the Delivery Point specified in the Seventh --------------- Schedule for: (a) the no load test prior to the initial synchronization of the GTGs and/or the Cogeneration Power Production Facility; (b) testing and commissioning after initial synchronization up to the Commercial Operation Date; (c) the start up of each gas turbine and the Cogeneration Power Production Facility from time to time during the period from the Commercial Operation Date and throughout the Cooperation Period; 2.6.3 During and after Plant Outages: At the Delivery Point to operate ------------------------------ the Cogeneration Power Production Facility equipment necessary during outages and to re-start the Cogeneration Power Production Facility after such outages as requested by SPCC; 2.6.4 During the Cooperation Period: At the Delivery Point to supply the ------------------------------ general power requirements of the Cogeneration Power Production Facility (including electricity for housing, lighting, air conditioning and water supply), when the Cogeneration Power Production Facility is not operating; 2.6.5 Start-ups. --------- 2.6.5.1 Start-ups Following Certain Shutdowns: Notwithstanding the ------------------------------------- foregoing subsections of this Article 2.6, all electricity taken by SPCC for the GTG load test or GTG start-ups following a shutdown (a) pursuant to a dispatch order of NPC which is not the result of any failure of SPCC to comply with its obligations under this Agreement (whether or not as a result of Force Majeure) affecting NPC; or (b) as a result of any failure of NPC to comply with its obligations under this Agreement (except to the extent occasioned by Force Majeure, other than Government Force Majeure) but not pursuant to a dispatch order of NPC; shall be for the account of NPC. 2.6.5.2 Black Start Capability: The Cogeneration Power Production ---------------------- Facility shall have a Black Start capability; provided, however, that SPCC may from time to time, in its discretion, utilize power from the Thermal Hosts to start up the Cogeneration Power Production Facility instead of relying on its internal Black Start capability. 2.7 TRANSMISSION LINE. NPC shall construct the Transmission Line in accordance ------------------ with the Fifth Schedule and otherwise as required by this Agreement to interconnect the Cogeneration Power Production Facility to NPC grid system at its cost, expense and risk (except as otherwise set forth in this Agreement) so that the Transmission Line Completion Date occurs not later than the Target Transmission Line Completion Date. 12 2.8 OPERATION. As more fully set forth in Article 5, SPCC shall, at its cost, ---------- expense and risk (except as otherwise required by this Agreement), operate the Cogeneration Power Production Facility during the Cooperation Period within the Operating Parameters set out in the Second Schedule (Operating Parameters) and in accordance with Good Operating Procedures, and the dispatch instructions of NPC properly given according to the Sixth Schedule. NPC shall have the right, subject to the conditions set forth in the Sixth Schedule, to dispatch the Cogeneration Power Production Facility to an output of 90 MW. Notwithstanding anything to the contrary set forth in this Agreement, to the extent that the Cogeneration Power Production Facility is operating at a reduced output pursuant to NPC's dispatch instructions below 200 MW, SPCC shall be entitled to operate the Cogeneration Power Production Facility at less than 60% thermal efficiency, and shall not be subject to any penalties for failure to meet the Thermal Efficiency Standards. 2.9 POWER AND ENERGY. As more fully set forth in Articles 5 and 6: ----------------- 2.9.1 SPCC shall, at its cost, expense and risk (except as otherwise set forth in this Agreement) deliver the Net Available Capacity and energy to NPC at the Delivery Point during the Cooperation Period. 2.9.2 SPCC shall provide Ancillary Services to NPC during the Cooperation Period. 2.9.3 NPC shall take the Net Available Capacity and energy delivered by the Cogeneration Power Production Facility at the Delivery Point on the outgoing line and shall pay to SPCC fees as provided in Part B of Article 6. 2.9.4 SPCC shall have the right to provide emergency power supply to the Thermal Hosts upon clearance from NPC Systems Operations; provided, however, that SPCC shall install meters to monitor such deliveries and NPC shall have the right to invoice the Thermal Hosts, at its normal energy rates (less any standby or demand charges) for deliveries of power from the Cogeneration Power Production Facility. Such power shall be included in the calculation of Energy Fees and Fuel Fees in accordance with Article 6 hereof. Except as set forth herein, SPCC shall not confer upon any other person a right to electricity generated by the Cogeneration Power Production Facility. 2.10 STEAM. During the Cooperation Period, SPCC shall deliver steam to the ------ Thermal Hosts in accordance with the terms and conditions of the agreements with the Thermal Hosts. Any failure to deliver steam which results in SPCC failing to meet the Thermal Efficiency Standards shall result to a penalty to SPCC as more fully set out in the Eighth Schedule if not excused under Article 2.8 above. 2.11 COSTS OF NPC. NPC shall be responsible for and shall bear all costs ------------ incurred by it in connection with the performance of its obligations under this Agreement. 2.12 OWNERSHIP OF COGENERATION POWER PRODUCTION FACILITY. Subject only to ---------------------------------------------------- Article 18, SPCC shall at all times own the Cogeneration Power Production Facility including all equipment and materials on the Site or used in 13 connection with the Cogeneration Power Production Facility and Switchyard Facilities which have been supplied by it or at its cost. 2.13 CERTAIN RESPONSIBILITIES OF SPCC. On and subject to the terms of this --------------------------------- Agreement, SPCC, at its own cost, shall be responsible for: (a) acquiring and developing the Site, construction, erection of the required infrastructure as described in Articles 3 and 4 of the First Schedule (Project Scope and Specifications); (b) importing and transporting equipment to the Site; (c) obtaining permits for the building, construction, operation and other permits to form the basis of SPCC's application for an Environmental Compliance Certificate; Regional Development Council, Barangay, municipal and provincial resolutions, licenses and business permits and approvals for the Project; and visas and work permits for foreign personnel; recruiting local labor; and complying with all local and other regulations, including the payment of all fees and costs thereof (other than those which are to be obtained by NPC pursuant to this Agreement); (d) constructing the Cogeneration Power Production Facility and Switchyard Facilities in accordance with the specifications set out in the First Schedule (Project Scope and Specifications) and Sixteenth Schedule (Environmental Criteria) and in compliance with the requirements of the Environmental Compliance Certificate; (e) preparing the Environmental Impact Statement Report (including the Environmental Impact Study) and obtaining the Project's Environmental Compliance Certificate; and (f) supplying and delivering Fuel necessary to generate electricity required pursuant to Article 6.1, or causing such Fuel to be supplied and delivered, during the period from the testing and commissioning of the Cogeneration Power Production Facility and during the Cooperation Period. 2.14 CERTAIN RESPONSIBILITIES OF NPC. On and subject to the terms of this -------------------------------- Agreement, NPC shall: (a) cooperate with and provide SPCC with any available data or information needed for SPCC to obtain an Environmental Impact Assessment report which are necessary for SPCC to obtain an Environmental Compliance Certificate; (b) provide SPCC with technical information required by SPCC for the design of the Switchyard and associated facilities; and (c) on a best efforts basis, provide the required endorsements where reasonably necessary, for SPCC to obtain the government approvals described in Articles 2.13(c) and 28.1.2. 2.15 MUTUAL COOPERATION. The Parties shall mutually cooperate with each other in ------------------- order to achieve the objectives of this Agreement. 14 2.16 FUEL SUPPLY. SPCC shall, at its cost, expense and risk (except as ------------ otherwise provided in this Agreement), supply and deliver all Fuel required during the start-up testing, commissioning of the Cogeneration Power Production Facility and all fuel required in the operation of the Cogeneration Power Production Facility during the Cooperation Period. ARTICLE 3 - CONSTRUCTION 3.1 PROJECT MILESTONE DATES. ------------------------ 3.1.1 SPCC shall commence development of the Cogeneration Power Production Facility on the Contract Signing Date and shall thereafter diligently pursue such work in order to achieve the timely completion of the Project and fulfill its other obligations under this Agreement in accordance within the following timetable:
MILESTONE TARGET DATE (Months from Contract Signing Date) Posting of Development Bond within ten Days Completion of Documentary requirements Six (6) Calendar Months (Government Approvals) Issuance of Environmental Compliance Ten (10) Calendar Months Certificate Financial Closing Date Fifteen (15) Calendar Months Site/Project Mobilization Date Sixteen (16) Calendar Months Target Commercial Operation Date Forty-Four (44) Calendar Months Posting of O & M Bond within ten Days after Commercial Operation Date
3.1.1.1 Environmental Compliance Certificate issuance shall be the time at which SPCC Philippines has received such issuance from the Department of Environmental and Natural Resources, and has provided NPC a copy thereof, as certified by an appropriate officer of SPCC Philippines. 3.1.1.2 Financial Closing shall be the time at which SPCC has demonstrated, to the reasonable satisfaction of NPC, that the financial resources committed to SPCC are adequate to perform SPCC's obligations under this Agreement by submitting a confirmation from its Lenders to NPC that the initial drawdown of 15 funds under the Lending Agreements is subject to no further condition. 3.1.1.3 Site/Project Mobilization shall be the time at which (a) SPCC begins, and thereafter diligently continues, construction of the foundation footings or other similar work which demonstrates, to the reasonable satisfaction of NPC, that it has begun (and intends diligently to pursue) construction of the Cogeneration Power Production Facility on the Site; and (b) SPCC delivers the Construction Performance Bond (Eighteenth Schedule) to NPC. 3.1.1.4 Within ten (10) Days after the Commercial Operation Date, SPCC shall deliver the O & M Bond (Nineteenth Schedule) to NPC. Notwithstanding anything to the contrary elsewhere contained in this Agreement, the Commercial Operation Date shall not occur until SPCC has so delivered that O & M Bond, and the Commercial Operation Date shall not occur prior to the Target Commercial Operation Date. 3.1.2 If a Party is prevented, hindered or delayed in the performance of an obligation under this Agreement by: (a) Force Majeure; or (b) by any failure (whether or not occasioned by Force Majeure) of the other Party to perform an obligation under this Agreement (including, in the case of NPC, to take electricity); then, unless specifically provided otherwise in this Agreement, the time limited for the performance of that obligation (or any date by which performance of that obligation is to be achieved, including in the case of SPCC, the Target Commercial Operation Date, and in the case of NPC, the Target Transmission Line Completion Date) shall at the option of the affected Party be extended by a period equal to the period by which its performance is so prevented, hindered or delayed. However, the time limited for performance of an obligation by NPC shall not be extended to the extent that performance of that obligation is prevented, hindered or delayed by Government Force Majeure. 3.1.3 NPC shall defend, indemnify and hold SPCC harmless against any and all claims and demands for any liabilities (other than contractual liabilities to the Thermal Hosts) and damages and all reasonable costs payable to any third parties as a result of the extension of the target date for any Milestone for reasons other than (i) the fault of SPCC; or (ii) any event of Force Majeure (other than Government Force Majeure). The Parties shall consult with each other and take all reasonable steps to minimize the losses of either Party from any such delay and to minimize any overall delay or prejudice to the Project. NPC or the appropriate governmental authority shall have the right to audit all costs charged to NPC by SPCC pursuant to this Article 3.1.3. 3.1.4 Notwithstanding anything to the contrary contained in this Agreement, NPC shall not draw on the Development Bond for any delay or failure in 16 performance by SPCC hereunder if the Environmental Compliance Certificate is delayed or not issued and such delay or non-issuance is attributable to the action or inaction of NPC or any relevant Competent Authority and not to any failure of SPCC to submit required documents or otherwise fulfill the legal requirements for issuance of an Environmental Compliance Certificate. 3.2 DELAY IN ACHIEVING MILESTONE ---------------------------- 3.2.1 If, subject to Article 3.1.2, SPCC fails to achieve a Milestone by the date therefor, it shall pay to NPC the amounts and at the times mentioned, and at the rate set forth in respect of such delay in the Third Schedule, for each Day of delay thereafter until such Milestone is achieved. 3.2.2 In the case of the amounts paid before the Commercial Operation Date, NPC shall refund such amounts paid by SPCC, without interest, if the Commercial Operation Date occurs on or before the Target Commercial Operation Date. SPCC acknowledges that this is a reasonable security required by NPC in the light of its responsibilities, and reflects the possibility that the Commercial Operation Date will not occur by the Target Commercial Operation Date and that electricity from the Cogeneration Power Production Facility will not be available to it on that date; and in the case of the non-delivery of the O & M Bond, that NPC will not have security for the performance of SPCC's obligations after the Commercial Operation Date. 3.3 SPCC'S RIGHTS. Pursuant to its obligations under Article 3.1 SPCC shall, -------------- among other things, have full right to: (a) call for tenders and award contracts with or without tender; (b) arrange for the preparation of detailed designs and approve or reject the same; (c) appoint and remove consultants and professional advisers; (d) purchase equipment; (e) appoint, organize and direct staff, and manage and supervise the Project; (f) enter into contracts for the supply of materials and services; and (g) do all other things necessary or desirable for the completion of the Facilities in accordance with the Specifications and Internationally Accepted Engineering Standards by the Target Commercial Operation Date. 3.4 LOCAL CONTRACTS. In fulfilling its obligations under Article 3.1 SPCC ---------------- shall, where available, award contracts to Philippine contractors and suppliers of materials and services provided that the quality, delivery times, costs, reliability and other terms are comparable to those offered by non-Philippine contractors and/or suppliers. 17 3.5 MONITOR PROGRESS. ----------------- (a) NPC shall review the basic engineering designs and plans prepared by SPCC for the Cogeneration Power Production Facility and the detailed designs of the Switchyard Facility in terms of its compliance with the prescribed standards and specifications set forth in the First Schedule; to ensure that the design and plans will not adversely affect the safe and secure operation of the grid, and shall approve the same, if found acceptable, prior to actual construction. NPC shall not unreasonably withhold such approval if design is per prescribed standards and specifications and within Internationally Accepted Engineering Standards. Any design changes by NPC outside of the prescribed standards and specifications are subject to concurrence by SPCC and, when applicable, are subject to a change in Capital Recovery Fees and in the schedule unless it is shown to SPCC's reasonable satisfaction that the safety or integrity of the grid would be compromised if such changes were not implemented. If NPC has not commented on such designs or plans within seventeen (17) Days from the date of receipt by NPC per the drawing submittal schedule agreed between NPC and SPCC, then such designs and plans shall be deemed approved. This approval by NPC notwithstanding, SPCC shall be solely responsible for the integrity of its detailed engineering designs and plans. The approval thereof by NPC does not diminish this responsibility, nor does it transfer any part of such responsibility to NPC. (b) SPCC shall allow NPC to conduct environmental audits and monitoring in accordance with the Environmental Compliance Certificate. During such audit and monitoring, NPC personnel shall be accompanied at all times by SPCC personnel, and shall be subject to Site rules and regulations. Such audits shall be limited to SPCC'S battery limits. (c) NPC shall be entitled, at its own cost, to monitor the progress and quality of the design, construction and installation work and for this purpose SPCC shall: (i) submit to NPC a monthly report (in form and content reasonably satisfactory to NPC), due within thirty (30) Days from the end of the preceding month, outlining the construction progress in such detail as is reasonable in the circumstances; (ii) ensure that NPC and any experts appointed by NPC in connection with the Project, with reasonable notice, are afforded reasonable access to the Site at times to be agreed with SPCC, provided that such access does not interfere with the work comprising the Project or expose any person on the Site to any danger; (iii) make available to NPC and any experts appointed by NPC in connection with the Project for inspection at the Site copies of all plans and designs (other than any proprietary information of SPCC or any of its contractors) or any part thereof; including all design drawings of SPCC or of its contractor or sub-contractor and manufacturers' engineering and technical manuals; and 18 (iv) make available an office of approximately 150 square feet at the Site for the use of NPC personnel performing such monitoring. (d) NPC shall be entitled at its own cost to witness Tests of machinery at the Site. SPCC shall give NPC fourteen (14) Days' written notice of the initiation of such Tests. Revision to the initiation of such Tests shall be given verbally no less than twenty four hours in advance to be followed by a written confirmation. (e) As soon as practicable after this Agreement is signed, NPC and SPCC shall organize a committee to formulate and agree on procedures for monitoring and reviewing the progress of the design, construction, equipping, completion and commissioning of the Cogeneration Power Production Facility and the Switchyard Facility. 3.6 DISCLAIMER. ---------- SPCC: (a) accepts that any information made available to NPC and any comment or approval made or given by NPC in respect thereof or otherwise in respect of the construction, operation and maintenance of the Cogeneration Power Production Facility (including the certification of the results of Tests) shall not relieve SPCC of any obligation nor prejudice any right of NPC under this Agreement; (b) shall in no way represent to any third party that, as a result of any engineering review conducted by NPC, NPC is responsible for the engineering soundness of, or otherwise makes any representation or warranty as to, the Cogeneration Power Production Facility; (c) agrees that it shall, subject to the other provisions of this Agreement, be solely responsible for the economic and technical feasibility, operational capability and reliability of the Cogeneration Power Production Facility; and NPC and SPCC acknowledge that Article 3.5 is intended to provide NPC the right to gather data for its own information only, and that, except as specifically set forth in Article 3.5(a), the same shall not be construed as giving NPC the right to approve, consider for possible amendment, require any revision or take any action with respect to designs or other works on the Facilities, provided, the design and works will not adversely affect the NPC grid, are as per prescribed standards and specifications, and are within Internationally Accepted Engineering Standards. 3.7 CONSULTATION. SPCC shall consult with NPC before and during the development ------------- of the design of the Cogeneration Power Production Facility and Switchyard Facility and, if and to the extent that operation of the grid may be affected, will discuss with NPC the possibility of alterations to the Specifications. 3.8 DRAWINGS AND TECHNICAL DETAILS. Without prejudice to Article 3.5, SPCC ------------------------------ shall, prior to commencing actual construction of the Cogeneration Power Production Facility and Switchyard Facility, prepare and submit to NPC five (5) 19 hard copies regarding the main group of drawings and technical details listed hereunder with respect to the Generating Assets: (a) final arrangement plans for general layout of machinery and equipment; (b) general and detailed drawings and specifications for electro- mechanical work; (c) general and detailed design drawings for civil and architectural works; (d) electrical protection drawings; (e) generator protection drawings; (f) GTG and STG turbine output curves; (g) energy balance calculation; (h) electrical single line diagram; (i) systems flow diagrams; (j) project summary comprising a general plant description, thermal process, electrical concept, control and monitoring concept, operating concept and general layout; (k) definitive overall project schedule; and (l) technical data such as design condition and assumptions of plant data, performance data of equipment(s), and correction curves. As soon as practicable or within six (6) months after the Commercial Operation Date, SPCC shall furnish NPC three (3) copies of "as-built" plans and design drawings in ISO 44 size (bound) and operation and maintenance manuals. Thereafter, SPCC shall furnish NPC any revisions thereof from the "as built" plans and design drawings during the Cooperation Period in the same number of copies and ISO 44 size. "As-built" plans and design drawings shall also be provided on microfilm or in such other electronic medium as SPCC and NPC may agree. 3.9 CONFIDENTIALITY. ---------------- (a) During the term of this Agreement each Party shall treat as confidential and (except as provided in Article 3.9(b)) shall not without first obtaining the consent of the other Party disclose to any person the provisions of this Agreement or any information supplied or made available for examination or otherwise disclosed hereunder to such Party by the other (such provisions and, in relation to such Party, such information being hereinafter referred to as "Confidential Information"). (b) Notwithstanding the provisions of Article 3.9(a), Confidential Information may be disclosed without the other Party's consent: 20 (i) by a Party to a governmental department, agency or authority; (ii) by SPCC to the Lenders; (iii) by a Party to its directors, officers, employees, agents and technical and professional advisers (and those of its parent companies and/or their subsidiary companies) who reasonably require such information in the course of their duties and responsibilities in relation to this Agreement; (iv) by a Party to its contractors and suppliers to the extent they reasonably require such information in the performance of their obligations in relation to this Agreement; (v) by a Party to the extent reasonably required for the purposes of obtaining and maintaining insurance; (vi) to the extent required by law, the rules of any recognized stock exchange upon which the shares of the disclosing Party (or of its parent companies or its and/or their subsidiary companies) are listed; (vii) for the purposes of dispute resolution or the enforcement of rights and obligations under this Agreement; and (viii) to the extent such information has become generally available to the public other than as a result of a breach by the disclosing Party of its obligations under this Article 3.9. 3.10 BOND. ---- (a) To secure the performance of its obligations under Article 3.2 in respect of the Development Milestones, SPCC shall, not later than ten (10) Days from the Contract Signing Date, cause to be issued and delivered to NPC, and maintained in full force and effect until the start of the Site/Project Mobilization, a standby letter of credit confirmed by a local bank in favor of NPC (the "Development Bond") in the agreed form in an amount equal to thirty (30) US$ multiplied by the Contracted Capacity (expressed in Kilowatts) (US$9,120,000.00). The form of the Development Bond is attached hereto as the Seventeenth Schedule. If the letter of credit is not so issued and delivered, this Agreement shall immediately terminate and be of no force or effect. (b) To secure the performance of its obligations under Article 3.2 in respect of the Construction Milestones, and to secure NPC against an Abandonment by SPCC of the Cogeneration Power Production Facility during construction, SPCC shall, upon the achievement of Site/Project Mobilization, promptly cause to be issued and delivered to NPC, and maintained in full force and effect until the Commercial Operation Date, a standby letter of credit confirmed by a local bank in favor of NPC (the "Construction Performance Bond") in the agreed form and in an amount equal to sixty (60) US$ multiplied by the Contracted Capacity (expressed in Kilowatts) (US$18,240,000.00) without need of demand from NPC. 21 The form of the Construction Performance Bond is attached hereto as the Eighteenth Schedule. (c) To secure NPC against an Abandonment by SPCC of the Cogeneration Power Production Facility during the period from the Commercial Operation Date up to the end of the Cooperation Period and to secure the due payment of amounts due to NPC by SPCC under this Agreement, SPCC shall cause to be issued and delivered to NPC immediately before the Commercial Operation Date, and maintained in full force and effect during each year falling within such period, a standby letter of credit confirmed by a local bank in favor of NPC (the "O & M Bond") in the agreed form and in an amount equal to thirty (30) US$ multiplied by the Contracted Capacity (expressed in Kilowatts) (US$9,120,000.00). The form of the O & M Bond is attached hereto as the Nineteenth Schedule. To the extent NPC makes demand and is paid under the O&M Bond for payment defaults by SPCC under this Agreement, SPCC shall cause the O&M Bond to be reinstated for its full value at all times. (d) For purposes of this Agreement, the Cogeneration Power Production Facility shall be deemed to have been Abandoned, and an Abandonment shall have occurred, if: (i) SPCC notifies NPC in writing that it has decided to terminate all construction work or operations of the Cogeneration Power Production Facility other than by reason of Force Majeure or fault of NPC and does not intend to recommence such work; or (ii) SPCC fails to resume construction or operation of the Cogeneration Power Production Facility within one hundred eighty (180) Days of termination or cessation of any event of Force Majeure (or delay occasioned by an event of Force Majeure) other than by reason of another event of Force Majeure; or (iii) SPCC fails to achieve Site/Project Mobilization by the Target Commercial Operation Date due to the fault of SPCC and through no fault of NPC; or (iv) the Commercial Operation Date shall have failed to occur within nine (9) months after the Target Commercial Operation Date due to the fault of SPCC and through no fault of NPC; or (v) the shareholders of SPCC shall have passed a resolution for the winding-up of SPCC, or SPCC shall have commenced proceedings before any court or administrative tribunal for winding-up, dissolution, bankruptcy, insolvency, or similar relief, or become subject to a final order or decree in any such proceeding; or (vi) due to the fault of SPCC, there shall have been a transfer or conveyance of SPCC's right to own and/or operate the Cogeneration Power Production Facility to any person without the prior written approval of NPC, except as specifically permitted pursuant to this Agreement; or 22 (vii) following the Commercial Operation Date, the Cogeneration Power Production Facility shall not have generated energy for a period exceeding 180 consecutive Days, due to the fault of SPCC and through no fault of NPC. (e) SPCC shall cause the Development Bond, the Construction Performance Bond and the O&M Bond to be maintained in force and effect in the applicable amounts set forth above until the Site/Project Mobilization Date, Commercial Operation Date and the end of the Cooperation Period, respectively. For such purpose, SPCC shall ensure that, on a timely basis, the Development Bond (if expiring by its terms before the Site/Project Mobilization Date), the Construction Performance Bond (if expiring by its terms before the Commercial Operation Date) and the O&M Bond (if expiring by its terms before the end of the Cooperation Period) are extended, renewed or replaced at least fifteen (15) Days before their respective expiry dates, in each case for a term not shorter than six (6) calendar months. ARTICLE 4 - TESTING 4.1 TESTING PROCEDURES. ------------------ 4.1.1 Without prejudice to Article 4.1.2, after the Site/Project Mobilization Date, SPCC shall provide to NPC a list of Tests and equipment inspections of the Cogeneration Power Production Facility (or every part thereof) which are to be carried out, whether before or after the Commercial Operation Date, and of the place and the scheduled time at which any such Test or inspection is to be conducted, and shall keep NPC fully informed of any material changes thereto. NPC shall notify SPCC in writing which Tests will be witnessed by NPC. 4.1.2 Not later than six (6) months and not earlier than nine (9) months prior to the then scheduled start of the Guarantee Tests, SPCC shall notify NPC in writing of its proposed (and, as soon as practicable thereafter the Parties shall meet to agree on) procedures, standards, protective settings, duration and program consistent with the Fourteenth Schedule (Tests and Test Procedure) for: (a) the Guarantee Test and all other Tests of the Cogeneration Power Production Facility mentioned in the Fourteenth Schedule to be conducted before the Commercial Operation Date; and (b) the Performance Tests and all other Tests of the Cogeneration Power Production Facility mentioned in the Fourteenth Schedule to be conducted during the Cooperation Period. To the extent the Parties are unable to agree, the matter shall be referred to an Expert for resolution. 23 4.2 WITNESSING OF TESTS. ------------------- 4.2.1 NPC shall have the right to witness all Tests of the Cogeneration Power Production Facility or any part thereof, and SPCC shall procure any necessary consent of its contractors and suppliers thereto. 4.2.2 SPCC shall give NPC fourteen (14) Days written notice of any Tests mentioned in Article 4.1.1 which are to be conducted on the Site (or within the Philippines) and sixty Days written notice of any such Tests which are to be conducted outside of the Philippines. 4.2.3 Provided notice has been given pursuant to this Article 4, Tests may be conducted validly at the notified times in the absence of representatives of NPC. If SPCC fails to give proper notice under this Article 4, the Test concerned, if conducted in the absence of NPC unless NPC otherwise agrees, shall be invalid and shall be repeated (subject again to the notice requirements of this Article 4) at the cost, risk and expense of SPCC. 4.2.4 No Guarantee Test or Performance Test shall be regarded as successfully completed until the result thereof has been jointly certified by SPCC and NPC in accordance with Article 4.6. To the extent the Parties are unable to agree, the matter shall be referred to an Expert for resolution. 4.2.5 SPCC shall coordinate with NPC's Systems Operations Department to establish the actual testing dates. 4.3 GUARANTEE TEST. --------------- 4.3.1 The Guarantee Test shall demonstrate to NPC that the Cogeneration Power Production Facility is capable of operating on a continuous and reliable basis in accordance with the Operating Parameters and the Specifications for a period of seven days and shall be used to prove the Contracted Capacity as of the Commercial Operation Date. 4.3.2 In the event that the Guarantee Tests demonstrate that the Cogeneration Power Production Facility is capable of operating on a continuous and reliable basis in accordance with the Operating Parameters and the Specifications, SPCC and NPC shall jointly certify that the Guarantee Tests were successfully completed. The Commercial Operation Date shall occur on the Target Commercial Operation Date or the date the Guarantee Tests are successfully completed, whichever is later. The Net Available Capacity shall be based on the actual results of the Guarantee Test, but shall in no event be greater than 304,000 kW. 4.3.3 If the Guarantee Tests have demonstrated that the Net Available Capacity is less than the Contracted Capacity, SPCC may elect (by notice to NPC within fifteen Days after completion of the Guarantee Test) that the Commercial Operation Date be deemed to have occurred. SPCC shall have no liability to NPC in respect of the reduced capacity beyond the effects thereof on the calculation of the Capital Recovery Fees and the Fixed O & M Fees to be paid by NPC under the Eighth Schedule. SPCC may retest at any time, upon giving notice as required in Article 4.2, if the capacity demonstrated in the Guarantee Tests is lower than 304,000 kW. 24 4.3.4. The Guarantee Tests will be performed in accordance with the provisions of this Article 4 and of the Fourteenth Schedule (Test and Test Procedures). 4.4 PERFORMANCE TEST. ----------------- 4.4.1 The Performance Test shall prove the Net Available Capacity nominated by SPCC for the Contract Year. 4.4.2 The Performance Test shall be done within fifteen (15) Days after each anniversary of the Commercial Operation Date, or such other date as the Parties may mutually agree, and in accordance with the provisions of this Article 4 and the Eighth Schedule and the Fourteenth Schedule (Test and Test Procedures). SPCC may retest up to three times within the fifteen Day period described above; provided, however, that NPC shall be given twenty-four (24) hours' telephonic or written notice of each retest. Additional retests may be carried out with NPC's reasonable approval. The results of the most recent Performance Test (including any retesting carried out pursuant to this Article 4.4.2) shall be effective for the purpose of determining deliveries and payments commencing at the start of the next Contract Year. 4.4.3 If, for any reason, SPCC is unable to conduct a Performance Test at the time scheduled for such Performance Test, SPCC shall promptly reschedule the Performance Test and shall give NPC at least twenty- four (24) hours' written notice of the rescheduled Test date. If SPCC shall have failed to conduct a Performance Test within the fifteen Day period described in Article 4.4.2, then the Performance Test shall be deemed to have demonstrated that the Cogeneration Power Production Facility is not Available. The foregoing shall not apply if SPCC's failure to conduct the Performance Test is due to an event of Force Majeure (including any failure of NPC to take electricity). 4.4.4 Yearly nomination of the Net Available Capacity for the following Contract Year shall be made by SPCC to NPC not later than thirty (30) Days prior to the anniversary of the Commercial Operation Date. 4.4.5 If SPCC fails to provide its nomination to NPC as provided above, the Net Available Capacity shall be equal to the Net Available Capacity in effect during the previous Contract Year until such time that SPCC shall have nominated and performed the required Tests in accordance with this Article 4 and the Fourteenth Schedule. SPCC shall (if required by NPC) and may (with the reasonable approval of NPC and upon forty-eight (48) hours' telephonic or written notice to NPC) carry out a Performance Test of the Cogeneration Power Production Facility at any time to determine Net Available Capacity. However, no more than four Performance Tests may be carried out in any Contract Year, except for retests permitted under Article 4.4.2 and tests required by NPC, neither of which shall count toward this limit. If the results of such Performance Test requested by NPC show that the Net Available Capacity is lower than the previous Contract Year's Net Available Capacity, SPCC shall refund to NPC excess payments for the Capital Recovery Fees and the Fixed O & M Fees during 25 the current Contract Year that the previous Contract Year's Net Available Capacity was in effect. To the extent the Parties are unable to agree, the matter shall be referred to an Expert for resolution. 4.5 COST OF TESTING AND PURCHASE OF ELECTRICITY. -------------------------------------------- During testing and commissioning of the Cogeneration Power Production Facility prior to the Commercial Operation Date: (a) SPCC shall at its own cost supply Fuel and (b) NPC shall take all electricity generated by the Cogeneration Power Production Facility during Tests and supplied at the Delivery Point, and shall pay Energy Fees therefor at fifty percent of the base energy rate set forth in the Eighth Schedule. If after completion of such testing but prior to the Commercial Operation Date, NPC desires to purchase energy from the Cogeneration Power Production Facility, then the Parties shall agree in writing upon the terms and conditions of such purchase. 4.6 CERTIFICATION. -------------- 4.6.1 Forthwith, upon the completion of the Guarantee Tests or Performance Tests pursuant to this Article 4 and the Fourteenth Schedule, SPCC and NPC shall jointly certify the result of such Tests. NPC shall not unreasonably withhold its certification. 4.6.2 Any other material Tests of the Cogeneration Power Production Facility (and the constituent parts thereof) to be completed before the Commercial Operation Date successfully completed shall be certified by SPCC in writing and SPCC shall provide NPC with a copy of such a certificate. 4.6.3 To the extent the Parties cannot agree upon whether or not a Test has been successfully completed, the matter shall be referred to an Expert for resolution. The Expert shall be directed to award interest at the Agreed Interest Rate on amounts not paid when due. The Expert shall have the power to award penalties in the event that the Expert determines that a Party has unreasonably withheld its certification, in an amount not to exceed three times the actual damages incurred by the other Party (including, in addition to amounts not paid when due, all liabilities, damages, and all reasonable costs payable to any third parties as a result of such delay, plus interest at the Agreed Interest Rate thereon from the date incurred). 4.7 DEEMED COMPLETION. ------------------ 4.7.1 If the Commercial Operation Date has not occurred only because the Guarantee Tests cannot successfully be carried out because NPC cannot take the electricity which will be generated during such Tests because the Transmission Line is not complete, the Commercial Operation Date shall 26 be deemed for all purposes of this Agreement to occur on the date on which it would otherwise have occurred, as notified in writing by SPCC to NPC ("Deemed Completion Date") but not, for the avoidance of doubt, before what would have been the Target Commercial Operation Date, but for such failure. On and from such date, the Cogeneration Power Production Facility shall be deemed to be Available, with a Net Available Capacity equal to 304,000 kW, and NPC shall pay Availability Fees based upon such capacity until the Net Available Capacity is established pursuant to the Guarantee Test. 4.7.2 In the circumstances mentioned in Article 4.7.1 above, NPC shall notify SPCC at least thirty (30) Days prior to the Transmission Line Completion Date, and SPCC shall initiate start-up, commissioning and testing activities no later than fifteen (15) Days after the Transmission Line Completion Date. SPCC shall schedule the Guarantee Test for as soon as reasonably possible after NPC notifies SPCC in writing that it is able to take the electricity generated by the Cogeneration Power Production Facility. If, for any reason, SPCC is unable to conduct the Guarantee Test at the time scheduled for such Test, SPCC shall promptly reschedule the Test and shall give NPC at least five (5) Days written notice of the rescheduled Test date. If SPCC shall have failed to conduct the Guarantee Test within one hundred twenty (120) Days of the Transmission Line Completion Date, then the Guarantee Test shall be deemed to have demonstrated that the Cogeneration Power Production Facility is not Available. The foregoing shall not apply if SPCC's failure to conduct the Guarantee Test is due to an event of Force Majeure (including any failure of NPC to take electricity or any failure of NPC to give proper, accurate notice of the Transmission Line Completion Date). 4.7.3 If NPC has made payments to SPCC of Availability Fees based upon a Net Available Capacity of 304,000 kW pursuant to Article 4.7.1 above, and if upon completion of the Guarantee Test (and any retesting carried out pursuant to this Agreement) the Net Available Capacity is determined to be less than 304,000 kW or the Cogeneration Power Production Facility is deemed not Available pursuant to Article 4.7.2, then the fees previously paid by NPC pursuant to Article 4.7.1 shall be recalculated based on the actual Net Available Capacity, and SPCC shall reimburse NPC for the overpayments (in the currencies in which such payments were made by NPC), plus interest thereon at the Agreed Interest Rate. 4.7.4 To the extent the Parties cannot agree upon whether or not SPCC shall have achieved the Deemed Completion Date, the matter shall be referred to an Expert for determination. ARTICLE 5 - OPERATION OF THE COGENERATION POWER PRODUCTION FACILITY 5.1 SPCC'S RESPONSIBILITIES. SPCC shall be responsible, at its own cost, for ------------------------ the management, operation, maintenance and repair of the Cogeneration Power Production Facility and Switchyard Facilities during the Cooperation Period and shall use its reasonable efforts to ensure that during such period the Cogeneration Power Production Facility is in good operating condition and capable of 27 generating electricity in a safe and reliable manner within the Operating Parameters. Except in an Emergency (when it shall use all reasonable endeavors to comply with dispatch instructions), SPCC shall not be obliged to operate the Cogeneration Power Production Facility other than within the Availability and actual Operating Parameters last advised by it to NPC pursuant to Article 5.3. 5.2 DOWNTIME. Notwithstanding Article 5.1, SPCC shall be entitled to periods --------- of Planned Maintenance and Forced Outage (as defined in the Sixth Schedule) in order to undertake necessary overhaul, maintenance, inspection, repair and turbine washing subject to the provisions of the Sixth Schedule, and shall not be obliged to operate the Cogeneration Power Production Facility inconsistently therewith. 5.3 AVAILABILITY. ------------- 5.3.1 SPCC shall at all times keep NPC advised of the current and anticipated Availability and actual Operating Parameters of the Cogeneration Power Production Facility. Without prejudice thereto, SPCC shall comply with the Sixth Schedule. 5.3.2 SPCC shall not advise of nor permit to remain outstanding any advice as to Availability and Operating Parameters containing levels different from those which the Cogeneration Power Production Facility is capable of achieving. This shall not oblige SPCC to advise NPC of levels in excess of those specified in the First and Second Schedules. 5.3.3 To the extent that an event of Force Majeure (other than Government Force Majeure) affects NPC's ability to take electricity from the Cogeneration Power Production Facility, but the Cogeneration Power Production Facility would have been able to deliver electricity in accordance with the terms and conditions of this Agreement, the Cogeneration Power Production Facility shall be deemed not Available (and the term "Force Majeure Outage" as used in the Eighth Schedule shall include all such reductions in Availability) to the extent it cannot be operated because of NPC's failure to take electricity because of Force Majeure (other than Government Force Majeure); but only for a period equal to the duration of the actual event or circumstance of Force Majeure and for a maximum of seven additional days, in the aggregate, in any Contract Year. The time taken to overcome an event or occurrence of Force Majeure, as well as the time during which the effects of Force Majeure subsist, shall not, for the purposes of the foregoing, be considered in determining the duration of the actual event or occurrence of Force Majeure. 5.4 OPERATION. ---------- 5.4.1 The Cogeneration Power Production Facility shall be operated as a base load generating unit at a nearly continuous level of output, except during periods of Downtime and Forced Outages as more specifically described in the Sixth Schedule (Electricity Delivery Procedures), subject to this Agreement, and safe operating practices pursuant to the Second Schedule (Operating Parameters) and Good Operating Procedures. 28 5.4.2 SPCC shall only operate the Cogeneration Power Production Facility in accordance with the dispatch instructions given in accordance with the Sixth Schedule. However, and without prejudice to the Sixth Schedule, SPCC shall not be obliged to operate the Cogeneration Power Production Facility other than within the Availability and actual Operating Parameters last advised by it pursuant and subject to Article 5.3.1 and 5.3.2 (except in an Emergency, when SPCC shall use all reasonable efforts to comply). 5.5 SPCC'S RIGHTS. Pursuant to its obligations under Article 5.1 of this -------------- Agreement, SPCC shall have all the rights of an owner and operator of a Cogeneration Power Production Facility, including among other things the right to: 5.5.1 enter into contracts for the supply of materials and services, for operation and maintenance, and for the sale of steam to the Thermal Hosts; 5.5.2 appoint and remove consultants and professional advisers; 5.5.3 purchase replacement equipment; 5.5.4 appoint, organize and direct staff and manage, and supervise the Cogeneration Power Production Facility; 5.5.5 establish and maintain regular inspection, maintenance and overhaul procedures; and 5.5.6 do all other things necessary or desirable for the operation of the Cogeneration Power Production Facility within the Operating Parameters set forth in the Second Schedule. 5.6 NPC'S OBLIGATIONS. NPC shall: ------------------ 5.6.1 endeavor to ensure that there is a supply of electricity as provided in Article 2 and the First Schedule (Project Scope and Specifications), the cost of the utilization of which shall be for SPCC's account; and 5.6.2 at its own cost, construct, install, maintain and repair the Transmission Line and ensure that at all times the Transmission Line is capable of operating within the specifications set out in the Fifth Schedule (Transmission Line Specifications). 5.7 ENVIRONMENTAL IMPACT. SPCC shall monitor and produce reports (copies of --------------------- such reports to be furnished to NPC) on the environmental impact of the Cogeneration Power Production Facility in accordance with the requirements of the Environmental Compliance Certificate, and shall operate the Cogeneration Power Production Facility in compliance with the requirements of the Environmental Compliance Certificate and the Sixteenth Schedule (Environmental Criteria). 5.8 SAFETY AND TECHNICAL GUIDELINES/ GRID CODE. ------------------------------------------- 5.8.1 NPC and SPCC shall organize a Steering Committee which shall, from time to time, coordinate, meet, discuss and agree upon safety and technical guidelines for the operation of the Cogeneration Power Production Facility 29 in accordance with the Operating Parameters, the Specifications, NPC's System requirements and the Grid Code. The Steering Committee shall also serve as a venue for the discussion of contractual issues and concerns in relation to the Cogeneration Power Production Facility. The Committee shall be composed of six members. three to be nominated by SPCC and three to be nominated by the Regional Center, one of which should be from Systems Operations (Luzon). 5.8.2 The Parties acknowledge that no Grid Code has yet been adopted in the Philippines. To the extent that the Grid Code, if and when adopted, imposes monetary burdens on the Project (such as requirements for the installation of equipment not contemplated in the First Schedule), SPCC shall give NPC notice of the costs of complying therewith, and NPC shall reimburse SPCC for such costs. NPC or the appropriate governmental authority shall have the right to audit all costs to NPC by SPCC. ARTICLE 6 - SALE OF ELECTRICITY PART A: SUPPLY OF ELECTRICITY 6.1 SUPPLY TO NPC. SPCC agrees to sell electricity to NPC and NPC agrees to -------------- take and pay for all electricity delivered to NPC in accordance with the procedures set out in the Sixth Schedule (Electricity Delivery Procedures) and the Operating Parameters set out in the Second Schedule (Operating Parameters). 6.2 QUANTITY. The quantities of electricity delivered to NPC by SPCC at the --------- Delivery Point from time to time shall be monitored, measured and recorded in accordance with the provisions of the Seventh Schedule (Measurement and Recording of Electricity). 6.3 DELIVERY. SPCC shall deliver the entire Cogeneration Power Production --------- Facility power output (net of Cogeneration Power Production Facility usage and subject to Article 2.9.4) to NPC at the Delivery Point on the outgoing line consistent with the Seventh Schedule (Measurement and Recording of Electricity). It is acknowledged that (except as otherwise provided in the Sixth Schedule) the Cogeneration Power Production Facility shall operate as base load plant; provided, however, that SPCC shall comply with the terms and conditions of the Sixth Schedule in accommodating dispatch orders validly given in accordance therewith. PART B: FEES 6.4 FEES. ---- 6.4.1 During the Cooperation Period NPC shall pay SPCC Availability Fees and Energy Fees, in each case calculated as provided in the Eighth Schedule. 6.4.2 Fuel Fees shall be payable from and after the Commercial Operation Date calculated on the basis of all kWhs delivered to the Delivery Point on the outgoing line at the heat rate guaranteed in the Eighth Schedule. 30 6.4.3 In the event of an occurrence of Force Majeure described in Article 13.1 (a) (except Force Majeure related solely to the Thermal Hosts) which renders the Cogeneration Power Production Facility unable to operate, or an occurrence of Force Majeure which renders NPC unable to take electricity and results in the Cogeneration Power Production Facility being deemed not Available during the occurrence of the Force Majeure event pursuant to Article 5.3.3, either of which results in a reduction of Availability Fees pursuant to the Eighth Schedule, the Cooperation Period shall be extended to account for the number of kWh lost due to the event of Force Majeure. 6.5 INVOICES. In respect of each Billing Period, SPCC will deliver to NPC an --------- invoice (in US$ and/or Philippine Pesos as required by the Eighth Schedule) in respect of Capital Recovery Fees, Fixed Operating and Maintenance Fees, Energy Fees and Fuel Fees for such Billing Period and NPC shall pay to SPCC the amount of such invoice within thirty (30) Days after the receipt of such invoice. 6.6 PAYMENT BY NPC. All fees payable to SPCC pursuant to this Article 6 shall --------------- be paid in the currencies stipulated in the Eighth Schedule (Delivery of Power and Energy) and each sum payable shall be decreased or increased so as to ensure that after NPC has deducted therefrom all taxes or charges for which NPC is liable for pursuant to Article 10.1, if any, (which taxes and charges shall be separately stated in all invoices and are to be paid in Pesos), there remains a sum equal to the amount that would have been payable to SPCC had there been no requirement to deduct or withhold such taxes or other charges. 6.7 NO SET-OFF. Except as set forth above or as required by the Law of the ----------- Republic of the Philippines, all payments made by NPC hereunder shall be made free and clear of and without deduction for or on account of any set- off, counterclaim, tax or otherwise except for taxes payable by SPCC which are required by Law to be withheld by NPC and except as specifically permitted pursuant to Article 6.10. 6.8 DISPUTES. If NPC disputes the amount specified in any invoice it shall so --------- inform SPCC within fifteen (15) Days of receipt of such invoice. If the dispute is not resolved by the invoice due date, NPC shall pay the undisputed amount on or before such date. The disputed amount shall be resolved according to Article 19 within fifteen (15) Days after the invoice due date for such invoice (for a total of forty-five (45) Days after receipt of such invoice) and all or any part of the disputed amount which is finally determined pursuant to Article 19 or Article 23 to be payable to SPCC shall be paid together with interest pursuant to Article 29.1 from the due date of payment until payment in full. PART C: FOREIGN EXCHANGE 6.9 DOLLAR PAYMENTS. All sums payable to SPCC in dollars shall be payable in ---------------- dollars in New York, in same-day funds, on the day when payment is due, to the account of SPCC at ______(Bank)_______or such other account as SPCC may specify and is acceptable to NPC which acceptance shall not be unreasonably withheld. 6.10 COST OF PAYMENTS. Any costs incurred by NPC in connection with the ----------------- remittance of funds outside the Philippines shall be for SPCC's account and shall 31 be deducted from the amount so remitted, provided that the portion of any regular and generally applicable bank charges, fees, and Documentary Stamp Tax in excess of 0.15% of the amount remitted shall be for the account of NPC and shall be paid by NPC directly to the remitting bank. 6.11 PESO PAYMENTS. All sums payable to SPCC in Pesos shall be payable in Pesos -------------- in Manila, in same-day funds, on the day when payment is due, to the account of SPCC with a bank in Manila that SPCC shall specify and is acceptable to NPC which acceptance shall not be unreasonably withheld. 6.12 PAYMENTS TO NPC. All sums payable by SPCC to NPC, whether pursuant to ---------------- judgment or otherwise, shall be payable in same-day funds, on the day when payment is due, to the account of NPC with a bank in Manila that NPC shall specify. 6.13 DOLLAR DEFICIENCY. In the event that any payment, whether pursuant to ------------------ judgment or otherwise, upon prompt conversion to dollars and transfer to New York, as provided in Article 6.9, does not result in payment of the dollar amount stipulated in this Agreement, SPCC shall be entitled to immediate payment of, and shall have a separate cause of action for, the dollar deficiency plus interest thereon pursuant to Article 29. However, should any such payment (upon conversion to dollars and transfer to New York as aforesaid) result in the receipt by SPCC of a sum in excess of the dollar amount stipulated in this Agreement, SPCC shall notify and pay the excess amount to NPC immediately upon SPCC's receipt of notice of the over- payment and its agreement to the same plus interest thereon pursuant to Article 29. PART D: CHANGE IN CIRCUMSTANCES 6.14 CHANGE IN CIRCUMSTANCES. ------------------------ 6.14.1 If, as a result of any Law coming into effect after the Contract Signing Date, or any Law (including any Law or any official written interpretation thereof, which SPCC has relied upon in entering into this Agreement, but excluding such Laws that only affect any Thermal Host in its capacity as thermal host and purchaser of steam) in force at the date hereof being amended, modified or repealed, or as a result of any Consent in effect as of the Contract Signing Date being subsequently terminated, withdrawn, rescinded or amended or as a result of any new required Consent not being obtained on a timely basis for reasons other than fault of SPCC, the Cogeneration Power Production Facility is unable to operate in accordance with the Specifications or within the Operating Parameters, and/or the interest of SPCC in the Site, the Project or the Facilities and/or SPCC's economic return on its investment (net of Philippine taxes and other impositions) is materially reduced, prejudiced or otherwise adversely affected (including without limitation, any restriction on the ability to remit funds in dollars outside of the Philippines), SPCC shall give NPC notice thereof with reasonably full particulars of the Law concerned and of its proposal for and the cost of complying therewith (which proposal should substantially preserve SPCC's economic return at the least cost to NPC, consistent with both Parties' obligations under this Agreement) and the Parties shall promptly meet and seek, in good faith (including by the provision of information and data), to agree on amendments to this 32 Agreement which will substantially preserve SPCC's said economic return at the least cost to NPC consistent with both Parties' obligations under this Agreement. If the Parties are unable to come to an agreement on appropriate amendments, the issue of how to amend this Agreement within the stated parameters shall be resolved according to Article 19 and, failing resolution thereunder, shall be referred to arbitration pursuant to Article 23. 6.14.2 If the circumstances mentioned above materially and favorably affect (or, in the reasonable opinion of NPC notified to SPCC, may materially and favorably affect) the said economic return of SPCC, SPCC shall give NPC notice thereof with reasonably full particulars of the Law concerned and of its proposal for and the savings resulting from taking advantage thereof (which proposal should maintain SPCC's economic return at the greatest savings for NPC consistent with both Parties' obligations under this Agreement) and the Parties promptly shall meet and seek, in good faith (including by the provision of information and data), to agree on amendments to this Agreement which will maintain SPCC's economic return at the greatest savings to NPC consistent with both Parties' obligations under this Agreement. If the Parties are unable to come to an agreement on appropriate amendments, the issue of how to amend this Agreement within the stated parameters shall be resolved according to Article 19 and, failing resolution thereunder, shall be referred to arbitration pursuant to Article 23. 6.14.3 For the purpose of determining whether a change in circumstances has occurred, a Consent obtained after the Contract Signing Date shall not be considered a change in circumstances unless such Consent was given on terms which are materially different from those which SPCC (to the best of its knowledge) could reasonably have expected immediately prior to the Contract Signing Date. 6.15 CONVERSION TO OTHER FUEL. ------------------------- 6.15.1 Conversion to Other Fuels. If and when Fuel is either unavailable ------------------------- or the Parties agree that there is another fuel which: (1) meets or betters the environmental criteria set forth in the Sixteen Schedule (Environmental Criteria); (2) satisfies the turbine warranties and specifications; and (3) is more economical on an overall basis for the Parties and the Project (taking into account fuel price and operation and maintenance considerations), the Parties may agree to an alternate fuel. The Thermal Efficiency Standards under such conditions shall remain pegged at 60%, computed on an annual basis. The Parties shall revise the Fourth Schedule (Fuel and Fuel Testing) to specify the cost basis of the alternate fuel. 6.15.2 Conversion to Natural Gas. If and when natural gas becomes -------------------------- available for use at the Cogeneration Power Production Facility, NPC may request SPCC to convert the Cogeneration Power Production Facility to operate on natural gas subject to an agreement on revised fees (pursuant to the Eighth Schedule) and parameters. If the Parties mutually agree to a change of fuel pursuant to this Article 6.15.2, then: 33 6.15.2.1 if the result is an increase in output due solely to the change in fuel, the Parties shall revise the Capital Recovery Fees and the Fixed Operating and Maintenance Fees so that SPCC is revenue neutral; 6.15.2.2 the Parties shall endeavor to make any adjustments in the Base Energy Rate necessary or appropriate to adequately compensate SPCC for the change in operating parameters attributable to the change in fuel; 6.15.2.3 the Parties shall revise the Fuel Fee equation applicable to the use of natural gas; and 6.15.2.4 the Thermal Efficiency Standards for natural gas shall be 57% pursuant to DOE Circular No. 96-01-005. ARTICLE 7 - TERM AND TERMINATION 7.1 TERM. The term of this Agreement shall begin from the Contract Signing ----- Date hereof and shall end on the last day of the Cooperation Period of twenty five (25) Years from the Commercial Operation Date unless otherwise provided herein or subsequently earlier terminated as agreed to by the Parties. 7.2 TERMINATION BY NPC. NPC shall have the right to terminate this Agreement ------------------- upon 30 Days' written notice to SPCC: (a) if SPCC Abandons the Cogeneration Power Production Facility; (b) if SPCC fails to deliver and maintain any Bond as and when required by this Agreement within fifteen (15) Days of a request therefor by NPC; and (c) if SPCC fails to obtain and maintain any insurance as required by this Agreement or fails within fifteen (15) Days of a request therefor by NPC to provide NPC with evidence reasonably satisfactory to it that any insurance required by this Agreement is maintained. 7.3 TERMINATION BY SPCC. -------------------- (a) SPCC shall have the right to terminate this Agreement upon 30 Days' written notice to NPC if NPC by reason of its insolvency or otherwise has failed to pay or ensure the due payment of any sum due under this Agreement (as the same may have been amended by mutual agreement or by arbitration pursuant to Article 23) within ninety (90) Days of the due date of such payment. (b) SPCC shall have the right to terminate this Agreement upon 30 Days' written notice to NPC if periods of Government Force Majeure have resulted in the Target Commercial Operation Date being extended by twelve months. 7.4 EXERCISE OF TERMINATION PAYMENT BY NPC. NPC shall have the right to --------------------------------------- terminate this Agreement if any period of Government Force Majeure during the Cooperation Period continues for more than twelve calendar months. 34 7.5 PRE-COMPLETION TERMINATION AND PAYMENT. --------------------------------------- 7.5.1 If this Agreement is terminated prior to the Commercial Operation Date pursuant to Article 7.3 or 7.4: (a) NPC shall not be entitled to draw upon the Development Bond or the Construction Performance Bond (and NPC shall promptly return such Bond to SPCC); (b) NPC shall pay SPCC a termination charge (calculated and paid in U.S. Dollars) equal to the aggregate of all costs, expenses and liabilities, including but not limited to all principal, interest and fees owed by SPCC to its Lenders, any other interest and any fees incurred by SPCC in connection herewith, plus an amount sufficient to provide SPCC with a return on equity of twelve (12%) percent per annum on the equity invested in the Project, for the period when the equity was invested; and (c) the termination shall be effective thirty (30) Days after the termination notice is given, at which time NPC shall pay SPCC the applicable termination charges and SPCC shall transfer the Generating Assets (other than the Site) to NPC on an "as is" basis. 7.5.2 If this Agreement is terminated prior to the Commercial Operation Date pursuant to Article 7.2 (a), (b) or (c), NPC shall be entitled to draw the remaining amount of the then applicable Bond at the time of termination. 7.6 POST-FACILITY COMPLETION TERMINATION AND PAYMENT. ------------------------------------------------ 7.6.1 If this Agreement is terminated on or after the Commercial Operation Date pursuant to Article 7.3 or 7.4: (a) NPC shall not be entitled to draw upon the Construction Performance Bond or the O&M Bond (and NPC shall promptly return such Bond to SPCC); (b) NPC shall pay SPCC the applicable termination charges determined in accordance with the Twentieth Schedule (Termination Price); and (c) The termination shall be effective thirty (30) Days after the termination notice is given, at which time NPC shall pay SPCC the applicable termination charges. In the event that there is no Viable Market (as defined in the Twentieth Schedule) as of the effective date of the termination, SPCC shall transfer the Generating Assets to NPC on an "as is" basis. In the event that a Viable Market exists, SPCC shall retain ownership of the Generating Assets. 7.6.2 If this Agreement is terminated on or after the Commercial Operation Date pursuant to Article 7.2(a), (b) or (c), NPC shall be entitled to draw the remaining amount of the O&M Bond at the time of termination. 35 7.7 DEDUCTIONS. In the event that the provisions of this Article apply as a ---------- result of an event of Force Majeure pursuant to Article 13, then there shall be deducted from any sum payable by NPC to SPCC an amount equal to the value, if any, of any applicable insurance proceeds received by SPCC, in respect of the event leading to the operation of the provisions of Article 13. ARTICLE 8 - REPRESENTATIONS, WARRANTIES AND COVENANTS OF SPCC 8.1 CORPORATE EXISTENCE. -------------------- 8.1.1 SPCC represents that it is a private corporation, duly organized and existing under the laws of the Netherlands with the corporate power and authority to execute, deliver and perform the terms and conditions to be performed by it under this Agreement, and that as of the date of this Agreement, the shareholders of SPCC are Texaco Nederland, B.V., a wholly owned subsidiary of Texaco Inc., and MEC San Pascual B.V., a wholly owned subsidiary of Edison Mission Energy. 8.1.2 SPCC Philippines is, or when formed pursuant to Article 28 will be, an entity duly organized and existing under the laws of the Republic of the Philippines with the power and authority to execute, deliver and perform the terms and conditions to be performed by it under the Accession Undertaking. As of the date of the Accession Undertaking, the partners in SPCC Philippines will be SPCC and Batangas Energy Corporation, a wholly owned subsidiary of Caltex. 8.2 GOVERNMENT AUTHORIZATIONS. SPCC represents and warrants that it has taken -------------------------- all necessary corporate action to enter into, execute, deliver and perform this Agreement, and such will not constitute a breach of any agreement or agreements to which it is a party; and prior to the Commercial Operation Date as required in all Project Milestones, it will have secured or caused to be secured all orders, consents, approvals, licenses and permits of all relevant government or governmental agencies in order for it to construct, own and operate the Cogeneration Power Production Facility. 8.3 COMPLIANCE WITH STANDARDS. SPCC warrants that the Cogeneration Power -------------------------- Production Facility shall be constructed, operated and maintained in accordance with Internationally Accepted Engineering Standards, Good Operating Procedures and those internationally accepted environmental standards which have been adopted by Law in the Philippines. 8.4 COMPLIANCE WITH LAWS. SPCC shall operate the Cogeneration Power Production --------------------- Facility in accordance with all environmental and other Philippine and local Laws in force as of the Contract Signing Date and shall comply with any changes in such laws and regulations and with any new laws and regulations, subject to Article 6.14. 8.5 SPCC'S WARRANTY AGAINST CORRUPTION. SPCC hereby warrants that neither it ----------------------------------- nor its representatives have offered any government officer and/or NPC official or employee any consideration or commission for this Agreement nor has it or its representatives exerted or utilized any corrupt or unlawful influence to 36 secure or solicit this Agreement for any consideration or commission; that SPCC shall not subcontract any portion or portions of the scope of the work of the Agreement awarded to any person known by SPCC to be an official or employee of NPC or to the relatives within the third degree of consanguinity or affinity of the NPC officials who are directly or indirectly involved in contract awards or project prosecution and that if any commission is being paid to a private person, SPCC shall disclose the name of the person and the amount being paid and that any material violation of this warranty shall constitute a sufficient ground for the rescission or cancellation of this Agreement or the deduction from the contract price of the consideration or commission paid without prejudice to the filing of civil or criminal action under the Anti-Graft law and other applicable laws against SPCC and/or its representatives and NPC's officials and employees. ARTICLE 9 - REPRESENTATIONS, WARRANTIES AND COVENANTS OF NPC 9.1 CORPORATE EXISTENCE. NPC represents that it is a corporation duly -------------------- organized and existing under and by virtue of the laws of the Republic of the Philippines, and has the corporate power and authority to execute, deliver and carry out the terms and conditions of this Agreement. 9.2 GOVERNMENT AUTHORIZATIONS. NPC represents and warrants that it has taken -------------------------- all necessary corporate action, and has secured or caused to be secured all necessary government orders, consents or approvals, permits and licenses to enter into, execute and perform this Agreement, to purchase power from SPCC, and shall endeavor to secure all other governmental approvals and registrations as may be required to enable it to make payments therefor in the respective currencies referred to herein, and such will not constitute a breach of any agreement or agreements to which it is a party. ARTICLE 10 - TAXES 10.1 RESPONSIBILITY FOR TAXES. ------------------------- 10.1.1 In the performance of its obligations under this Agreement, SPCC shall be responsible for: (i) obtaining all permits, approvals, clearances relative to plant construction and operation, including fees and other charges thereof, required by various government agencies, instrumentalities, subdivisions, entities, and/or private institutions routinely needed and available for business activities which any enterprise would be required to secure on its own; (ii) paying taxes imposed or calculated on the basis of the net income of SPCC and personnel income taxes of its personnel, and ensuring, on a best efforts basis, the payment of taxes imposed on its contractors and sub-contractors; (iii) paying taxes (such as input VAT) and duties on capital equipment and spare parts in accordance with the policies, guidelines, laws 37 and regulations of the Philippines Board of Investment (BOI) Investment Priorities Plan of 1996, and the Bureau of Internal Revenue (BIR) or any taxing authority thereof; (iv) paying local taxes, fees and charges imposed on SPCC; (v) paying for the entitled benefits provided for in Energy Regulations No. 1-94 "Benefit for LGUs, Regions, and Affected Community and People Hosting Power Plants and Energy Resource Development Projects" (as applicable); (vi) paying all real estate taxes and assessments, rates and other charges in respect of the Site, buildings and improvements on the Site and the Cogeneration Power Production Facility; In the event that a change in Law or any official written interpretation thereof after the Contract Signing Date increases SPCC's tax burden, the imposition of such additional taxes or increase in tax burden shall be treated as a change in circumstances, and Article 6.14 shall apply. Nothing contained in this Agreement shall obligate NPC to be responsible to any taxing authority for taxes imposed on SPCC's sub- contractors. The Parties acknowledge that such taxes are the responsibility of the subcontractors, and do not intend by this Agreement to assume any responsibility to third parties with respect to such taxes. 10.1.2 In light of NPC's exemption from VAT pursuant to Law, SPCC has agreed not to charge VAT to NPC. SPCC desires to obtain a zero rating from the Government of the Republic of the Philippines. However, in the event that NPC or its successor or assign is determined not to be exempt from VAT, SPCC shall have the right to charge VAT to NPC or such successor or assign. Such VAT shall be paid by NPC, or such successor or assign, in addition to the amounts set forth in the Eighth Schedule. For the avoidance of doubt, no Law, or change in Law, resulting in a determination that SPCC is zero rated or a determination that NPC or its successor is not exempt from VAT shall be considered a change in circumstances for the purposes of Article 6.14.2. 10.2 PAYMENT RESPONSIBILITIES. NPC shall be responsible for reimbursing SPCC ------------------------- for any fees that SPCC has paid, which fees are NPC's responsibility to pay, within thirty (30) Days of written demand therefor. NPC or the appropriate governmental authority shall have the right to audit all costs charged to NPC by SPCC pursuant to this Article 10.2. 10.3 PAYMENTS FREE AND CLEAR. All sums payable by NPC under this Agreement ------------------------ whether by way of fees, reimbursement of expenses or taxes, or otherwise shall be paid in full, without set-off or counterclaim, free of any deductions or withholdings imposed by the Republic of the Philippines or any agency or instrumentality thereof (including political subdivisions and taxing authorities), all of which shall be for the account of NPC (except those for which SPCC is to be responsible pursuant to Article 10.1). In the event that NPC is prohibited by law from making payments hereunder free of deductions or withholdings, then NPC shall pay such additional amounts to SPCC as may be 38 necessary in order that the actual amount received after deduction or withholding (and after payment of any additional taxes or other charges due as a consequence of the payment of such additional amounts) shall equal the amount that would have been received if such deduction or withholding were not required. 10.4 LATE PAYMENT ------------ 10.4.1 BY NPC. If any amount payable by NPC to SPCC hereunder whether in ------ respect of fees or otherwise and whether pursuant to judgment or otherwise is not received by SPCC on or before the due date NPC shall pay interest thereon, calculated at the Agreed Interest Rate from the date upon which it was due until the date which such amount is received by SPCC. 10.4.2 BY SPCC. If any amount payable by SPCC to NPC, whether pursuant to -------- judgment or otherwise, is not paid on or before the due date, SPCC shall pay interest thereon, calculated at the Agreed Interest Rate from the date that it was due until the date upon which such amount is received by NPC. ARTICLE 11- INSURANCE 11.1 INSURANCE. SPCC shall be responsible for obtaining insurance throughout ---------- the Cooperation Period as provided in the Tenth Schedule (Insurance) and shall provide NPC with certificates of all insurance obtained with respect to the Project. SPCC will obtain insurance from GSIS, to the extent such insurance complies with the terms of this Agreement and is available on commercially reasonable terms, and provided further that SPCC shall have the right to arrange reinsurance. SPCC shall be entitled to endorse or assign any insurance proceeds or claims hereunder in favor of any Lenders providing financing for the Project. Unless NPC has failed to perform any of its payment obligations hereunder and such failure is continuing, NPC shall, subject to the rights of any Lender, have the right to cause the proceeds of claims against such insurances, except third party liability and workmen's compensation insurance, with respect to damage or other casualty to the Cogeneration Power Production Facility, to be applied by SPCC to repair or restore the Cogeneration Power Production Facility to its previous condition. 11.2 ENDORSEMENTS. SPCC shall cause its insurers to provide endorsements naming ------------- NPC and its employees as additional insureds under its comprehensive or commercial general liability insurance policies relating to the ownership, construction, operation and maintenance of the Cogeneration Power Production Facility. ARTICLE 12 - TRANSMISSION LINE 12.1 OWNERSHIP AND RESPONSIBILITIES. NPC shall construct the Transmission Line ------------------------------- in accordance with the Fifth Schedule at its sole cost, risk and expense and so that the Transmission Line Completion Date occurs not later than the Target Transmission Line Completion Date. NPC shall maintain and operate the Transmission Line thereafter until the end of the Cooperation Period. 39 12.2 FAILURE TO TIMELY COMPLETE. --------------------------- 12.2.1 BY NPC OF THE TRANSMISSION LINE WHEN SPCC HAS ACHIEVED DEEMED ------------------------------------------------------------- COMPLETION DATE. If, by the Target Commercial Operation Date, SPCC --------------- has achieved the Deemed Completion Date, then NPC shall: (a) pay Availability Fees as set forth in Article 4.7; and (b) defend, indemnify and hold SPCC harmless against any and all claims and demands for any liabilities (other than contractual liabilities to the Thermal Hosts) and damages and all reasonable costs payable to any third parties as a result of such delay. The Parties shall consult with each other and take all reasonable steps to minimize the losses of either Party from the delay in completion of the Transmission Line and to minimize any overall delay or prejudice to the Project. NPC or the appropriate governmental authority shall have the right to audit all costs charged to NPC by SPCC pursuant to this Article 12.2.1. 12.2.2 BY NPC OF THE TRANSMISSION LINE WHEN SPCC HAS NOT ACHIEVED THE -------------------------------------------------------------- COMMERCIAL OPERATION DATE. If the Transmission Line is not ------------------------- completed by the Target Transmission Line Completion Date and SPCC has not achieved the Deemed Completion Date by the Target Commercial Operation Date, then the Target Commercial Operation Date shall be extended on a day for day basis, until either (a) SPCC achieves the Deemed Completion Date, at which time if the Transmission Line is still not capable of receiving power, the remedies provided for in Article 12.2.1 shall apply calculated from the date on which the Deemed Completion Date has occurred; or (b) the Transmission Line is completed and is capable of receiving power, at which time NPC's right to receive penalties shall commence after the Target Commercial Operation Date as set forth in Article 12.2.3. 12.2.3 BY SPCC. If the Transmission Line is capable of receiving power and ------- the Target Commercial Operation Date has occurred, but the Cogeneration Power Production Facility is not Available, then SPCC shall be subject to the penalties set forth in the Third Schedule. 12.3 TRANSFER OF OBLIGATION TO SPCC. Nothing contained in this Article shall ------------------------------ bar the Parties from entering into a separate agreement under which SPCC would cause the Transmission Line to be built on or over rights of way or easements obtained by NPC. NPC's obligation to obtain environmental clearances, rights of way and easements in a timely fashion would remain subject to Article 12.2.1. ARTICLE 13 - FORCE MAJEURE 13.1 FORCE MAJEURE. A Party shall not be liable for any failure to perform an -------------- obligation under this Agreement (including, in the case of NPC, to take electricity) to the extent such performance is prevented, hindered or delayed by: 40 (a) events or circumstances (other than as mentioned in paragraph b. below) which are beyond its reasonable control and the effects of which cannot reasonably be overcome by it by the exercise of Good Operating Procedures; or (b) i. war (whether declared or not), hostilities, belligerence, blockade, revolution or insurrection occurring in (or initiated by the Government of) the Republic of the Philippines; ii. expropriation, requisition, confiscation, nationalization, import restriction or closure of harbors, docks, canals or other assistance to shipping or navigation by the government of the Republic of the Philippines or any subdivision thereof; iii. rationing or allocation, whether imposed by Law or by compliance of industry at the insistence of the government of the Republic of the Philippines or any subdivision thereof; or iv. event, matter or thing which shall reasonably be within the control of NPC or any Competent Authority, or any closure, restriction or other material change in the operation of the Refinery (to the extent not due to the negligence of the Refinery or the Refinery's failure to comply with any Law in effect as of the Contract Signing Date), which directly causes a material and adverse impact on the Cogeneration Power Production Facility, caused by or contributed by NPC or any Competent Authority; and, in any such case, the effects of which cannot reasonably be overcome by it by the exercise of Good Operating Procedures. The items set forth in Article 13.1(b), subsections (i) through (iv) above shall be referred to as events of "Government Force Majeure", and each of the foregoing events, matters or things described in this Article 13.1 shall be referred to as an event of "Force Majeure" in this Agreement; provided that: (c) Planned Maintenance; (d) failure to pay money (except as a result of a total failure of the worldwide money transfer system); (e) Forced Outage, to the extent the result of actual or anticipated mechanical or electrical derangement or component failure under design operating conditions and when constructed, operated and maintained in accordance with Good Operating Procedures; (f) any failure by a Party to obtain and/or maintain and comply at all times with the terms of all Consents necessary to enable it to fulfill its obligations under this Agreement, if the reason for such failure is the refusal by a Party concerned to accept conditions which are not unduly onerous; 41 (g) in the case of SPCC, any failure to obtain and maintain a bond or insurance as required by this Agreement; (h) in the case of SPCC, any event, matter or thing which shall reasonably be within the control of SPCC; (i) in the case of NPC, lack of market for electricity; and (j) in the case of NPC, Government Force Majeure; shall not be Force Majeure. 13.2 EXCEPTIONS. ----------- 13.2.1 Notwithstanding Article 13.1, NPC shall not be entitled to claim for itself Force Majeure in respect of any event of Government Force Majeure, and shall not be relieved of its obligation to make payments of Availability Fees by the occurrence of such event of Government Force Majeure, whether such event affects NPC or SPCC. 13.2.2 Notwithstanding Article 13.1, SPCC shall not be entitled to claim Force Majeure for the following events: (a) Any shutdown of the Refinery due to bankruptcy, reorganization, or appointment of a receiver for Caltex; or (b) Any failure by the Refinery to provide any Fuel it has contracted with SPCC to provide, if and to the extent that such Fuel is available elsewhere for delivery to the Project (i) for the same price as the Fuel to have been supplied by the Refinery (or at such higher price as NPC shall have agreed in writing to include in the Fuel Fees) and (ii) on the same terms and conditions as the Fuel to have been supplied by the Refinery, or on different terms and conditions to the extent that such terms and conditions do not increase the overall price to SPCC (or NPC shall have agreed in writing to compensate SPCC for the effect thereof through the Fuel Fees). 13.3 PROCEDURE. The Party invoking Force Majeure shall: ---------- (a) notify the other Party as soon as reasonably practicable by fax or cable of the event or circumstance concerned and of the extent to which fulfillment of its obligations is prevented, hindered or delayed thereby; (b) keep the other Party fully informed as to the actions taken or to be taken by it to overcome the effects thereof, and from time to time provides the other Party with such information and permits it such access as the other Party may reasonably require for the purpose of assessing such effects and the actions taken or to be taken; and (c) resume performance of its obligations as soon as possible after the effects thereof have been overcome or the event or circumstance no longer exists. 42 13.4 CONSULTATION. The Parties shall consult with each other and take all ------------- reasonable steps to minimize the losses of either Party resulting from Force Majeure and to minimize any overall delay or prejudice to the Project. 13.5 EXTENSION OF TIME. ------------------ 13.5.1 If a Party is prevented, hindered or delayed in the performance of an obligation under this Agreement by Force Majeure then, subject to the foregoing provisions of this Article 13, the time limited for the performance of that obligations shall be extended by a period equal to the period by which its performance was so prevented, hindered or delayed; provided that the time limited for performance of an obligation by NPC shall not be extended to the extent that performance of that obligation has been prevented, hindered or delayed by Government Force Majeure. 13.5.2 If a Party is prevented, hindered or delayed in the performance of an obligation under this Agreement by any failure (whether or not occasioned by Force Majeure) of the other Party to perform an obligation under this Agreement, the time limited for the performance of that first mentioned obligation shall be extended by a period equal to the period by which the first mentioned Party's performance was so prevented, hindered or delayed. 13.5.3 If a Party's performance is prevented, hindered or delayed by an event of Force Majeure for a period in excess of 180 Days, or if any event of Force Majeure occurs which causes material damage to the Project or the Cogeneration Power Production Facility and such event of damage would not ordinarily be insured against by NPC, the Parties hereto shall meet and endeavor to agree on amendments to this Agreement which will substantially preserve SPCC's economic return at the least cost to NPC consistent with both Parties' obligations under this Agreement. If the Parties are unable to come to an agreement on appropriate amendments, the issue of how to amend this Agreement within the stated parameters shall be resolved according to Article 19 and, failing resolution thereunder, shall be referred to arbitration pursuant to Article 23. ARTICLE 14 - EXPERT 14.1 APPLICATION OF ARTICLE. The provision of this Article 14 shall apply ----------------------- whenever a dispute cannot be settled by mutual discussion and either (a) this Agreement specifically provides that the matter is to be referred to a Expert for resolution or (b) the Parties agree in writing to refer the matter in question to an Expert for resolution. 14.2 APPOINTMENT. The procedure for the appointment of an Expert shall be as ------------ follows: 14.2.1 the Party wishing to appoint or to refer a matter to an Expert shall give notice to that effect to the other Party and, with such notice, shall give details of the reason for the appointment of, and the matter to be referred to, the Expert; 43 14.2.2 the Parties shall meet and endeavor to agree upon a person to be the Expert; 14.2.3 if, within twenty-one (21) Days from the date of the notice under paragraph 14.2.1 above, the Parties have failed to agree upon an Expert, the matter shall forthwith be referred by the Party wishing the appointment to be made to the UNCITRAL ("the Appointor") which shall be requested to make the appointment of the Expert within thirty Days and, in so doing, may take such independent advice as he thinks fit; 14.2.4 upon a Person being appointed as Expert under the foregoing provisions, the Parties forthwith shall notify such Person of his selection and shall request him to confirm within fourteen Days whether or not he is willing and able to accept the appointment; 14.2.5 if such Person is either unwilling or unable to accept such appointment, or shall not have confirmed his willingness and ability to accept such appointment within the said period of fourteen Days, then (unless the Parties are able to agree upon the appointment of another Expert) the matter shall be referred (by either Party) in the manner aforesaid to the Appointor who shall be requested to make an appointment or (as the case may be) a further appointment and the process shall be repeated until a Person is found who accepts the appointment as Expert; 14.2.6 Within seven (7) Days of the appointment of the Expert, the Expert shall designate a time and place for a hearing of the Parties on the dispute, which time shall not be more than fourteen (14) Days after the Expert's appointment; and 14.2.7 if there shall be any dispute between the Parties as to the remuneration to be offered to the Expert, then such amount shall be determined by the Appointor whose decision shall be final and binding on the Parties. 14.3 ELIGIBILITY. Unless the Parties agree otherwise in writing, a person shall ------------ not be appointed as an Expert: 14.3.1 unless he shall be qualified by education, experience and training to determine the matter in dispute; 14.3.2 if he has an interest or duty which would materially conflict with his role (including being a director, officer, employee or consultant to a Party or to any affiliate of a Party); or 14.3.3 if he is a national or permanent resident of the Philippines or of any country in which SPCC or its shareholders (or their ultimate holding companies) is located. 14.4 PROCEDURES. ----------- 14.4.1 The following provisions shall apply to the Expert's determination: (a) each Party shall supply to the Expert such information as the Expert may request; 44 (b) at the time nominated for the hearing, each Party shall appear before the Expert (with advisors of its choosing, if the Party so desires) and present its case; (c) the Expert shall make his decision as soon as reasonably practicable after completion of the hearing and receipt of data, information and submissions supplied and made to him by the Parties not later than thirty Days after he has confirmed to the Parties acceptance of his appointment; (d) the Expert shall ignore any data, information or submissions supplied and made after thirty Day period referred to in subparagraph (c) above unless the same are furnished in response to a specific request from him; (e) the Expert shall be entitled to obtain such independent professional and/or technical advice as he may reasonably require and to obtain any necessary secretarial assistance as is reasonably necessary; and (f) the Expert shall give full written reasons for his decision. 14.4.2 All communications between the Parties and the Expert or the Appointor shall be made in writing and a copy thereof provided simultaneously to the other Party. No meeting between the Expert or the Appointor and the Parties or either of them, shall take place unless both Parties have a reasonable opportunity to attend any such meeting. 14.4.3 The Expert shall be deemed not to be an arbitrator but shall render his decision as an expert and the procedural laws relating to arbitration shall not apply to the Expert or his determination or the procedure by which he reaches his decision. 14.4.4 The determination of the Expert shall be final and binding upon the Parties upon the delivery to them of the Expert's written determination, save in the event of fraud, mistake or manifest error. 14.4.5 Each Party shall bear the costs of providing all data, information and submissions given by it, and the costs and expenses of all counsel, witnesses and employees retained by it, but (unless the Expert shall make any award of such costs and expenses which award, if made, shall be part of the Expert's decision) the cost and expenses of the Expert and any independent advisers to the Expert, and any costs of his appointment if he is appointed by the Appointor, shall be borne equally by the Parties. 14.4.6 If the Expert does not render a decision within a period of ninety (90) Days of completion of the hearing or such longer or shorter period as the Parties may agree in writing, either Party may, upon giving notice to the other, terminate such appointment, and a new Expert shall be appointed who shall resolve the dispute in accordance with this Article 14. If the dispute is not resolved within nine months of a Party's original notice to refer the dispute to an Expert, or enforcement of this Article 14 or any 45 decision hereunder is denied for any reason, then either Party may refer the dispute to arbitration in accordance with Article 23. ARTICLE 15 - SEVERAL OBLIGATIONS Except where specifically provided otherwise in this Agreement, the duties, obligations and liabilities of the Parties hereto are several and not joint or collective, each Party shall be liable only for its own obligations. Nothing in this Agreement shall be construed as creating an association, trust, partnership or joint venture among the Parties hereto. ARTICLE 16 - NOTICES 16.1 WRITING. Unless otherwise stated, each communication to be made hereunder shall be made in writing. 16.2 ADDRESSES. Any communication or document to be made or delivered by one ---------- Party to another Party pursuant to this Agreement shall be made or delivered to that other Party at the following address or fax number: NATIONAL POWER CORPORATION President Quezon Avenue Corner Agham Road East Triangle, Diliman Quezon City, Philippines Fax (632) 921-2998 with a copy to: Project Manager Project Management and Engineering Services Group Quezon Avenue Corner Agham Road East Triangle, Diliman Quezon City, Philippines Fax (632) 921-2998 SAN PASCUAL COGENERATION COMPANY INTERNATIONAL B.V. Managing Director 8/F 6750 Ayala Avenue 1226 Makati, Metro Manila Philippines Fax (632) 892-7755 46 with a copy to: 3521 CB Utrecht The Netherlands Croeselaan 18 Fax (31-30) 21-6944 Attention: Managing Directors or such other address notified by that Party to the other Parties by giving not less than 15 Days notice of such change of address, and shall be deemed effective (i) in the case of any communication made by fax, with correct confirmation, when dispatched to such fax number, and (ii) in the case of any communication made by letter, when left at that address or otherwise received by the addressee. ARTICLE 17 - WAIVER None of the provisions of this Agreement shall be considered waived by either Party except when such waiver is given in writing. The failure of either Party to insist, in any one or more instances, upon strict performance of any of the provisions of this Agreement or to take advantage of any of its rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect. ARTICLE 18 - BENEFIT OF AGREEMENT 18.1 ASSIGNMENT BY NPC. NPC may assign or transfer all or any part of its rights, benefits or obligations hereunder, and may merge or consolidate with any other company which is wholly or partially owned by the Republic of the Philippines where the surviving entity adopts and becomes fully liable to perform NPC's obligations hereunder and such merger or consolidation does not affect the validity and enforceability of the Performance Undertaking. 18.2 NPC PRIVATIZATION. ------------------ 18.2.1 In the event of restructuring and/or privatization of NPC in furtherance of law or regulation coming into effect after the signing of this Agreement, NPC may assign all or any part of its rights and obligations under this Agreement to any person to whom the Performance Undertaking (to the extent applicable to the obligations assigned) is extended in respect of the obligations assigned. 18.2.2 Except as set forth in Article 18.2.1 above, NPC has the right to assign all or any of its rights and obligations under this Agreement to any person or persons, provided that the assignee shall have obtained and maintained for two Years an investment grade credit rating from Standard & Poors or Moody's Investor Service or any other internationally recognized rating agency for its long-term, unsecured, unguaranteed U.S. Dollar or Japanese Yen debts. 18.3 ASSIGNMENT BY SPCC. SPCC may not, without the consent of NPC, transfer all or any of its obligations hereunder except that, for the purposes of arranging or 47 rearranging financing for the Project, and ascending this Agreement to SPCC Philippines, SPCC may assign or transfer to any person or entity providing financing to the Project, all or any part of its rights and benefits hereunder as security for the indebtedness. NPC shall duly acknowledge any such assignment or transfer of which it is given notice and shall cooperate in good faith in executing required documents and consents required by the lending party or institution. SPCC shall remain jointly and severally liable with SPCC Philippines for the obligations under this Agreement upon the ascension by SPCC Philippines. 18.4 SPCC PHILIPPINES. The importation into the Philippines of all equipment ----------------- for the Project and all other work in connection with the Project which necessarily has to be performed in the Philippines and which SPCC agrees to be responsible for hereunder shall be carried out by SPCC Philippines which shall undertake to perform SPCC's obligations to perform such work and in consideration of which NPC shall pay fees as provided in Part B of Article 6; for such purpose, SPCC, NPC and SPCC Philippines (whose participation SPCC shall procure) shall execute and deliver the Accession Undertaking, upon the effectiveness of which SPCC Philippines shall become a party hereto without the need for any further action on the part of SPCC or NPC . 18.5 EFFECT OF ASSIGNMENT. Except as set forth in Article 18.4, no assignment -------------------- shall be effective until the assignee has delivered to the Parties a written undertaking (in form and content reasonably satisfactory to them) accepting and assuming the rights and obligations to be assigned. Thereupon, the assignor shall be relieved of its obligations to the extent assigned except for any obligations accrued before the effective date of the assignment. Such accrued obligations shall also become the obligations of the assignee. ARTICLE 19 - DISPUTE RESOLUTION 19.1 REGULAR MEETINGS. Throughout the Cooperation Period representatives of NPC ----------------- and SPCC shall meet regularly at not less than yearly intervals, or as the need arises, to discuss the progress of the Project and the operation of the Cogeneration Power Production Facility in order to ensure that the arrangement between the Parties hereto proceeds on a mutually satisfactory basis. 19.2 AMICABLE SETTLEMENT. Without prejudice to Article 14, the Parties hereto -------------------- agree to seek in good faith to resolve any dispute, controversy or claim arising out of, or relating to, this Agreement, or the breach, termination or invalidity thereof, or in the interpretation of any of the provisions thereof by discussion. Failing such resolution, either Party may require by notice to the other that the matter be referred to their respective senior executives with decision making authority for resolution and each Party shall procure that its senior executive seeks in good faith to resolve the matter by discussion with the other. Such dispute or differences and the joint decision of such senior executives shall be binding upon the Parties hereto and in the event that a settlement of any such dispute or difference is not reached pursuant to this Article 19.2 then the provisions of Article 23 shall apply. 48 ARTICLE 20 - ENTIRE AGREEMENT This Agreement constitutes or expressly refers to the entire agreement of the Parties in respect of the subject matter hereof and all previous agreements, arrangements, understandings and representations, express or implied and whether oral or written are of no force and effect. ARTICLE 21 - GOVERNING LAW 21.1 This Agreement shall be governed by and construed in accordance with the laws of the Republic of the Philippines except such of those laws as would direct the application of the laws of another jurisdiction. Without prejudice to Article 23, the Parties may by mutual agreement waive the arbitration requirements of Article 23 and, in such event, the Parties submit to the non-exclusive jurisdiction of the proper courts of Quezon City, Metropolitan Manila, Philippines for the hearing and determining of any action or proceeding arising out of or in connection with this Agreement. 21.2 Neither Party shall be relieved of any obligation under this Agreement pending the resolution of a dispute pursuant to Articles 14 or 23 or otherwise. ARTICLE 22 - DISCLAIMER Except to the extent provided in this Agreement, in no event shall either Party be liable to the other Party for any indirect, special, incidental, consequential or exemplary damages with respect to any claim arising out of this Agreement, whether based upon contract, tort (including negligence), strict liability, patent, trademark, or servicemark or otherwise. ARTICLE 23 - ARBITRATION Subject to Article 19.2 and without prejudice to Article 14 , any dispute, controversy or claim arising out of or relating to, this Agreement, or the breach, termination or invalidity thereof, shall be finally settled by arbitration in accordance with the UNCITRAL Arbitration Rules in effect at the time of such dispute. Arbitration under this Agreement shall be conducted by three (3) arbitrators, each party having the power to appoint one of the arbitrators. The third arbitrator shall be selected in accordance with the UNCITRAL Rules, as shall either of the other two arbitrators if, after a period of 30 Days from receipt of a written demand for arbitration, no such arbitrator has been appointed. In the selection of any arbitrator, consideration shall be given to the arbitrator's familiarity with power contracts and experience in dispute resolution between parties, as a judge or otherwise. The arbitrators shall have the authority to issue appropriate remedies including monetary judgments and specific performance of this Agreement after taking into consideration any appropriate amendments proposed by such arbitrators. Any decision by the arbitrators shall be binding and non-appealable, and maybe enforced by any court of competent jurisdiction. The place of arbitration shall be Singapore, or such other site as may be agreed by the Parties. The language to be used in the arbitration proceedings shall be English. 49 ARTICLE 24 - IMMUNITY To the extent that NPC may in any jurisdiction claim for itself or its assets or revenues immunity from suit, execution, attachment (whether in aid of execution, before judgment or otherwise) or other legal process and to the extent that in any such jurisdiction there may be attributed to itself or its assets or revenues such immunity (whether or not claimed), NPC agrees not to claim and irrevocably waives such immunity to the full extent permitted by the laws of such jurisdiction. ARTICLE 25 - EFFECT OF HEADINGS Article, Part, Article, and/or paragraph headings appearing in this Agreement are inserted for convenience only and shall not be construed as interpretation of text. ARTICLE 26 - SEVERABILITY If any term of this Agreement is finally declared to be invalid by competent courts, the other terms hereof shall not thereby be affected or impaired and shall continue in full force and effect and the Parties shall, in good faith, seek to negotiate valid substitute provisions which shall as nearly as possible preserve the commercial balance between them. ARTICLE 27 - LIABILITY 27.1 LIMIT OF LIABILITY. ------------------- (a) Except in the case of intentional breach or gross negligence, the liability of SPCC to NPC, to the extent the loss or damage suffered by NPC is attributable to SPCC'S failure to achieve a Milestone or to supply Contracted Capacity, Net Electrical Output or Ancillary Services, or to maintain the 60% plant Thermal Efficiency in accordance with this Agreement shall be limited to the payment of the specific amounts mentioned in Article 3.10 and the Third Schedule and the loss of income from application of the penalties mentioned in the Eighth Schedule, at the times mentioned in this Agreement. (b) Except in the case of intentional breach or gross negligence, the liability of NPC to SPCC for any breach by it of this Agreement on or after the Commercial Operation Date, to the extent the loss or damage suffered by SPCC is attributable to its being prevented from supplying Contracted Capacity, Net Electrical Output or Ancillary Services, shall be limited to the payment of Availability Fees at the times mentioned in this Agreement, the penalties, if any, awarded by the Expert pursuant to Article 4.6.3 of this Agreement, and, if such breach results in termination of this Agreement by SPCC, to the payment of the Termination Price. (c) Without prejudice to Article 4.7, and except in the case of intentional breach or gross negligence, the liability of NPC for any breach by it of this Agreement before the Commercial Operation Date, to the extent the loss or damage suffered by SPCC is attributable to SPCC's being delayed in 50 the prosecution of the Project, shall be limited to the payment of the reasonable additional costs and expenses incurred by SPCC as a consequence thereof, the penalties, if any, awarded by the Expert pursuant to Article 4.6.3 of this Agreement, and, if such breach results in termination of this Agreement by SPCC, to payment of the specific amounts mentioned in Article 7.5.1(b). 27.2 NPC INDEMNITY. NPC shall defend, indemnify and hold harmless SPCC, and its -------------- officers and employees, from and against any claim of any third party for loss, damage, cost or expense suffered as a result of any interruption of electricity supply or any other disruption or surge of electricity supply arising out of or in connection with this Agreement, howsoever occasioned, and NPC shall indemnify SPCC against any loss, cost or expense resulting from damage to the Cogeneration Power Production Facility caused or resulting from any interruption or disruption or surge of electricity along the Transmission Line, unless and to the extent that such loss, cost or expense would have been avoided had any safety and protective equipment installed on the Site by SPCC not failed to operate within the specifications agreed between NPC and SPCC, except to the extent the result of gross negligence or willful misconduct by SPCC. 27.3 CROSS INDEMNITY. Subject to Article 27.1 and 27.2, each of NPC and SPCC ---------------- ("Indemnifying Party") shall defend, indemnify and hold harmless the other, its directors, officers, employees and agents (including but not limited to affiliates and contractors and their employees) from and against all liabilities, damages, losses, penalties, claims, demands, suits, costs, expenses (including reasonable attorney's fees and expenses) and proceedings of any nature whatsoever for bodily injury (including death) or property damage (but not economic loss or any other consequential damage) that result from the performance under this Agreement by or on behalf of that Party (including, with respect to SPCC, the engineering, design, construction, financing, purchase, acquisition, acceptance, delivery, ownership, possession, operation, use, leasing, maintenance, repair, reconditioning, return, abandonment or other application or disposition of the Cogeneration Power Production Facility and any fuel, equipment, materials or supplies used therein, by-products (including steam, waste products or emissions therefrom)), except to the extent that such injury and/or any damage is attributable to the negligent or intentional act or omission of the Party seeking to be indemnified or its directors, officers, employees, representatives or agents); in the event such injury or damage results from the joint or concurrent negligent or intentional act or omission of the Parties, each shall be liable under this indemnification for the proportion attributable to its relative degree of fault. ARTICLE 28 - EFFECTIVE DATE AND CONDITIONS PRECEDENT 28.1 EFFECTIVE DATE -------------- 28.1.1 Within ten (10) Days from the execution of this Agreement by the Parties, SPCC shall deliver to NPC (each in form and substance satisfactory to NPC): (i) copies of the memorandum and articles of incorporation of SPCC, certified as true and correct by a director of SPCC; 51 (ii) a certificate of a director of SPCC, confirming the approval of the board of directors of SPCC to the execution, delivery and performance of SPCC of this Agreement; (iii) the Proponents' Agreement, duly executed by all persons (other than NPC and SPCC Philippines), expressed to be the Party thereto; (iv) a certificate of a director or officer of each Proponent, confirming the approval of the board of directors of such Proponent to the execution, delivery and performance by such Proponent of the Proponents' Agreement; and (v) the Development Bond; except to the extent waived by NPC. If SPCC fails so to deliver all of these items, at NPC's option this Agreement shall immediately terminate and be of no force or effect. 28.1.2 The Effective Date shall be the date on which last occurs the following ("Conditions Precedent"): (i) the delivery to SPCC of a certificate of the Corporate Secretary of NPC confirming the approval of the National Power Board to the execution, delivery and performance by NPC of this Agreement. (ii) the delivery to SPCC of a legal opinion of the General Counsel of NPC in the form of set out in the Thirteenth Schedule; (iii) Notice to Proceed issued by NPC to SPCC in the form and substance required under Law; (iv) the receipt by NPC and delivering to SPCC of a legal opinion of the Secretary of Justice of the Republic of the Philippines as to the validity, enforceability and binding effect of the Performance Undertaking; (v) the receipt by NPC of the registration by the Bangko Sentral ng Pilipinas of the Build Own Operate scheme covered by this Agreement which is required to allow NPC to purchase foreign exchange from the Philippine banking system to service payments due under this Agreement; (vi) the receipt by SPCC of a Performance Undertaking of the Republic of the Philippines in the form and terms of the Eleventh Schedule which it requires to perform its obligations under this Agreement; (vii) the receipt by SPCC of an opinion of the National Electrification Administration and the Energy Regulatory Board confirming that the operation by SPCC of the Cogeneration Power Production Facility will not constitute a public utility so as to require a franchise, certificate of public convenience or other similar license which it requires to perform its obligations under this Agreement; 52 (viii)the registration of SPCC Philippines with the Securities and Exchange Commission of the Republic of the Philippines which it requires to perform its obligations under this Agreement, and delivering to NPC copies of its organizational documents, certified as true and correct by a director of SPCC Philippines, together with the Accession Undertaking, duly executed by SPCC and SPCC Philippines, and a counterpart of the Proponents' Agreement, duly executed by SPCC Philippines; (ix) the registration of SPCC Philippines with the Board of Investments of the Republic of the Philippines as a pioneer enterprise under the Omnibus Investments Code of 1987 which it requires to perform its obligations under this Agreement, containing the conditions and the incentives which a registered enterprise may be entitled to under the 1996 Investments Priorities Plan which SPCC has based its proposal; and (x) the receipt by SPCC of a notice from the Bureau of Internal Revenue stating that SPCC has achieved a zero rating for its sale of electricity to NPC, subject to no conditions or qualifications; except to the extent waived by SPCC in respect of Articles 28.1.2 (i), (ii), (iii), (iv), and (x). 28.1.3 If the Conditions Precedent mentioned in Articles 28.1.2 (i), (iii) and (iv) have not been satisfied within three months after the Contract Signing Date, SPCC shall have the right to terminate this Agreement, whereupon NPC shall return the Bid Bond or Development Bond, whichever is effective, to SPCC and this Agreement shall be of no further force or effect. Each Party shall bear its own costs and expenses. 28.1.4 If the Conditions Precedent mentioned in Articles 28.1.2 (v) to (ix) above have not been satisfied within six months after the Contract Signing Date, this Agreement shall terminate (unless the Parties otherwise agree) and be of no further force or effect and each Party shall bear its own costs and expenses. The Development Bond will be returned to SPCC. 28.1.5 If the Condition Precedent mentioned in Article 28.1.2(x) above has not been satisfied by September 30, 1997, this Agreement shall terminate (unless such condition precedent is waived by SPCC) and be of no further force or effect and each Party shall bear its own costs and expenses. The Development Bond will be returned to SPCC. 28.1.6 If the Condition Precedent mentioned in Article 28.1.2 (ii) above has not been satisfied within seven months after the Contract Signing Date, this Agreement shall terminate (unless such condition precedent is waived by SPCC) and be of no further force or effect and each Party shall bear its own costs and expenses. The Development Bond will be returned to SPCC. 28.2 CONDITIONS PRECEDENT. Until the Effective Date, except with respect to --------------------- Article 6.14 and other than as mentioned in Article 28.1, no Party shall have any obligation to the other. However, all the provisions of this Agreement related to 53 the full enjoyment and enforcement of the obligations mentioned in this Article 28.1 (including those in relation to dispute resolution and giving of the notices) shall be effective on and from the Contract Signing Date to the extent they so relate. 28.3 TERMINATION FOR FAILURE TO OBTAIN CERTAIN GOVERNMENT APPROVALS. If SPCC -------------------------------------------------------------- fails to obtain the final approval and registration by the Bangko Sentral ng Pilipinas for: (i) any bridge or other loans to be made in non-Philippine currency by the shareholders or any other party to SPCC and for the payment of interest thereon and the payment of the principal thereof in foreign currency; (ii) incurring by SPCC of non-Philippine currency debt from international financial institutions or agencies, including International Finance Corporation and Asian Development Bank, the Overseas Private Investment Corporation, the Multilateral Investment Guarantee Agency, the United States Agency for International Development, for the purpose of repaying bridge loans (if any) extended by Shareholders or any other party, and for meeting the balance of the capital requirements of the Project; (iii)repatriation of Shareholders' investment in SPCC and the profits of such investment as allowed by the laws, rules and regulations of the Republic of the Philippines on the date the investment is made; and (iv) SPCC to receive payment in dollars as provided herein and to maintain an offshore dollar account or accounts, and such failure is not due to the fault of SPCC, then SPCC at its option may terminate the Agreement and SPCC shall have no further liability whatsoever hereunder and NPC shall not be entitled to draw upon any Bond. 54 ARTICLE 29 - COUNTERPART EXECUTION This Agreement may be executed in any number of counterparts which, when taken together, shall constitute one and the same agreement. AS WITNESS the hands of the duly authorized representatives of the Parties - ---------- hereto on the 10th day of September, 1997. NATIONAL POWER CORPORATION By: /s/ Guido Alfredo Delgado ------------------------- GUIDO ALFREDO DELGADO President SAN PASCUAL COGENERATION COMPANY INTERNATIONAL B.V. By: /s/ Martin D. Considine /s/ Robert E. Driscoll ----------------------- ---------------------- MARTIN D. CONSIDINE ROBERT E. DRISCOLL Managing Director Managing Director Signed in the presence of: /s/ Ariel C. Vinoya /s/ Patrick R. Hale ----------------------- ---------------------- 55 EX-10.46 3 PURCHASE AGREEMENT BETWEEN "EGAT" & "GULF" EXHIBIT 10.46 POWER PURCHASE AGREEMENT (INITIALED COPY) Agreement regarding Power Purchase Agreement relating to 734 MW Power Plant in Prachuab Kiri Khan Province, Kingdom of Thailand between Electricity Generating Authority of Thailand and Gulf Power Generation Company Limited ----------------------- With regard to the Power Purchase Agreement for the 734 MW coal-fired power plant to be located in Prachuab Kiri Khan Province (hereinafter the "Agreement") which the Electricity Generating Authority of Thailand ("EGAT") and Gulf Power Generation Company Limited ("GULF") are executing contemporaneously with this letter (an execution copy of which is attached hereto), EGAT and GULF (hereinafter referred to as the "Parties") agree as follows: 1. Unless otherwise defined herein, capitalized terms in this letter shall have the same meaning as in the Agreement. 2. EGAT agrees that on or prior to the date that is the earlier of the Scheduled Financial Close Date and the date of Financial Close, Section 19.1 of the Agreement and paragraph 4.1 Schedule 2 thereto, shall be amended, if necessary, so as to extend to GULF terms that are no less favorable than the terms and conditions associated with comparable provisions in any other power purchase agreement executed, or subsequently amended or supplemented by EGAT, as a result of EGAT's Request for Proposals - 1994 Independent Power Solicitation (the "1994 Solicitation"). Notwithstanding the foregoing, GULF shall not be entitled to any such amendments pursuant to this provision for terms which are concluded with any other IPP project as a result of dispute resolution which has yielded a binding decision by an expert or by arbitration under or in connection with any power purchase agreement. 3. After the execution of this letter, subject to paragraph 2 hereof, GULF shall not claim any relief from its obligations under the Agreement on the basis of Force Majeure or Governmental Force Majeure due to issuance by the Thailand Ministry of Finance of a notification on 2 July 1997 providing that the value of the Thai Baht will be set by conditions in the foreign exchange markets (the "Notification"). Other than amendments to the Agreement in accordance with paragraph 2 hereof, there shall not be any revisions to the Agreement with respect to the issuance of the Notification or the adoption of the managed float of the Thai Baht thereunder. 4. EGAT agrees that, at all times prior to the date which is the earlier of the Scheduled Financial Close Date and the date of Financial Close, the terms of this Agreement and Schedules thereto shall be amended, if necessary, so as to extend to GULF terms (other than terms which are related to a power project's specific technical characteristics) no less favorable to GULF than the terms and conditions included in any other Stage 2 power purchase agreement executed, or subsequently amended or supplemented, by EGAT in connection with the 1994 Solicitation (commonly referred to as Stage 2 of Round One of EGAT's IPP Program) with respect to: a. the rights of the Generator or the obligations of EGAT regarding any compensation to be paid by EGAT as a result of the termination of the Agreement following a default by EGAT; b. the list and definitions of Force Majeure and Governmental Force Majeure; c. except with regard to the period of time Force Majeure must continue before EGAT may exercise its termination rights under Section 14.6.2 of the Agreement, the termination rights in respect of, or the nature or categories of compensation to be paid to a power producer in the event of, the occurrence and continuation of an event of Force Majeure or Governmental Force Majeure or the factors or procedures for determining such compensation; and d. the method of payment set forth in Section 19.3 of the Agreement. 5. EGAT agrees to extend to GULF material revisions in the manner in which the application of Schedule 2 is administered with regard to any other power purchase agreement for coal fired generation that is executed by EGAT as a result of the 1994 Solicitation, provided such revisions are not related to power project specific technical characteristics and (i) remedy demonstrated problems with the administration of Schedule 2 and are of a generic nature which warrant application to all of the power purchase agreements for coal fired generation that have been executed by EGAT as a result of the 1994 Solicitation, and (ii) would restrict the application of or limit GULF's exposure to the DRA, DDF and DSN deductions set forth in Schedule 2 of this Agreement. 6. The Parties shall confer together in good faith concerning appropriate accounting and tax treatment for the New Transmission Facilities and documentation related thereto, including potential amendments to the Agreement, if applicable. 7. The Parties agree that this letter and the Agreement together contain or expressly refers to the entire Agreement between the Parties with respect to the subject matter addressed thereby. Each of the Parties acknowledges and confirms that it does not enter into this letter or the Agreement in reliance on, and the Parties expressly waive any rights associated with, any representation, warranty, commitment, obligation or other undertaking by the other Parties not expressly reflected in this letter and the Agreement. Any dispute under or concerning this letter shall be resolved in accordance with Section 15 of this Agreement, which are incorporated by reference herein. Acknowledged and agreed as of the date set forth below On behalf of the On behalf of the ELECTRICITY GENERATING GULF POWER GENERATION AUTHORITY OF THAILAND (EGAT) COMPANY LIMITED (GULF) By: By: ------------------------- -------------------------- (Mr. Viravat Chlayon) (Mr. Sarath Ratanavadi) Governor Director December 1997 December 1997 Bangkok, Thailand Bangkok, Thailand By: -------------------------- (Mr. Gerard P. Loughman) Director December 1997 Bangkok, Thailand CONTRACT NO. IPP/ 41-107 POWER PURCHASE AGREEMENT BETWEEN GULF POWER GENERATION COMPANY LIMITED AND ELECTRICITY GENERATING AUTHORITY OF THAILAND SIGNED ON DECEMBER 22, 1997 CONTENTS
SECTION PAGE 1. DEFINITIONS AND INTERPRETATIONS.................................................... 2 1.1 Definitions.................................................................. 2 1.2 Interpretation............................................................... 12 1.3 Calculation Values........................................................... 13 1.4 Table of Contents and Headings............................................... 13 2. FACILITY DEVELOPMENT AND CONNECTION ARRANGEMENTS................................... 13 2.1 Obligations to Construct..................................................... 13 2.2 Construction and Licensing of the Facility................................... 13 2.3 Independent Engineer and Progress Reports on Construction.................... 14 2.4 Metering..................................................................... 15 2.5 Grid Code Equipment and Communication Requirements........................... 17 2.6 Rights-Of-Way and Easements.................................................. 17 2.7 Provision of Information and Consultation Relating to EGAT Transmission Facilities...................................................... 18 2.8 Completion of New Transmission Facilities.................................... 18 2.9 Inspection and Energizing of the Connection Point and Facility Switchyard................................................................... 21 2.10 Synchronizing and Commercial Operation....................................... 22 2.11 Testing...................................................................... 24 2.12 Review by EGAT............................................................... 26 3. PROVISION AND PURCHASE OF AVAILABILITY AND ELECTRICITY........................................................................ 26 3.1 Obligation to Provide Dependable Contracted Capacity and Contracted Operating Characteristics.................................................... 26 3.2 Compliance with the Grid Code................................................ 27 3.3 Sale and Purchase of Electricity............................................. 27 3.4 Provision of Standby Service................................................. 28 3.5 Dispatch Instructions........................................................ 28 3.6 Operation and Maintenance (O&M) Reports...................................... 28 4. DELIVERY OF ELECTRICITY............................................................ 28 4.1 Quality of Supply............................................................ 28 4.2 Title and Risk of Loss....................................................... 29 4.3 Failure of the System........................................................ 29
Page i 5. AVAILABILITY PAYMENTS............................................................ 29 5.1 Calculation of Availability Payments....................................... 29 5.2 Confirmation and Payment of Availability Payments.......................... 29 5.3 Notices of Availability and Declared Operating Characteristics............. 29 6. ENERGY PAYMENTS.................................................................. 30 6.1 Entitlement to and Calculation of Energy Payments.......................... 30 6.2 Confirmation and Payment of Energy Payments................................ 30 7. MINIMUM TAKE..................................................................... 30 8. ENVIRONMENTAL QUALITY REQUIREMENTS............................................... 32 9. FUEL SUPPLY...................................................................... 32 9.1 Fuel Supply Obligations.................................................... 32 9.2 Subsequent Fuel Supply Agreements.......................................... 33 9.3 Fuel Stock................................................................. 33 10. CRITICAL DATES AND DURATION OF AGREEMENT......................................... 34 10.1 Initial Term............................................................... 34 10.2 Survival of Rights on Termination.......................................... 34 10.3 Extension of Agreement..................................................... 34 10.4 Critical Dates............................................................. 34 10.5 Extension of Critical Dates and Term....................................... 35 11. CONTRACTED MILESTONES............................................................ 35 12. DEFAULT AND TERMINATION.......................................................... 36 12.1 Termination by the Generator............................................... 36 12.2 Termination by EGAT........................................................ 37 12.3 Step-In Rights............................................................. 39 12.4 Other Rights to Terminate.................................................. 42 13. SECURITIES AND LIQUIDATED DAMAGES................................................ 42 13.1 Establishment of Development Security...................................... 42 13.2 EGAT's Right to Retain Development Security as Liquidated Damages.......... 42 13.3 Liquidated Damages for Contracted Capacity Deficiencies.................... 44 13.4 Payments from the Security................................................. 44 13.5 Additional Security........................................................ 44 13.6 Reasonable Liquidated Damages.............................................. 46
Page ii 14. FORCE MAJEURE.................................................................. 46 14.1 Overview................................................................ 46 14.2 Notice of Force Majeure and Consequences................................ 47 14.3 Limitations............................................................. 48 14.4 Payment Rights and Obligations During Force Majeure..................... 48 14.5 Payments During Extension of Term....................................... 51 14.6 Termination............................................................. 52 14.7 Reconstruction.......................................................... 53 15. DISPUTE RESOLUTION............................................................. 54 15.1 Resolution.............................................................. 54 15.2 Arbitration............................................................. 54 16. LIMITATION OF LIABILITY........................................................ 56 16.1 Indemnification......................................................... 56 16.2 Consequential Damages................................................... 57 17. CHANGE-IN-LAW.................................................................. 57 17.1 Tax Change Adjustment................................................... 57 17.2 Change-in-Law Adjustment................................................ 58 17.3 BOI Privileges.......................................................... 60 18. CONFIRMATION STATEMENT......................................................... 60 18.1 Confirmation of Availability and Metered Energy......................... 60 18.2 Access to Information................................................... 60 18.3 Review of Confirmation Statement and Meter Reconciliation Statement..... 60 18.4 Disputes................................................................ 61 18.5 Final Confirmation Statement............................................ 61 18.6 Disputes Limitation..................................................... 61 18.7 Effect of Confirmation Statement........................................ 61 18.8 Energy Payment Adjustments.............................................. 61 18.9 Interference with Metering.............................................. 62 19. BILLING AND PAYMENT............................................................ 62 19.1 Payment Invoice/Credit Note............................................. 62 19.2 Other Payments.......................................................... 63 19.3 Payment Procedure....................................................... 63 19.4 Application of Payments................................................. 63
Page iii 19.5 Interest.................................................................. 64 19.6 Disputed Items............................................................ 64 19.7 Taxes and Fines........................................................... 64 19.8 Set-Off................................................................... 65 20. INDEXATION....................................................................... 65 21. CONFIDENTIALITY AND ANNOUNCEMENTS................................................ 66 21.1 General Restrictions on the Parties....................................... 66 21.2 Exceptions................................................................ 66 21.3 Internal Procedures....................................................... 67 21.4 Public Announcements...................................................... 67 22. INSURANCE AND INDEMNITIES........................................................ 67 22.1 Insurance Required........................................................ 67 22.2 Endorsements.............................................................. 68 22.3 Certificates Required..................................................... 68 22.4 Application of Proceeds................................................... 69 23. REPRESENTATIONS AND WARRANTIES................................................... 69 24. EQUITY UNDERTAKING............................................................... 71 24.1 Restrictions on Transferability........................................... 71 24.2 Qualifications to Equity Transfer Restrictions............................ 71 25. MISCELLANEOUS PROVISIONS......................................................... 72 25.1 Amendments................................................................ 72 25.2 Waivers of Rights......................................................... 72 25.3 Notice.................................................................... 72 25.4 Assignment................................................................ 73 25.5 Effect of Illegality...................................................... 74 25.6 Entire Agreement.......................................................... 75 25.7 Counterparts.............................................................. 75 25.8 Currency.................................................................. 75 25.9 Language.................................................................. 75 25.10 Third Parties............................................................. 75 25.11 Inconsistencies and Conflicts............................................. 75 26. GOVERNING LAW AND JURISDICTION................................................... 76 26.1 Governing Law.............................................................. 76
Page iv 26.2 Waiver.................................................................... 76 26.3 Arbitration............................................................... 76 27. PRIVATIZATION OF EGAT............................................................ 76 28. PERMISSION UNDER EGAT ACT........................................................ 76 SIGNATURES....................................................................... 77
Page v THIS AGREEMENT (the AGREEMENT) is made on this 22 day of December, 1997 BETWEEN (1) GULF POWER GENERATION CO., LTD., incorporated under the laws of Thailand, represented by Mr. Sarath Ratanavadi, Director and Mr. Gerard P. Loughman, Director, with its registered address at 11th Floor, M. Thai Tower 1, All Seasons Place, 87 Wireless Road, Lumpini, Phatumwan, Bangkok 10330, Thailand (the GENERATOR); and (2) ELECTRICITY GENERATING AUTHORITY OF THAILAND, represented by Mr. Viravat Chlayon, Governor, with its registered address at 53 Charansanitwong Road, Bang Kruai, Nonthaburi 11130, Thailand (EGAT). The Generator and EGAT are also each referred to herein as a PARTY and collectively as the PARTIES. WHEREAS: (A) The Government of Thailand has announced the policy of encouraging and promoting the development of independent power producers for generating electricity to meet electricity demands in Thailand. (B) To advance such Governmental policy, EGAT and the Generator have entered into this Agreement setting out the terms on which the Generator has agreed to develop, construct, finance, operate and maintain a 734 MW coal-fired electricity generating plant at Boh Noak Subdistrict, Kui Buri District, Prachuab Khiri Khan Province, Thailand to provide electricity to EGAT in accordance with the terms and conditions of this Agreement. NOW IT IS HEREBY AGREED as follows: Page 1 1. DEFINITIONS AND INTERPRETATIONS 1.1 DEFINITIONS Unless otherwise defined herein, capitalized terms used herein shall have the following meanings, whether used in the singular or in the plural: ACCESS RIGHTS This term shall have the meaning assigned thereto in Section 2.6.1; ACTUAL AVAILABILITY The Availability (in MWh) provided by a Unit during a Settlement Period or other period as the context requires, determined in accordance with Schedule 2; ADDED FACILITY CHARGE This term shall have the meaning assigned thereto in Section 2.8.16; AFFILIATE When applied to a Person, any other Person controlling, controlled by or under common control with such first-named Person, provided that (i) for purposes of Section 24, any Person that owns directly or indirectly securities having fifty percent (50%) or more of the voting power for the election of directors or other governing body of a corporation or fifty percent (50%) or more of the partnership or other ownership interests of any other Person (other than as a limited partner of such Person) will be deemed to control such corporation or other Person, and (ii) for any purpose other than Section 24, any Person that owns directly or indirectly securities having ten percent (10%) or more of the voting power for the election of directors or other governing body of a corporation or ten percent (10%) or more of the partnership or other ownership interests of any other Person (other than as a limited partner of such Person) will be deemed to control such corporation or other Person; AGREEMENT This Power Purchase Agreement and the Schedules hereto; AVAILABILITY The capability of a Unit (in MWh) to provide generating capacity and electricity to EGAT, regardless of the level at which EGAT dispatches the Unit, and AVAILABLE shall be construed accordingly; AVAILABILITY NOTICE A statement in the form set out in Schedule 15 declaring or revising the capability of a Unit to provide (i) generating capacity up to its Page 2 Dependable Contracted Capacity, and (ii) the other Contracted Operating Characteristics set out in Paragraph 2 of Schedule 1; AVAILABILITY PAYMENT Payment made by EGAT to the Generator for the Actual Availability provided by the Units as determined in accordance with Schedule 2; BACK-UP METERING EQUIPMENT The back-up metering equipment and associated devices as described in Schedule 13; BAHT The lawful currency of the Kingdom of Thailand; BILLING PERIOD The period beginning on the Commercial Operation Date of the First Unit and ending on the last day of the month in which that date occurs, each full month in a Contract Year, and the period beginning on the first day of the month in which the Term expires and ending on the day the Term expires; BTU British Thermal Units; BUSINESS DAY Any weekday from Monday through Friday, excluding in each calendar year (i) not more than sixteen (16) holidays designated by EGAT no later than December 20 of the preceding year, and (ii) any other holidays designated by the Bank of Thailand for such calendar year; CHANGE-IN-LAW Any of the following events occurring after the Execution Date as a result of any action by any Governmental Authority: (i) a change in or repeal of an existing Law, (ii) an enactment or making of a new Law, and (iii) a change in the manner in which a Law is applied or in the application or interpretation thereof (including any interpretation of environmental standards); COMMERCIAL OPERATION DATE The date agreed by EGAT and the Generator in accordance with Section 2.10.2 with respect to each Unit; COMMERCIAL OPERATIONS TEST The series of tests to determine the net generating capacity and Operating Characteristics of a Unit as set out in Schedule 14; CONFIRMATION STATEMENT A statement in the form set out in Schedule 15 confirming the capability of a Unit to provide (i) generating capacity up to its Dependable Contracted Capacity, and (ii) the other Page 3 Contracted Operating Characteristics set out in Paragraph 2 of Schedule 1; CONNECTION The link between the Facility and the EGAT System; CONNECTION POINT The physical point or points where the Facility and the New Transmission Facilities are connected, which shall be the takeoff structure in the Facility switchyard, as identified in Schedules 10 and 13; CONTRACTED AVAILABLE HOURS This term shall have the meaning assigned thereto in Schedule 2; CONTRACTED CAPACITY The rated net power output (expressed in MW) of each Unit as set out in Schedule 1; CONTRACTED OPERATING The Operating Characteristics of each Unit as set CHARACTERISTICS out in Schedule 1, exclusive of Paragraph 3.2 thereof; CONTRACT YEAR For the first calendar year of the Facility's operation, the period which begins on the Commercial Operation Date of the First Unit and ends on December 31, and thereafter during the Term, each annual period commencing on January 1 and ending on December 31 (or on the last day of the Term); CONTROL For purposes of Section 27.1, control of any Person by a Governmental Authority shall mean direct or indirect ownership by such Governmental Authority of fifty percent (50%) or more of the securities having ordinary voting power for the election of directors or other governing body (for a corporation) or fifty percent (50%) or more of a partnership interest (excluding interests as a limited partner) or other ownership interests of another Person; DECLARED OPERATING The Operating Characteristics of a Unit as CHARACTERISTICS declared from time to time in accordance with Schedule 2; DEFAULT RATE A rate equal to two percent (2%) over the Overdraft Rate; DEPENDABLE CONTRACTED The maximum continuous net generating capacity of CAPACITY a Unit (measured in MW or kW as appropriate) established in accordance with Section 2.11; Page 4 DESIGN LIMITS The operational limits of a Unit as set out in Schedule 1 and revised from time to time as agreed by the Parties; DEVELOPMENT SECURITY A direct pay letter of credit or letter of guarantee from one or more Thai banks or a cash sum held by an escrow agent provided to EGAT by the Generator in accordance with Section 13.1; DISPATCH The direction by EGAT's Control Center to commence, increase, decrease, continue or cease the delivery of electricity into the EGAT System; DISPATCH INSTRUCTION An instruction issued by EGAT's Control Center to the Generator pursuant to the Grid Code to perform one or more of the Declared Operating Characteristics or other operation permitted by this Agreement or the Grid Code; EARLIEST COMMERCIAL The dates set out in Section 10.4 with respect to OPERATION DATE each Unit (or as adjusted in accordance with Section 10.5) on or after which the Unit may begin commercial operation pursuant to Section 2.10.2; EGAT The Electricity Generating Authority of Thailand; EGAT ACT The Electricity Generating Authority of Thailand Act, B.E. 2511, as amended from time to time; EGAT'S CONTROL CENTER EGAT's National or Regional Control Centers set up for the purposes of Dispatch of generating units, external interconnectors and the EGAT System; EGAT SYSTEM The bulk power network controlled or used by EGAT for the purpose of generating, transmitting and distributing electricity to EGAT's customers; EMERGENCY CONDITIONS A condition or situation that in EGAT's reasonable judgment is likely to cause (i) an imminent physical threat of danger to life, health or property, or (ii) a significant disruption on the EGAT System that would adversely affect EGAT's ability to meet its obligation to provide safe, adequate and reliable supply of electricity to its customers; Page 5 ENERGIZING DATE The date determined in accordance with Section 2.10.1 on which the Connection is energized for the pre-operation testing and start up of the First Unit; ENERGY PAYMENT Payment made by EGAT to the Generator for the electrical energy generated by a Unit and delivered to the EGAT System as determined in accordance with Schedule 3; EPC CONTRACT The agreement or agreements for the engineering, design, supply, construction, erecting and testing of the Facility, as modified or supplemented from time to time; EVENT OF DEFAULT An event, condition or circumstance described in Section 12.1.1 or 12.2.1; EXECUTION DATE The date on which this Agreement is signed by the Parties; EXPERT Any person appointed by agreement between the Parties pursuant to Section 15.1.2; FACILITY The two Units and the Generator's associated buildings, structures, roads, and other appurtenances, not including the New Transmission Facilities; FACILITY SWITCHYARD The Facility's 500kV equipment, including the Unit auxiliary transformer, associated buildings, structures, roads and other related appurtenances; FINAL CONFIRMATION This term shall have the meaning assigned thereto STATEMENT in Section 18.5; FINANCIAL CLOSE When all relevant Financing Documents required to fund fully the development, acquisition, construction, ownership, and initial working capital for the Facility have been duly executed and either (i) an initial funding thereunder has occurred, or (ii) EGAT shall have received a certificate of the lead bank, agent or trustee acting for the Financing Parties (or any other evidence reasonably satisfactory to EGAT) confirming that all conditions precedent to the initial drawdown of funds thereunder have been satisfied or waived by the Financing Parties where the Generator does not need to make a drawdown of funds thereunder to so fund the Facility; Page 6 FINANCING DOCUMENTS The agreements for the making available of any loans, credit facilities, notes (including floating rate notes and commercial paper), bonds, subordinated debt or other funds other than equity or equity-related funds and including working capital and any letters of credit (and related agreements), security agreements, swap agreements, and any other hedging agreements and any other documents relating to the financing or refinancing of the New Transmission Facilities or the Access Rights and of the development, construction, acquisition, ownership, operation and maintenance of the Facility; FINANCING PARTIES Any Person which provides loans or other financing to the Generator as evidenced by or pursuant to the Financing Documents; FIRST UNIT The first of the two Units to be installed in accordance with the schedule set out in Section 10.4; FORCE MAJEURE This term shall have the meaning assigned thereto in Section 14.1.1; FUEL Coal which meets the specifications set out in the Fuel Purchase Agreement; FUEL PURCHASE AGREEMENT The Fuel sales contract between the supplier of Fuel and the Generator; FUEL STOCK The stock of Fuel to be arranged by the Generator in accordance with Section 9.3; FUEL TRANSPORTATION The agreement executed by the Generator to AGREEMENT transport Fuel to the Site if arrangements for such transport are not fully provided for in the Fuel Purchase Agreement; GENERATOR This term shall have the meaning assigned thereto in the opening recitals of this Agreement; GJ Gigajoule; GOVERNMENTAL APPROVAL Any approval, consent, concession, decree, permit, waiver, exemption or approval from, or filing with, or notice to, any Governmental Authority; GOVERNMENTAL AUTHORITY The Government of Thailand and any ministry, department, political subdivision, Page 7 instrumentality, agency, authority (excluding EGAT or any successor to EGAT's interests under this Agreement), corporation or commission under the direct or indirect control of the Government of Thailand, or the Parliament of Thailand, or any court or tribunal in Thailand; GOVERNMENTAL FORCE This term shall have the meaning assigned thereto MAJEURE in Section 14.1.2; GRID CODE The code issued by EGAT and attached hereto as Schedule 20, which sets forth certain requirements with respect to the coordination of power facilities with the operation of the EGAT System, and as it may be amended, modified or supplemented from time to time; INDEPENDENT ENGINEER The engineering firm appointed by the Generator in accordance with Section 2.3.1; KW Kilowatt; KWH Kilowatt-hour; LAW Any legislation, statute, act, Royal decree, rule, order, treaty, regulation or announcement (excluding the Grid Code), or any interpretation thereof, which has been enacted, issued or promulgated by any Governmental Authority; METERING EQUIPMENT The Primary Metering Equipment and Back-Up Metering Equipment as described in Schedule 13; METERING POINT The point on the Site where the Metering Equipment is located, as further described in Schedule 13; METER RECONCILIATION A report issued in accordance with Section 18.1 STATEMENT following any meter test conducted pursuant to Section 2.4.3; MINIMUM TAKE LIABILITY This term shall have the meaning assigned thereto in Section 7; MW Megawatt; MWH Megawatt-hour; NET CAPACITY TEST The test to determine the net generating capacity of a Unit as set out in Schedule 14; Page 8 NET ELECTRICAL GENERATION For any period, the net electrical energy delivered by the Facility or a Unit as the context requires (measured in kWh or MWh as appropriate at the Metering Point) into the EGAT System during such period; NEW MAIN TRANSMISSION The 500 kV double circuit transmission line from LINE (NMTL) Bang Saphan to the NTF Connection Point and from the NTF Connection Point to Chom Bung to be constructed by EGAT; NEW TRANSMISSION Extensions and modifications to the EGAT System as FACILITIES (NTF) described in Schedule 10 made in order to allow connection of the Facility to the EGAT System; NOTICE A statement or notice in one of the forms set out in Schedule 15 declaring, revising or confirming the capability of a Unit to provide its Contracted Operating Characteristics; NTF CONNECTION POINT The physical point or points where the New Transmission Facilities and the New Main Transmission Line are connected, as identified in Schedule 10; NTF COMMISSIONING The date determined in accordance with Section COMPLETION DATE 2.8.14 on which the New Transmission Facilities have successfully completed the final testing and commissioning requirements set out in Schedule 18; NTF ENERGIZING DATE The date determined in accordance with Section 2.8.10 on which the NTF Connection Point is energized; O&M AGREEMENT The operation and maintenance agreement for the Facility between the Generator and the Facility operator; OPERATING CHARACTERISTICS The parameters which define the capability of a Unit to respond to Dispatch Instructions; OUTAGE NOTICE A statement in the form set out in Schedule 15 declaring or revising the period during which a Unit shall be withdrawn from service and the degree to which this affects the Unit's capability to deliver its Contracted Operating Characteristics, as described in Schedule 2; OVERDRAFT RATE The minimum overdraft rate then in effect at Krung Thai Bank Public Company Limited, or its successor; Page 9 PARTY This term shall have the meaning assigned thereto in the recitals of this Agreement; PAYMENT INVOICE/ A statement in the form set out in Schedule 6 CREDIT NOTE issued by the Generator in accordance with Section 19.1; PERSON Any individual, corporation, partnership, joint venture, association, trust, unincorporated organization, Governmental Authority or other entity; PLANNED OUTAGE Any period during which a Unit is wholly or partially withdrawn from service as determined in accordance with the Grid Code; POST EVENT NOTICE A statement given by EGAT in the form set out in Schedule 15 describing a failure by a Unit to deliver the Contracted Operating Characteristics declared in a previous Notice; PRIMARY METERING The Primary Metering Equipment and associated EQUIPMENT devices as described in Schedule 13; PROJECT The design, development, construction, financing, ownership, operation and maintenance of the Facility under the terms of this Agreement; PROJECT AGREEMENTS The EPC Contract, the Fuel Purchase Agreement, the Fuel Transportation Agreement (if any), the Financing Documents, the O&M Agreement, and the Site Agreement; PRUDENT UTILITY PRACTICES The practices, methods and acts engaged in or accepted by a significant portion of the international electric generating industry for facilities or equipment similarly situated to the Facility, the New Transmission Facilities or the New Main Transmission Line that, at a particular time, in the exercise of reasonable judgment in light of the facts known or that reasonably should have been known at the time a decision was made, would be expected to accomplish the desired result in respect of the design, engineering, construction, operation and maintenance of the facilities or equipment associated with the Facility, the New Transmission Facilities or the New Main Transmission Line, in a manner consistent with Law, Governmental Approvals, reliability, safety, economy, environmental protection and the construction, operation and maintenance Page 10 standards recommended by the Facility's equipment suppliers and manufacturers; SCHEDULED COMMERCIAL The date set out in Section 10.4 with respect to OPERATION DATE each Unit (or as adjusted in accordance with Section 10.5) on which the Unit is scheduled to begin commercial operation; SCHEDULED CONSTRUCTION The date set out in Section 10.4 (or as adjusted in COMMENCEMENT DATE accordance with Section 10.5) on which the Generator is scheduled to commence construction of the Facility in accordance with Section 11(i); SCHEDULED ENERGIZING DATE The date set out in Section 10.4 (or as adjusted in accordance with Section 10.5) on which the Connection is scheduled to be energized by EGAT for the pre-operation testing and start up of the First Unit; SCHEDULED FINANCIAL The date set out in Section 10.4 by which the CLOSE DATE Generator is scheduled to complete the Financial Close of the Project; SCHEDULED NTF ENERGIZING The date set out in Section 10.4 (or as adjusted in DATE accordance with Section 10.5) on which the NTF Connection Point is scheduled to be energized by EGAT for the testing and commissioning of the New Transmission Facilities; SECOND UNIT The second of the two Units to be installed in accordance with the schedule set out in Section 10.4; SETTLEMENT PERIOD A period of one (1) hour starting on the hour; SITE The plot of land upon which the Facility is located; SITE AGREEMENT The purchase or lease agreement(s) relating to the Generator's acquisition of a right to occupy and use the Site for the Project; SPONSORS Gulf Electric Company Limited (60%) and MEC International B.V. (40%); TAXES Any tax, charge, tariff, duty or fee of any kind charged, imposed or levied, directly or indirectly, by any Governmental Authority, including any VAT, sales tax, stamp duty, import duty, withholding tax (whether on income, dividends, interest payments, fees, Page 11 equipment rentals or otherwise), tax on foreign currency loans or foreign exchange transactions, excise tax, property tax, registration fee or license, water tax or environmental, energy or fuel tax (including any fee or charge imposed or assessed on the basis of the carbon or calorific content of fuel); TERM The period of this Agreement as specified in Section 10.1, subject to extension in accordance with Sections 10.3 and 10.5; UNIT Either of the Facility's two electrical generating sets, each comprising a coal-fired boiler and a steam turbine generator and ancillary equipment and facilities as described in Schedule 7; and VAT The value added tax in Thailand or such other taxes having the same effect. 1.2 INTERPRETATION In this Agreement (including its Schedules), unless otherwise stated: 1.2.1. Any references to: (a) the Grid Code, or any section, appendix or other provision thereof, shall be construed, at any particular time, as including a reference to the Grid Code, section, appendix or the relevant provision thereof as it may have been amended, modified or supplemented; (b) any agreement (including this Agreement or any Schedule hereto) shall be construed, at any particular time, as including a reference to the relevant agreement as it may have been amended, modified, supplemented or novated; (c) a month shall be construed as a reference to a calendar month; (d) a particular Section or Schedule shall be a reference to the relevant Section or Schedule in or to this Agreement; and (e) a particular paragraph or sub-paragraph, if contained in a Schedule, shall be a reference to the relevant paragraph or sub-paragraph of that Schedule. 1.2.2 Words in the singular may be interpreted as referring to the plural and vice versa, and words denoting natural persons may be interpreted as referring to corporations and any other legal entities and vice versa. 1.2.3. Whenever this Agreement refers to a number of days, such number shall refer to the number of calendar days unless Business Days are specified. A requirement that a payment be made on a day which is not a Business Day shall be construed as a requirement that the payment be made on the next following Business Day. Page 12 1.2.4. The words "include" and "including" are to be construed as being at all times followed by the words "without limitation", unless the context otherwise requires. 1.3 CALCULATION VALUES For the purposes of this Agreement, amounts and values shall be calculated to the number of decimal places indicated in Schedule 4 unless otherwise specified herein. 1.4 TABLE OF CONTENTS AND HEADINGS The table of contents and headings are inserted for convenience only and are not to be applied for purposes of construction and interpretation of this Agreement. 2. FACILITY DEVELOPMENT AND CONNECTION ARRANGEMENTS 2.1 OBLIGATIONS TO CONSTRUCT 2.1.1 The Generator shall design, engineer, construct, test and commission the Facility and the New Transmission Facilities. The Generator shall ensure that the New Transmission Facilities and the Facility Switchyard shall be ready for energizing on or before the Scheduled Energizing Date, and that the First Unit and Second Unit shall be ready for Dispatch on or before their respective Scheduled Commercial Operation Dates. 2.1.2 EGAT shall design, engineer, construct, test, and commission the New Main Transmission Line. EGAT shall energize the NTF Connection Point on or before the Scheduled NTF Energizing Date for testing and commissioning of the New Transmission Facilities and the Facility Switchyard, and to enable Dispatch of the First Unit and Second Unit on or before their respective Scheduled Commercial Operation Dates. 2.2 CONSTRUCTION AND LICENSING OF THE FACILITY The Parties shall comply with the following provisions. 2.2.1 The Generator shall apply for, obtain, and maintain, at its own expense, each Governmental Approval necessary for the Generator to construct, own, and operate the Facility and otherwise perform its obligations under this Agreement. EGAT shall, when reasonably requested by the Generator and at the Generator's cost, provide reasonable assistance to the Generator in obtaining, renewing and maintaining such Governmental Approvals. Notwithstanding the foregoing, the Generator shall be solely responsible for obtaining such Governmental Approvals. Subject to its regulatory and statutory discretion, EGAT shall grant to the Generator any approvals, consents, concessions, decrees, waivers, privileges or exemptions that EGAT is empowered to grant, provided the Generator (i) is in compliance with its obligations under this Agreement, and (ii) has met all applicable requirements for such grant. 2.2.2 The Generator shall commence the construction of the Facility on or before the Scheduled Construction Commencement Date. 2.2.3 The Facility shall be constructed to meet the Contracted Operating Characteristics set out in Schedule 1, the technical characteristics set out in Page 13 Schedule 7 and the construction schedule set out in Schedule 11. The Generator shall obtain EGAT's prior written consent to any material modifications in such technical characteristics, which consent shall not be unreasonably withheld or delayed. If EGAT does not respond to a request for such a material modification within thirty (30) days of receipt of such request, EGAT shall be deemed to have given its consent to the material modification. 2.2.4 The Generator shall construct, complete, repair and modify the Facility such that it shall, at all times, operate in compliance with all applicable Laws, including environmental Laws, and the Grid Code. 2.2.5 The Generator shall construct the Facility, either by itself or through third party contractors, according to Prudent Utility Practices and in a workmanlike and professional manner. 2.2.6 The Generator shall allow representatives of EGAT to inspect the construction site at any reasonable time during construction, start-up, and testing of the Facility, provided that EGAT shall notify the Generator in writing reasonably in advance of any inspection and shall cooperate with the Generator to minimize interference with the Generator's contractors at the Site. 2.2.7 The Parties shall cooperate with each other in accordance with the terms of this Agreement in the construction of the Facility, the New Transmission Facilities and in connecting the Facility to the EGAT System. 2.3 INDEPENDENT ENGINEER AND PROGRESS REPORTS ON CONSTRUCTION The Generator, at its expense, shall provide EGAT with the documents and other materials set out below within the dates specified there. 2.3.1 Within thirty (30) days after the Execution Date, the Generator shall provide EGAT with a list of five or more independent engineers. If at least three of the engineers listed are not reasonably acceptable to EGAT then, within fifteen (15) days of receiving the list (or any further lists required hereunder), EGAT may require the Generator to provide a further list and the Generator shall comply with any such requirement. Within fifteen (15) days of receiving a list containing at least three independent engineers reasonably acceptable to EGAT, EGAT shall nominate three or more of the engineers listed to be appointed to act as independent engineer (the "Independent Engineer") for the purposes of this Agreement and the Generator shall appoint one of the nominated engineers to act in that capacity. If EGAT does not nominate three or more engineers or request a further list of engineers within fifteen (15) days of receiving a list of engineers from the Generator, EGAT shall be deemed to have nominated all of the engineers on the list most recently provided to it by the Generator. Except as otherwise provided in this Agreement, the Generator shall bear all costs and expenses associated with the Independent Engineer. 2.3.2 Starting fifteen (15) days after the end of the first full calendar month after the Execution Date, and thereafter within fifteen (15) days after the close of each calendar quarter up to the start of construction of the Facility, the Generator shall submit for review to EGAT quarterly progress reports substantially in the form set out in Schedule 16. Page 14 2.3.3 On the tenth (10th) Business Day of every month after the start of construction of the Facility until the Commercial Operation Date of the Second Unit, the Generator shall submit for review to EGAT monthly progress reports substantially in the form set out in Schedule 17. 2.3.4 The Generator shall provide EGAT with any clarifications or further information which EGAT reasonably requests relating to the progress of construction of the Facility or the Generator's ability to perform its obligations to meet the Scheduled Commercial Operation Dates. 2.3.5 Within a reasonable period after the Commercial Operation Date of each Unit, the Generator shall provide to EGAT (i) a certificate from the Independent Engineer confirming that the Facility has been constructed in accordance with Prudent Utility Practices and the provisions of Schedules 1, 7, 8, 10, 13 and 18, and (ii) a report from the Independent Engineer on the status of the Facility in relation to compliance with the material technical provisions of the EPC Contract. The Generator shall provide any further documentation or evidence supporting the Independent Engineer's certificate which EGAT reasonably requests. 2.4 METERING 2.4.1 The Generator shall install, own and maintain, at the Generator's expense, all Metering Equipment and associated transformers. The Metering Equipment shall have the specifications set out in Schedule 13. The Generator, at its expense, shall provide (i) all metering structures, unless otherwise agreed, and (ii) surge protection and the necessary primary switches to isolate the metering installation. The specifications of such structures and switches shall be subject to EGAT's approval which shall not unreasonably be withheld or delayed. 2.4.2 The Metering Equipment shall be sealed in the presence of both EGAT and the Generator and the seals shall only be broken in the presence of both Parties for inspection, testing or adjustment. EGAT, at its expense, shall be entitled to have an authorized representative present to monitor any test of the Metering Equipment. 2.4.3 The accuracy of the Metering Equipment shall be tested annually as specified in Schedule 13 by the Generator at the Generator's expense, and the Generator shall give EGAT at least fourteen (14) days' prior written notice of the date of such annual test. Either Party may request additional tests of the accuracy of the Metering Equipment in writing at least fourteen (14) days prior to the proposed date of testing. The Generator shall bear the costs of any such additional tests, except that EGAT shall bear such costs if (i) EGAT requested the additional test, and (ii) the test demonstrates that the Metering Equipment is performing within the relevant tolerance limits as specified in Schedule 13. Whenever any Metering Equipment is found to be defective or not performing within such tolerance limits, it shall be adjusted, repaired, replaced, or re-calibrated by the Generator at its expense. Page 15 2.4.4 If any of the Metering Equipment fails to register, or if the Metering Equipment is found upon testing to be inaccurate by more than plus or minus five tenths of one percent (plus or minus 0.5%) in measuring Net Electrical Generation delivered, an adjustment shall be made correcting all measurements by the inaccurate or defective metering device for billing purposes, for both the amount of the inaccuracy and the period of the inaccuracy, in the following manner: (a) If the Parties cannot agree on the amount of the adjustment necessary to correct the measurements made by the Primary Metering Equipment, the Parties shall use the Back-Up Metering Equipment to determine the amount of such adjustment, provided that the Back-Up Metering Equipment is operating within the relevant tolerance limits as specified in Schedule 13. If the Back-Up Metering Equipment is found upon testing to be inaccurate by more than plus or minus five tenths of one percent (plus or minus 0.5%) in measuring Net Electrical Generation, and the Parties cannot agree on the amount of the adjustment necessary to correct the measurements made by the Back-Up Metering Equipment, the Parties shall, as soon as practicable on the basis of procedures to be mutually agreed upon by the Parties (which may be based upon deliveries of Net Electrical Generation), estimate the amount of the necessary adjustment on the basis of deliveries of the Net Electrical Generation to the EGAT System during periods of similar operating conditions when the Primary Metering Equipment was registering accurately and taking into account the Facility's Fuel use records during such periods; (b) If the Parties cannot agree on the period during which the inaccurate measurements were made, the period during which the measurements are to be adjusted shall be the shorter of (i) one half of the period from the last test of the Metering Equipment, and (ii) the one hundred and eighty (180) days immediately preceding the test that found the Metering Equipment to be defective or inaccurate; and (c) To the extent that the adjustment period covers a period of deliveries for which payment has already been made by EGAT, the Generator shall use the corrected measurements as determined in accordance with this Section 2.4.4 to re-compute the amount due for the period of the inaccuracy and shall subtract the previous payments by EGAT for such period from such re-computed amount. If the difference is a positive number, such difference shall be paid by EGAT to the Generator; and if the difference is a negative number, such difference shall be paid by the Generator to EGAT. Payment of such difference shall be made by means of a credit or an additional charge on the next statement rendered pursuant to Section 19. 2.5 GRID CODE EQUIPMENT AND COMMUNICATION REQUIREMENTS 2.5.1 The Generator shall install, maintain and operate the instrumentation set out in the applicable provisions of the Grid Code relating to metering. The Generator shall also provide telemetering equipment to facilitate remote monitoring of the measurements and indications of such instrumentation. 2.5.2 All installation, maintenance, lease, service or purchase costs for communications and remote indication units at the Facility required by the Grid Page 16 Code or specified in Schedules 10 and 13 shall be paid by the Generator. The costs of communications between the Facility and EGAT shall be borne by the Generator unless initiated by EGAT. 2.6 RIGHTS-OF-WAY AND EASEMENTS 2.6.1 No later than thirty (30) days after the Execution Date, the Generator shall identify to EGAT (i) the location of the takeoff structure at the Site and (ii) the location of the takeoff structure at the substation on the New Main Transmission Line to which the New Transmission Facilities shall be connected. 2.6.2 The Generator and EGAT shall cooperate in acquiring all ownership rights, rights-of-way, easements and continuing access rights (collectively, the ACCESS RIGHTS) necessary for the construction, operation, maintenance, upgrading, replacement and removal of any part of the New Transmission Facilities that will be located on property owned by any Person other than the Generator. 2.6.3 In accordance with Section 2.6.2, if the Generator reasonably believes it will be unable to acquire all of the Access Rights and so notifies EGAT, EGAT shall endeavor to acquire the Access Rights through the exercise of its authority under the EGAT Act as set out in Paragraph 5 of Schedule 10. All costs and expenses incurred by EGAT in the acquisition of the Access Rights shall be reimbursed by the Generator in accordance with the Paragraph 5(f) of Schedule 10. 2.6.4 EGAT's obligations under Sections 2.6.2 and 2.6.3 shall not be construed to require EGAT to exercise its authority under the EGAT Act in a manner that would be extraordinary in light of EGAT's historical use of such authority. For purposes of Section 14.1.1, circumstances which would allow EGAT to acquire the Access Rights only through such an extraordinary exercise of authority under the EGAT Act shall be deemed beyond EGAT's reasonable control. 2.6.5 If all of the Access Rights have not been procured by 31 March 1998, each of the dates set out in Section 10.4 and each of the milestone dates set out in Section 11 shall be extended by the number of additional days required to complete acquisition of the Access Rights. The Generator may elect to waive all or part of such extension by giving EGAT, no later than twelve (12) months before the Scheduled Commercial Operation Date for the First Unit, written notice of the number of days of the extension that will not be taken. 2.6.6 Notwithstanding EGAT's obligations under Section 2.6.2 and 2.6.3, (i) the Generator shall bear all costs and expenses caused by any delay in obtaining the Access Rights, (ii) any Events of Force Majeure that delay or prevent acquisition of the Access Rights shall be deemed to be Force Majeure affecting the Generator and under no circumstances construed as Force Majeure affecting EGAT. 2.6.7 The Access Rights shall be acquired in EGAT's name or become EGAT's by Law. EGAT shall allow the Generator, as EGAT's agent, to exercise all uses of the Access Rights that are required for the Generator's design, engineering, construction, testing, and commissioning of the New Transmission Facilities. Page 17 2.6.8 The Generator shall grant to EGAT all necessary rights-of-way and easements, including adequate and continuing access rights to the Generator's property, to install, operate, maintain, replace, or remove any of EGAT's equipment or facilities for the Connection. Such rights-of-way and easements shall be granted no later than the date construction of the New Transmission Facilities is completed and shall survive the termination or expiration of this Agreement for a period of at least one hundred and eighty (180) days to enable EGAT to remove any of its equipment or facilities located thereon. 2.7 PROVISION OF INFORMATION AND CONSULTATION RELATING TO EGAT TRANSMISSION FACILITIES 2.7.1 EGAT has provided the Generator with the materials EGAT provides contractors or suppliers of equipment on their appointment by EGAT to construct transmission facilities or supply equipment for that purpose. Such materials are included or identified in Schedule 10 and set out EGAT's standard design specifications and engineering and construction guidelines, standard contractual terms, conditions and warranties required from contractors, and other standard practices relating to the construction of EGAT transmission facilities. EGAT shall provide any such additional materials reasonably requested by the Generator. 2.7.2 EGAT shall afford the Generator reasonable opportunities for consultation concerning the materials provided pursuant to Section 2.7.1. 2.8 COMPLETION OF NEW TRANSMISSION FACILITIES 2.8.1 The Generator shall design, engineer, construct, test, and commission the New Transmission Facilities in accordance with (i) the standard EGAT practices and contractual requirements as set out in the materials and information provided to the Generator under Sections 2.7.1 and 2.7.2, and (ii) Prudent Utility Practices whenever there is not an applicable standard EGAT practice or contractual requirement. Although EGAT shall by Law and the provisions of Section 2.6 and this Section 2.8.1 have legal title to the New Transmission Facilities from the start of their construction, the Generator shall bear the risk of loss of or damage to the New Transmission Facilities until the NTF Commissioning Completion Date. 2.8.2 Unless otherwise agreed between the Parties, all contractors and suppliers of equipment appointed by the Generator for the design, engineering, construction, testing or commissioning of the New Transmission Facilities shall be contractors or suppliers of equipment that have previously performed similar services for or supplied similar equipment to EGAT. The Generator shall consult with EGAT concerning the selection of contractors and suppliers of equipment, and EGAT shall identify for the Generator contractors or suppliers of equipment that have previously performed services or supplied equipment to EGAT's satisfaction. 2.8.3 On the tenth (10th) Business Day of every month after the start of construction of the New Transmission Facilities, the Generator shall submit for EGAT's review monthly progress reports on the construction of the New Transmission Facilities substantially in the form set out in Schedule 17. Page 18 2.8.4 The Generator shall allow representatives of EGAT to inspect all construction sites of the New Transmission Facilities at any reasonable time during their construction or commissioning, provided that EGAT shall notify the Generator in writing reasonably in advance of any such inspection and shall cooperate with the Generator to minimize interference with the Generator's contractors at such sites. EGAT, at its expense, shall be entitled to attend and monitor the inspection, testing, energizing and commissioning of the New Transmission Facilities pursuant to Sections 2.8, 2.9 and 2.10 and Schedule 18. 2.8.5 If at any point during the construction or commissioning of the New Transmission Facilities EGAT determines that modifications in the New Transmission Facilities should be made to correct any discrepancies between the Generator's construction of the New Transmission Facilities and the materials and information provided by EGAT to the Generator in accordance with Section 2.7, the Generator shall make any such modifications reasonably proposed by EGAT. The Generator shall bear the cost of any such modifications that are required. 2.8.6 When the New Transmission Facilities are ready for initial inspection and testing, the Generator shall so notify EGAT in a statement in a form reasonably acceptable to EGAT. The initial inspection and testing of the NTF Connection Point and the New Transmission Facilities shall be scheduled for a date agreed by the Parties which shall be not more than seven (7) days after EGAT's receipt of such statement. 2.8.7 On the date determined pursuant to Section 2.8.6, the Generator shall carry out the initial inspection and testing of the NTF Connection Point and the New Transmission Facilities in accordance with Paragraph 3.1 of Part A of Schedule 18. 2.8.8 EGAT shall review on-site the results of the initial inspection and testing of the NTF Connection Point and the New Transmission Facilities carried out pursuant to Section 2.8.7. After receiving the results of such inspection and tests, EGAT shall either (i) within one (1) day provide the Generator with written notice that the inspection and testing requirements set out in Paragraph 3.1 of Part A of Schedule 18 have been met, or (ii) within seven (7) days provide the Generator with a written report describing any areas where, in EGAT's reasonable opinion, such requirements have not been met. 2.8.9 If pursuant to Section 2.8.8(ii) EGAT reports that the New Transmission Facilities or the NTF Connection Point is not ready for energizing, the Generator shall determine and remedy the cause of such failure. The remedy and cost of the remedy shall be borne by the Generator. The Generator shall notify EGAT when further inspection and testing pursuant to Paragraph 3.1 of Part A of Schedule 18 can take place. Such further inspection and testing shall commence on a date agreed by the Parties which shall be not more than seven (7) days after the Generator so notifies EGAT. Such further inspection and testing and EGAT's review of the results thereof shall proceed pursuant to Sections 2.8.6 to 2.8.8 and this Section. 2.8.10 EGAT shall provide the energizing source and the Generator shall energize the NTF Connection Point on an agreed date occurring not more than five (5) days after EGAT issues to the Generator written notice pursuant to Section 2.8.8(i), Page 19 provided that EGAT shall not be required to energize the NTF Connection Point before the Scheduled NTF Energizing Date. The EGAT energizing source shall be at least one (1) energized 500kV circuit from the New Main Transmission Line. After the Generator has energized the NTF Connection Point, the Generator shall conduct final energizing and commissioning tests in accordance with Paragraphs 3.2 and 3.3 of Part A of Schedule 18. 2.8.11 EGAT shall review on-site the results of the final energizing and commissioning tests of the NTF Connection Point and the New Transmission Facilities carried out pursuant to Section 2.8.10. After receiving the results of such tests, EGAT shall either (i) within one (1) day provide the Generator with written notice that the test requirements set out in Paragraphs 3.2 and 3.3 of Part A of Schedule 18 have been met with respect to all tests that can be performed using all New Main Transmission Line circuits available at the time for energizing the NTF Connection Point and New Transmission Facilities, or (ii) within seven (7) days provide the Generator with a written report describing any areas where, in EGAT's reasonable opinion, such requirements have not been met. 2.8.12 EGAT shall review on-site the results of the final energizing and commissioning tests of the 500kV circuits from NTF Connection Point to the Connection Point carried out pursuant to Section 2.8.10. After receiving the results of such tests, (i) within one (1) day EGAT shall provide the Generator with written notice of any determination by EGAT that the test requirements set out in Paragraphs 3.2 and 3.3 of Part A of Schedule 18 have been met with respect to one or both such circuits, and (ii) if EGAT determines that either of such 500kV circuits have not met such requirements, within seven (7) days EGAT shall provide the Generator with a written report describing any areas where, in EGAT's reasonable opinion, such requirements have not been met. 2.8.13 If EGAT reports that the New Transmission Facilities or the NTF Connection Point have not met the requirements for notice pursuant to Section 2.8.11(i) or that either of the 500kV circuits from the NTF Connection Point to the Connection Point has not met the requirements for notice pursuant to Section 2.8.12(i), the Generator shall determine and remedy the cause of such failure. The remedy and cost of the remedy shall be borne by the Generator. The Generator shall notify EGAT when further testing pursuant to Paragraphs 3.2 and 3.3 of Part A of Schedule 18 can take place. Such further testing shall commence on a date agreed by the Parties which shall be not more than seven (7) days after the Generator so notifies EGAT. Such further testing and EGAT's review of the results thereof shall proceed pursuant to Sections 2.8.10 to 2.8.12 and this Section. 2.8.14 The NTF Commissioning Completion Date shall be the date which is the later of (i) the date EGAT provides the Generator with notice pursuant to Section 2.8.11(i), or (ii) the date EGAT provides notice pursuant to Section 2.8.12(i) that both of the 500kV circuits from the NTF Connection Point to the Connection Point have met the test requirements set out in Paragraphs 3.2 and 3.3 of Part A of Schedule 18. 2.8.15 Beginning on the NTF Commissioning Completion Date, EGAT shall (i) assume the risk of loss of or damage to the New Transmission Facilities, and (ii) operate, maintain and energize the New Transmission Facilities in accordance with Prudent Utility Practices. Within thirty (30) days after the NTF Page 20 Commissioning Completion Date, the Generator shall assign to EGAT, with effect from the NTF Commissioning Completion Date, all continuing contractual rights and warranties the Generator has under all contracts relating to the construction of the New Transmission Facilities and equipment procured for that purpose. Such contractual rights and warranties shall meet or exceed the requirements set out in Paragraph 6 of Schedule 10. 2.8.16 There shall be included as a separate component of the Availability Payments an amount (the ADDED FACILITY CHARGE) to reimburse the Generator for costs incurred by it (including amounts paid by it to EGAT pursuant to Section 2.6 and Paragraph 5(f) of Schedule 10) in connection with the acquisition or transfer of Access Rights and in the design, engineering, construction, testing and commissioning of the New Transmission Facilities. The Added Facility Charge shall be a monthly payment payable for 150 consecutive months equal to the amounts specified in Paragraph 6.2 of Schedule 2. EGAT shall commence payments of the Added Facility Charge as part of the first payment of Availability Payments (after the Commercial Operation Date of the First Unit or pursuant to Section 2.10.4 or 14.4.2). Thereafter, EGAT shall pay the Added Facility Charge to the Generator irrespective of whether EGAT's obligation to make Availability Payments is otherwise excused in whole or in part during the Term. 2.9 INSPECTION AND ENERGIZING OF THE CONNECTION POINT AND FACILITY SWITCHYARD 2.9.1 When the Facility Switchyard is ready for the Connection Point to be energized, the Generator shall so notify EGAT in a statement in a form reasonably acceptable to EGAT. The inspection and testing of the Connection Point and the Facility Switchyard shall be scheduled for a date agreed by the Parties which shall be on or before the later of (i) fourteen (14) days after EGAT's receipt of such statement, and (ii) one day after EGAT provides notice pursuant to Section 2.8.12(i) that the test requirements set out in Paragraphs 3.2 and 3.3 of Part A of Schedule 18 have been met with respect to at least one of the two 500kV circuits from the NTF Connection Point to the Connection Point. 2.9.2 On the date determined pursuant to Section 2.9.1, the Generator shall carry out the initial inspection and testing of the Connection Point and Facility Switchyard in accordance with Paragraph 3.1 of Part B of Schedule 18. EGAT, at its expense, may attend and monitor the inspection and testing of the Connection Point and the Facility Switchyard. 2.9.3 EGAT shall review at the Site the results of the initial inspection and testing of the Connection Point and the Facility Switchyard carried out pursuant to Section 2.9.2. After receiving the results of such inspection and testing, EGAT shall either (i) within one (1) day provide the Generator with written notice that the test requirements set out in Paragraph 3.1 of Part B of Schedule 18 have been met, or (ii) within seven (7) days provide the Generator with a written report describing any areas where, in EGAT's reasonable opinion, such requirements have not been met. 2.9.4 If EGAT reports that the Facility Switchyard or the Connection Point is not ready for energizing, the Generator shall, at its expense, make such changes to the Facility Switchyard or the Connection Point as are required and notify EGAT when further inspection and testing pursuant to Paragraph 3.1 of Part B Page 21 of Schedule 18 can take place. Such further inspection and testing shall commence on a date agreed by the Parties which shall be not more than seven (7) days after the Generator so notifies EGAT. Such further testing and EGAT's review of the results thereof shall proceed pursuant to Sections 2.9.2 and 2.9.3 and this Section. 2.9.5 EGAT shall provide the energizing source and the Generator shall energize the Connection Point on an agreed date occurring not more than five (5) days after EGAT issues to the Generator written notice pursuant to Section 2.9.3(i), provided that EGAT shall not be required to energize the NTF Connection Point for this purpose before the Scheduled Energizing Date. The Generator shall conduct final energizing and commissioning tests for the Connection Point and Facility Switchyard pursuant to Paragraphs 3.2 to 3.4 of Part B of Schedule 18. 2.9.6 EGAT shall review the final energizing and commissioning test results of the Connection Point and the Facility Switchyard. After receiving the results of such testing, EGAT shall either (i) within one (1) day provide the Generator with written notice that the test requirements set out in Paragraphs 3.2 to 3.4 of Part B of Schedule 18 have been met, or (ii) within seven (7) days provide the Generator with a written report describing any areas where, in EGAT's reasonable opinion, such requirements have not been met. 2.9.7 If EGAT reports that the Facility Switchyard or the Connection Point have not met the requirements for notice pursuant to Section 2.9.6(i), the Generator shall determine and remedy the cause of such failure. The remedy and cost of the remedy shall be borne by the Generator. The Generator shall notify EGAT when further testing pursuant to Paragraphs 3.2 to 3.4 of Part B of Schedule 18 can take place. Such further testing shall commence on a date agreed by the Parties which shall be not more than seven (7) days after the Generator so notifies EGAT. Such further testing and EGAT's review of the results thereof shall proceed pursuant to Sections 2.9.5 and 2.9.6 and this Section. 2.10 SYNCHRONIZING AND COMMERCIAL OPERATION 2.10.1 After EGAT provides notice pursuant to Section 2.9.6(i), the Generator shall conduct the Unit synchronizing tests set out in Paragraph 3.5 of Part B of Schedule 18. EGAT shall review the results of such Unit synchronizing tests. After receiving the results of such testing, EGAT shall either (i) within one (1) day provide the Generator with written notice that the test requirements set out in Paragraph 3.5 of Part B of Schedule 18 have been met, or (ii) within seven (7) days provide the Generator with a written report describing any areas where, in EGAT's reasonable opinion, such requirements have not been met. If EGAT reports that the Unit has not met the requirements for notice pursuant to subclause (i) of this Section, the Generator shall determine and remedy the cause of such failure. The remedy and cost of the remedy shall be borne by the Generator. The Generator shall notify EGAT when further testing pursuant to Paragraph 3.5 of Part B of Schedule 18 can take place. Such further testing shall commence on a date agreed by the Parties which shall be not more than seven (7) days after the Generator so notifies EGAT. Such further testing and EGAT's review of the results thereof shall proceed pursuant to this Section. Page 22 The Generator shall be allowed to synchronize on an agreed date occurring after EGAT provides notice pursuant to subclause (i) of this Section 2.10.1, but no more than one hundred and eighty (180) days before the Commercial Operation Date of the Unit the Parties anticipate to be set pursuant to Section 2.10.2. 2.10.2 On the date which is twelve (12) months before the Scheduled Commercial Operation Date of the First Unit, EGAT shall provide the Generator with written notice stating whether the reserve capacity in the EGAT System forecasted for the Scheduled Commercial Operation Date of the First Unit is greater than or less than fifteen percent (15%). If such forecasted reserve capacity is less than fifteen percent (15%), the Commercial Operation Date of the First Unit may occur on or after its Earliest Commercial Operation Date and the Commercial Operation Date of the Second Unit may occur on or after its Earliest Commercial Operation Date. If such forecasted reserve capacity is greater than fifteen percent (15%), the Commercial Operation Date of the Units may not occur before their respective Scheduled Commercial Operation Dates without the written consent of EGAT which shall be at EGAT's sole discretion. Subject to the foregoing, the Commercial Operation Date of each Unit shall be a date agreed by EGAT and the Generator occurring no more than five (5) days after the later of (i) EGAT's receipt of a certificate of the Independent Engineer certifying that the Unit has successfully completed the Commercial Operations Test in accordance with Schedule 14, and (ii) the NTF Commissioning Completion Date. 2.10.3 If the Commercial Operation Date for either Unit fails to occur by its Scheduled Commercial Operation Date, the Generator shall pay EGAT liquidated damages of four (4) Baht/kW per day of Contracted Capacity of such Unit for the number of days such failure is not due to the actions or omissions of EGAT or otherwise excused hereunder in the period from the Unit's Scheduled Commercial Operation Date to the earlier of (i) its Commercial Operation Date, or (ii) the date two hundred and forty (240) days after the Scheduled Commercial Operation Date. 2.10.4 If the Commercial Operation Date of either Unit fails to occur by its Scheduled Commercial Operation Date, EGAT shall make Availability Payments to the Generator with respect to that Unit for the number of days during the period from its Scheduled Commercial Operation Date to its Commercial Operation Date that such failure is due solely to EGAT's not completing the New Main Transmission Line or not energizing the NTF Connection Point by the Scheduled NTF Energizing Date or not energizing the Connection Point by the Scheduled Energizing Date, unless such failure is otherwise excused hereunder. EGAT shall commence making such Availability Payments on the Scheduled Commercial Operation Date of the Unit after such date is adjusted as described below. For the purposes of determining the date such Availability Payments shall commence, the Scheduled Commercial Operation Date of the Unit (i) shall be extended by one day for each day by which the occurrence of the Commercial Operation Date is delayed due to causes attributable to the Generator, but (ii) shall not be extended pursuant to Section 10.5.2 for delay due solely to EGAT's Page 23 not completing the New Main Transmission Line, not energizing the NTF Connection Point by the Scheduled NTF Energizing Date or not energizing the Connection Point by the Scheduled Energizing Date. EGAT shall continue making such Availability Payments until the earlier of (i) the date upon which EGAT has made such Availability Payments for the same number of days as the Unit's Commercial Operation Date was delayed by EGAT as determined in accordance with the preceding paragraph, (ii) the Commercial Operation Date of the Unit, or (iii) the termination of this Agreement. Any Availability Payments made by EGAT in accordance with this Section 2.10.4 shall be calculated using the Contracted Capacity of the Unit. Costs which the Generator either did not incur or were avoidable because the Unit was not Available shall be deducted from such Availability Payments, and any additional costs necessarily or reasonably incurred as a result of the delay caused by EGAT shall be added to such Availability Payments. If the Dependable Contracted Capacity that is established for either Unit on its Commercial Operation Date is less than its Contracted Capacity, then the Availability Payments paid to the Generator with respect to that Unit during the period between its Scheduled Commercial Operation Date and its Commercial Operation Date shall be recalculated using its Dependable Contracted Capacity on its Commercial Operation Date. If the Availability Payments made in respect of that period exceed the amount reached by the recalculation, EGAT shall be entitled to deduct an amount equal to the excess from future payments due to the Generator by EGAT together with interest on the amount of the excess at the Overdraft Rate. Such deductions shall be made from such future payments pro- rata over the same period of time in which the excess Availability Payments were made. 2.10.5 Any Availability Payments payable by EGAT to the Generator in accordance with Section 2.10.4 shall be paid in accordance with Section 19.2. Liquidated damages payable by the Generator to EGAT in accordance with Section 2.10.3 shall be drawn by EGAT from any portion of the Development Security remaining after any reduction thereof in accordance with Section 13.2. To the extent such portion of the Development Security is insufficient to compensate EGAT for all liquidated damages due under Section 2.10.3, the Generator shall pay EGAT any further liquidated damages in accordance with Section 19.2. 2.11 TESTING 2.11.1 Prior to the Commercial Operation Date of each Unit, the Generator shall conduct the Commercial Operations Test for the Unit. Such test will (i) determine the Unit's Dependable Contracted Capacity, and (ii) verify the Unit's Contracted Operating Characteristics. The Generator shall provide thirty (30) days' prior written notice to EGAT of such test of each Unit. After such notice has been given, the Generator shall provide at least seven (7) days' prior written notice to EGAT of any rescheduling of the date of such test. EGAT, at its expense, may attend and monitor the Commercial Operations Test of each Unit. The Generator shall bear the costs and expenses of the Commercial Operations Tests and all other tests conducted before the Commercial Operation Date. Page 24 2.11.2 After the Commercial Operation Date of each Unit, the Unit shall be tested semi-annually during each Contract Year (and after each time the Unit is withdrawn from service for a major overhaul, modification or renovation) to establish the Dependable Contracted Capacity. The Dependable Contracted Capacity so established (i) may be more or less than the previously established Dependable Contracted Capacity for the Unit, but (ii) may not exceed the Unit's Contracted Capacity. The Generator shall bear the costs and expenses of all such semi-annual tests, and EGAT shall bear the costs and expenses of attending and monitoring such tests. 2.11.3 EGAT shall have the right to require the Generator to conduct a Net Capacity Test for either Unit upon seven (7) days' prior written notice to the Generator if EGAT reasonably believes that the generating capacity of the Unit is less than the Dependable Contracted Capacity then in effect for the Unit for any reason whatsoever except (i) Governmental Force Majeure, (ii) a condition caused by the EGAT System (including Force Majeure affecting EGAT), or (iii) a Planned Outage. The Generator shall bear the costs and expenses of any test required by EGAT under this Section 2.11.3, but EGAT shall repay the Generator such costs and expenses if the Net Capacity Test demonstrates a Dependable Contracted Capacity equal to or greater than that in effect for the Unit when EGAT requested the Net Capacity Test. In either case, EGAT shall be responsible for any costs and expenses of attending and monitoring such tests. 2.11.4 The Generator shall have the right to conduct Net Capacity Tests to establish a new Dependable Contracted Capacity for either Unit upon seven (7) days' prior written notice to EGAT. The Generator may request such determinations of Dependable Contracted Capacity on no more than four (4) occasions in any Contract Year, exclusive of any such determinations requested by EGAT pursuant to Section 2.11.3. The Generator shall bear the costs and expenses of any test required under this Section 2.11.4, and any expenses incurred by EGAT in attending and monitoring such tests. 2.11.5 The Dependable Contracted Capacity of each Unit on its Commercial Operation Date shall be the Dependable Contracted Capacity established by the most recently conducted Net Capacity Test of the Unit. The Dependable Contracted Capacity so established may not exceed the Unit's Contracted Capacity. The Dependable Contracted Capacity established for a Unit in the most recently conducted Net Capacity Test shall be effective until the Dependable Contracted Capacity for that Unit is next determined in accordance with this Section 2.11 and Schedule 14. Any Availability Notice issued by the Generator to EGAT pursuant to Section 5 shall not declare Availability for a Unit in excess of the Dependable Contracted Capacity in effect for that Unit at the time any such Availability Notice is issued, except as permitted in Paragraph 17 of Schedule 2. 2.12 REVIEW BY EGAT Notwithstanding any other provisions of this Agreement, any review by EGAT of any materials, documents, designs, drawings, schedules, design data or other information submitted by the Generator concerning the Facility under this Agreement or prior to the execution of this Agreement, or any consent by EGAT under Section 2.2.3 to any modification in the Facility's construction, or any inspection or testing of the Facility by EGAT, or any presence of EGAT to witness any test performed by the Generator, whether undertaken pursuant to this Agreement or not, shall not be deemed to constitute Page 25 an endorsement of the Facility nor a warranty or other assurance by EGAT of the safety, durability or reliability of the Facility, nor release the Generator of any of its obligations under this Agreement. 3. PROVISION AND PURCHASE OF AVAILABILITY AND ELECTRICITY 3.1 OBLIGATION TO PROVIDE DEPENDABLE CONTRACTED CAPACITY AND CONTRACTED OPERATING CHARACTERISTICS 3.1.1 In consideration of EGAT's agreement to pay Availability Payments, Energy Payments and other sums to the Generator on the terms and conditions of this Agreement, the Generator shall throughout the Term maintain, repair, fuel and operate the Facility as required by Prudent Utility Practices, the Grid Code and all applicable Laws to ensure the provision of the Dependable Contracted Capacity and the Contracted Operating Characteristics. 3.1.2 The Generator shall ensure that it does not at any time issue or allow to remain outstanding, with respect to a Unit, a declaration of revised Operating Characteristics which declares the Availability and Operating Characteristics of the Unit at levels or values different from those that the Unit could achieve at the relevant time except: (a) during periods of Planned Outage or otherwise with the consent of EGAT; (b) while repairing or maintaining the Facility or equipment necessary to the operation of the Facility where such repair or maintenance cannot reasonably, in accordance with Prudent Utility Practices, be deferred to a period of Planned Outage; (c) where necessary to avoid an imminent risk of injury to persons or material damage to property (including the Facility); (d) if it is not lawful for the Generator to operate the Facility; or (e) to the extent that the Generator is affected by a Force Majeure; provided that this Section shall not require the Generator to declare Availability or Operating Characteristics exceeding the requirements specified in Schedule 1. 3.1.3 EGAT shall accept test energy generated from a Unit prior to its Commercial Operation Date and pay the Generator for such energy as measured by Metering Equipment at the Metering Point in accordance with Section 19 an amount equal to the sum of: (a) the cost of Fuel used by the Generator to generate such test energy; plus (b) the variable operation and maintenance costs reasonably incurred by the Generator in producing such test energy. Page 26 3.2 COMPLIANCE WITH THE GRID CODE 3.2.1 The Generator shall comply with the provisions of the Grid Code in effect throughout the Term, subject to any variations therefrom granted to the Generator by EGAT. 3.2.2 EGAT shall use its reasonable efforts to notify the Generator in advance of proposed changes to the Grid Code, and the Generator may provide comments to EGAT in regard to such proposed changes. EGAT shall give due consideration to any such comment. 3.2.3 Within the period of time stated in the notice (which shall generally not be less than thirty (30) days) after receipt of a notice of change in the Grid Code which does not require Facility modifications, or which does not adversely affect the Facility's operation, the Generator shall comply with such change to the Grid Code. If Facility modifications are required or the Facility's operation would be adversely affected by a change in the Grid Code, the Generator shall as soon as practicable advise EGAT of the anticipated length of time required in order for the Generator, acting diligently, to effect compliance with such notice. The Generator shall take immediate steps to comply with such notice (unless EGAT subsequently notifies the Generator in writing that the Generator may discontinue such compliance). 3.2.4 If changes to the Grid Code result in increases or decreases in costs or revenues to the Generator, the provisions of Sections 3.2.5 and 17 shall apply and EGAT shall continue to make Availability Payments to the Generator in accordance with Schedule 2 without deductions due to the Grid Code's effect on the Facility's operations during the time period required for the Generator to adjust the Facility or its operation to comply with any such changes to the Grid Code. 3.2.5 The Generator shall provide EGAT with prompt written notice describing in reasonable detail any circumstances in which actions the Generator is required to take to comply with a change in the Grid Code will prevent the Generator from performing other obligations under this Agreement. The Generator's inability to perform such other obligations in such circumstances shall not in and of itself be a breach of this Agreement. 3.3 SALE AND PURCHASE OF ELECTRICITY 3.3.1 The Generator shall deliver to the Connection Point and sell to EGAT, and EGAT shall purchase from the Generator, on the terms and conditions of this Agreement, the Net Electrical Generation. The Net Electrical Generation delivered to EGAT shall be measured at the Metering Point using the Primary Metering Equipment. If the Primary Metering Equipment is inaccurate, otherwise defective, or being tested pursuant to Section 2.4, the measurements recorded by the Back-Up Metering Equipment shall be used to measure the Net Electrical Generation. 3.3.2 The Generator shall not deliver any electricity generated by the Facility to any third party during the Term or any extension of the Term made in accordance with this Agreement. Page 27 3.4 PROVISION OF STANDBY SERVICE To the extent permitted by law, EGAT shall offer the Generator standby electrical service at the applicable standby rate. 3.5 DISPATCH INSTRUCTIONS The Generator shall operate the Facility as a fully dispatchable facility. Subject to the terms and conditions of this Agreement, EGAT shall have the sole right and discretion to schedule and Dispatch the generation of electricity from the Facility and the delivery thereof into the EGAT System, provided that EGAT shall Dispatch the Facility in a manner that is consistent with: (a) the principle of merit order Dispatch, subject to the needs of the EGAT System; (b) the Grid Code; (c) Prudent Utility Practices; and (d) all applicable Laws, regulations and permits. Except in Emergency Conditions, EGAT shall only issue Dispatch Instructions that are in accordance with the Generator's declared Availability and Declared Operating Characteristics of each Unit as notified by the Generator from time to time. The Generator may but shall not be obliged to comply with any Dispatch Instruction that would require the Generator to operate either Unit beyond its declared Availability or Declared Operating Characteristics at the relevant time unless such Dispatch Instruction is stated to be issued under Emergency Conditions. In Emergency Conditions the Generator shall not be required to operate either Unit beyond its Design Limits or in any manner that would be inconsistent with Prudent Utility Practices. 3.6 OPERATION AND MAINTENANCE (O&M) REPORTS At least once in each calendar quarter, the Generator shall submit to EGAT a report from the O&M operator containing the information set out in Schedule 22. For so long as the Financing Documents remain effective, EGAT shall be provided with complete copies of all O&M reports provided to Financing Parties by the Generator or the O&M operator. 4. DELIVERY OF ELECTRICITY 4.1 QUALITY OF SUPPLY If at any time the supply of electricity from a Unit does not comply as to its electrical characteristics with the applicable requirements of the Grid Code or this Agreement as a result of the breach by the Generator of any such requirements: (a) the Generator shall take the steps necessary pursuant to Prudent Utility Practices to remedy such non-compliance as soon as possible; and (b) the Unit shall be deemed to be not Available to the extent of such non- compliance. Page 28 4.2 TITLE AND RISK OF LOSS Title to and risk of loss of any electricity generated by the Facility and delivered to EGAT in accordance with this Agreement shall pass to EGAT at the Connection Point. EGAT shall bear the cost of transmission losses incurred on the EGAT side of the Metering Point in the transmission of electricity sold to EGAT, except as attributable to diversion or theft before the Connection Point. 4.3 FAILURE OF THE SYSTEM The calculation of Availability Payments under Schedule 2 shall not include any deductions for: (a) any failure, restriction or outage of transmission facilities on the EGAT side of the Connection Point; (b) any action which the Generator, in accordance with the Grid Code, is obliged or entitled to take due to any frequency excursion on the EGAT System outside the frequency ranges and time limitations set out in Paragraph 4.1 of Schedule 1; or (c) any shedding of the Net Electrical Generation of a Unit instructed by EGAT. 5. AVAILABILITY PAYMENTS 5.1 CALCULATION OF AVAILABILITY PAYMENTS Commencing from the Commercial Operation Date of the First Unit, the Generator shall be entitled to receive from EGAT Availability Payments calculated in accordance with the provisions of Schedule 2. 5.2 CONFIRMATION AND PAYMENT OF AVAILABILITY PAYMENTS The Actual Availability and the Operating Characteristics of the Units in each Settlement Period shall be confirmed in a Final Confirmation Statement issued in accordance with Section 18. Amounts calculated pursuant to Schedule 2 shall be payable in accordance with Section 19. 5.3 NOTICES OF AVAILABILITY AND DECLARED OPERATING CHARACTERISTICS 5.3.1 The Generator shall keep EGAT advised of the Availability and Operating Characteristics of the Units by issuing Availability Notices and Outage Notices in accordance with the Grid Code. 5.3.2 Any Availability Notice or Outage Notice may be given by telephone in accordance with the Grid Code. The Notice shall be confirmed by facsimile as soon as possible thereafter and in any event shall be sent to EGAT within two hours. Where a facsimile is so sent by way of confirmation it shall state clearly that it is in confirmation of a Notice already given by telephone and must state the exact time at which the Notice was given by telephone. 5.3.3 If, following the occurrence of an event of the type specified in Paragraph 3.4 of Schedule 2, EGAT wishes to issue a Post Event Notice, it shall deliver a copy of the Post Event Notice to the Generator as soon as reasonably practicable but not Page 29 later than 5 p.m. on the fifth (5th) Business Day after the day on which the relevant event occurred. 5.3.4 A Post Event Notice shall specify: (a) the Settlement Period during which the relevant event occurred; and (b) the matters or values which EGAT intends to re-declare as a result of the relevant event. 5.3.5 If the Generator considers that a Post Event Notice was not validly issued in accordance with this Agreement, it shall notify EGAT, within seventy-two (72) hours after receipt of the written Post Event Notice or confirmation thereof, of the grounds for its objection. If EGAT and the Generator are unable to resolve the Generator's objection within fourteen (14) days of the date of such objection, the matter shall be referred to an Expert for determination in accordance with Section 15. If the Generator does not notify EGAT of its objection within such seventy-two (72) hour period, the Post Event Notice shall be deemed accepted by the Generator. 6. ENERGY PAYMENTS 6.1 ENTITLEMENT TO AND CALCULATION OF ENERGY PAYMENTS Commencing on the Commercial Operation Date of the First Unit, the Generator shall be entitled to receive from EGAT, for each Settlement Period, the Energy Payments for electrical energy generated from the Facility in response to Dispatch Instructions as measured and calculated in Schedule 3. The Generator shall not be entitled to receive an Energy Payment calculated in accordance with Schedule 3 for either (i) operations carried out without a Dispatch Instruction, or (ii) any operation or part thereof requested by EGAT's Control Center but not carried out by the Generator. 6.2 CONFIRMATION AND PAYMENT OF ENERGY PAYMENTS The operations of the Facility in each Settlement Period shall be reflected in a Final Confirmation Statement issued in accordance with Section 18. The Energy Payments due to the Generator pursuant to this Section 6 shall be payable in accordance with Section 19.1. 7. MINIMUM TAKE If the Generator is required to take or transport a minimum quantity of Fuel by the Fuel Purchase Agreement or the Fuel Transportation Agreement, and provided that the terms of such agreements have been approved by EGAT in accordance with Sections 9.1 and 9.2, EGAT shall share the costs (the MINIMUM TAKE LIABILITY) incurred by the Generator after the Commercial Operation Date of the Second Unit with respect to a failure to take or transport the minimum quantity of Fuel, as calculated under the provisions of the Fuel Purchase Agreement and Fuel Transportation Agreement. EGAT shall not share the Minimum Take Liability if such a failure (i) occurs before the Commercial Operation Date of the Second Unit, or (ii) is due to any causes other than Dispatch Instructions by EGAT, Force Majeure affecting EGAT or Governmental Force Majeure. Page 30 The method of sharing shall be on the basis of the following formula: EA - Expected Unit Availability EA = CAH for each Contract Year/8760 For two units, EA = (CAH//1// + CAH//2//) / (8760 x 2) AA - Actual Availability AA = (Sigma)AAH/8760 (Sigma)AAH = Equivalent Achieved Available Hours for each Contract Year For two units, AA = ((Sigma)AAH//1// + (Sigma)AAH//2//)/(8760 x 2) ACF - Annual Capacity Factor ACF = MWh generated during Contract Year ---------------------------------- Contracted Capacity (CC) x 8760 For two units, ACF = (ACF//1// + ACF//2//) /2 MACF - Minimum Annual Capacity Factor below which the Minimum Fuel Purchase Obligation applies = 0.60 If ACF is greater than or equal to MACF, then Minimum Take Liability does not apply. If ACF is less than MACF, the Minimum Take Liability applies, with the Generator's Share and EGAT's Share given by the following: EGAT's Share = 1 - EA - AA ------- EA - MACF Generator's Share = EA - AA ------- EA - MACF
The preceding formula allocates the Minimum Take Liability between EGAT and the Generator within the following boundaries: (a) If AA is greater than or equal to EA, EGAT shall bear one hundred percent (100%) of the Minimum Take Liability, and (b) If AA is less than or equal to the MACF, the Generator shall bear one hundred percent (100%) of the Minimum Take Liability. 8. ENVIRONMENTAL QUALITY REQUIREMENTS 8.1 The Generator shall comply with or exceed the standards set out in Schedule 8 and all applicable environmental Laws. 8.2 If, subsequent to the Execution Date, the Generator is required by a Change-in-Law to meet environmental standards which are more stringent than those set out in Schedule 8, Page 31 the Generator may submit to EGAT a certificate setting out the details of increased costs resulting from such change, in accordance with the provisions of Section 17. Such a certificate shall include or be accompanied by sufficient technical, environmental, and financial information and data to demonstrate that the least-cost option consistent with Prudent Utility Practices to meet or exceed the environmental Law has been selected. EGAT and the Generator shall promptly determine, in good faith, any necessary adjustments in accordance with Section 17. 8.3 The Generator shall establish environmental management systems and facilities to ensure that the applicable environmental Laws and the standards set out in Schedule 8 are complied with or exceeded. Unless otherwise directed by the relevant Governmental Authority, the Generator shall install and operate a suitable continuous emission and ambient air monitoring system including at least four monitoring stations at appropriate locations within a ten (10) kilometer radial distance from the Facility. The Generator shall also install and operate on-line recorders at the Facility and, unless otherwise directed, in the offices of the relevant Governmental Authority. 8.4 The Generator shall provide an annual report on all relevant aspects of the Generator's environmental facilities, activities and performance no later than thirty (30) days following each Contract Year. The annual report on environmental performance shall contain a statement of assurances to the effect that all applicable environmental Laws have been complied with or, where that is not the case, shall contain details of any failure to comply with such environmental Laws and the actions instituted to prevent such failures to recur. 9. FUEL SUPPLY 9.1 FUEL SUPPLY OBLIGATIONS 9.1.1 The Generator shall ensure that the Facility has sufficient quantities of Fuel to enable each Unit to operate at eighty-five percent (85%) of its Contracted Capacity on an annual basis from its Commercial Operation Date until the last day of the Term. 9.1.2 The Generator shall not enter into a Fuel Purchase Agreement or Fuel Transportation Agreement unless EGAT (i) has reviewed and approved the terms and conditions thereof in accordance with Section 9.1.3, or (ii) has been deemed to have so reviewed and approved the terms and conditions thereof in accordance with Section 9.1.4. 9.1.3 The Generator shall negotiate a Fuel Purchase Agreement and Fuel Transportation Agreement which satisfy the principles set out in Schedule 9. EGAT shall be afforded not less than thirty (30) days to review the draft Fuel Purchase Agreement and draft Fuel Transportation Agreement to determine whether or not such draft agreements satisfy the principles set out in Schedule 9. EGAT shall notify the Generator of its determination with respect to any such draft agreement within thirty (30) days of receiving the draft agreement. If EGAT determines that any such draft agreement does not satisfy the principles set out in Schedule 9, EGAT shall provide the Generator with the reasons for such determination and propose changes EGAT reasonably deems necessary for the draft agreement to satisfy such principles. Page 32 9.1.4 EGAT shall be deemed to have completed its review and approved the draft Fuel Purchase Agreement or draft Fuel Transportation Agreement if it does not provide the Generator with a written determination to the contrary together with the reasons for such determination and EGAT's proposed changes within thirty (30) days after the date of receipt of any such draft agreement. 9.1.5 EGAT's review, approval, objection or rejection of the draft Fuel Purchase Agreement, Fuel Transportation Agreement or any proposed amendment, modification or termination of such agreements shall not: (a) lessen, diminish or affect in any way the performance by the Generator of its obligations under this Agreement or the Project Agreements; (b) increase, expand or affect in any way the obligations of EGAT under this Agreement; (c) affect the application or interpretation of the provisions of this Agreement or the Project Agreements; or (d) result in EGAT incurring any liability whatsoever for the performance or consequences of the performance of the Fuel Purchase Agreement or Fuel Transportation Agreement. 9.1.6 The Generator shall provide EGAT with copies of the fully executed Fuel Purchase Agreement and Fuel Transportation Agreement on or before the date specified in Section 11(g). 9.2 SUBSEQUENT FUEL SUPPLY AGREEMENTS 9.2.1 The Generator shall not terminate, modify or amend the Fuel Purchase Agreement or Fuel Transportation Agreement without EGAT's prior written consent. If either such agreement is terminated, the Generator shall immediately negotiate a new Fuel Purchase Agreement or a new Fuel Transportation Agreement. 9.2.2 The provisions set out in Section 9.1 shall apply mutatis mutandis to any (i) new Fuel Purchase Agreement, (ii) new Fuel Transportation Agreement, and (iii) documents relating to any alternative Fuel arrangements made pursuant to Section 9.3.1. 9.3 FUEL STOCK 9.3.1 The Generator shall maintain at its expense on the Site at all times a Fuel Stock sufficient to meet all of the Generator's Fuel needs for a period of at least thirty (30) days in the event that there is an interruption in the Generator's Fuel supply. In determining whether the quantity of such Fuel Stock is sufficient, the Generator shall take into account, among other things, the maximum Fuel consumption rate of the Facility and the time required to accomplish necessary replenishment. 9.3.2 The Generator shall provide EGAT with any information reasonably requested by EGAT from time to time regarding the Fuel Stock and shall also keep EGAT Page 33 advised from time to time of any material modifications to its Fuel Stock arrangements. 9.3.3 The Generator shall not be entitled to claim Force Majeure under Section 14 for any interruption of the supply of Fuel to the Facility until such interruption due to Force Majeure has continued for a period of sixty (60) days from the date the interruption occurred. 10. CRITICAL DATES AND DURATION OF AGREEMENT 10.1 INITIAL TERM The Term of this Agreement shall begin on the Execution Date and shall continue for a period of twenty-five (25) years from the Commercial Operation Date of the Second Unit, unless otherwise extended or terminated in accordance with the provisions of this Agreement. 10.2 SURVIVAL OF RIGHTS ON TERMINATION The expiration or termination of this Agreement shall not affect any rights or obligations which may have accrued prior to or in connection with such expiration or termination, and shall not affect continuing obligations of each of the Parties under this Agreement or any other agreement between the Parties which are expressed to continue after such expiration or termination. 10.3 EXTENSION OF AGREEMENT The Term may be extended upon terms and conditions mutually satisfactory to the Parties. 10.4 CRITICAL DATES Scheduled Financial Close Date: 30 April 1999 Scheduled Construction Commencement Date: 1 May 1999 Scheduled NTF Energizing Date: 1 January 2001 Scheduled Energizing Date: 1 February 2001 Earliest Commercial Operation Date of the First Unit: 1 July 2001 Earliest Commercial Operation Date of the Second Unit: 1 January 2002 Scheduled Commercial Operation Date for the First Unit: 1 October 2001 Scheduled Commercial Operation Date for the Second Unit: 1 April 2002 10.5 EXTENSION OF CRITICAL DATES AND TERM 10.5.1 Each of the dates set out in Section 10.4 and the milestone dates set out in Section 11 shall be extended by one day for each day that a Force Majeure or Governmental Force Majeure preventing the achievement of such date has occurred and is continuing. Page 34 10.5.2 Each of the dates set out in Section 10.4 and the milestone dates set out in Section 11 shall be extended by one day for each day that the failure to achieve such date is due solely to the actions or omissions of EGAT. 10.5.3 The Term of this Agreement shall be extended by one day for each day of Force Majeure or Governmental Force Majeure occurring after the Commercial Operation Date of the First Unit. 10.5.4 Failure to meet any of the critical dates set out in Section 10.4, unless otherwise specifically stated in Section 12.2.1, shall not be construed as a breach or default under this Agreement. 11. CONTRACTED MILESTONES The Generator shall comply with the following milestones schedule in connection with the development and construction of the Facility: (a) EGAT shall have received from the Generator all drawings, reports and certificates required under Sections 2.3.2, 2.3.3 and 2.8.3 with regard to the design, construction and completion of the Facility on or before the dates such materials are due thereunder; (b) within fourteen (14) months after the Execution Date, EGAT shall have received from the Generator evidence satisfactory to EGAT demonstrating that the Generator has obtained all applicable Governmental Approvals, including those related to air quality, easements and rights of way, water use and discharge, solid waste and hazardous waste disposal required for the construction, operation, and maintenance of the Facility in accordance with the provisions of this Agreement, provided that if any such Governmental Approval has not been obtained by such date, the Generator shall provide to EGAT evidence demonstrating that (i) such Governmental Approval could not be applied for by such date other than due to an act or omission of the Generator, and (ii) the Generator can reasonably be expected to obtain such Governmental Approval before the date it is required to be obtained; (c) within fourteen (14) months after the Execution Date, EGAT shall have received from the Generator evidence acceptable to EGAT that the Generator has acquired all necessary easements, rights-of-way and authorizations needed to construct the Facility; (d) within fourteen (14) months after the Execution Date, EGAT shall have received from the Generator extracts or other evidence satisfactory to EGAT demonstrating that contracts for the design and construction of the Facility have been executed; (e) within fourteen (14) months after the Execution Date, EGAT shall have received from the Generator extracts or other evidence satisfactory to EGAT that contracts for the procurement of major equipment have been executed; (f) within fourteen (14) months after the Execution Date, EGAT shall have received from the Generator copies of the certificates of insurance coverage, or insurance policies required; Page 35 (f) EGAT fails to comply with or operate in conformity with any material obligation of this Agreement. 12.1.2 In addition to any other remedy available to it, the Generator shall be entitled to immediately terminate this Agreement by written notice to EGAT for Events of Default by EGAT pursuant to subsections (a) (following the thirty (30) day period specified in subsection (a)), (b), (c), (d) and (e) of Section 12.1.1. In the case of Section 12.1.1(f), the Generator shall give written notice describing such Event of Default and EGAT shall be given sixty (60) days from receipt of such notice to cure the default. If the default cannot be cured within sixty (60) days with the exercise of reasonable efforts, EGAT shall have an additional period of time of one hundred and eighty (180) days in which to cure the default, provided always that EGAT shall, throughout such additional period, exercise reasonable, continuous efforts to cure the default and continue to perform all its other obligations under this Agreement during such period of cure. The Generator may (but shall have no obligation to) grant any additional period of time within which to cure any default. If EGAT fails to cure the default within the relevant prescribed period, then the Generator may, in addition to any other rights and remedies available to it, immediately terminate this Agreement and consider EGAT in material breach of its obligations under this Agreement. 12.1.3 After any termination of this Agreement, the Generator may exercise any rights or remedies it has at law, including seeking monetary compensation for damages, injunctive relief or specific performance. 12.2 TERMINATION BY EGAT 12.2.1 Each of the following events shall be considered an EVENT OF DEFAULT with respect to the Generator: (a) the Generator defaults in the payment of any amount due and payable under this Agreement and such default continues unremedied for a period of thirty (30) days after the date on which EGAT gives notice of the default to the Generator; (b) damage to the Facility (excluding any damage caused by Force Majeure) renders it substantially incapable of generating electricity, and the Parties agree (or in the absence of such agreement an Expert determines in accordance with Section 15) that it is unlikely the Facility can be restored within thirty (30) months from the date the damage occurred to a condition such that (i) the Dependable Contracted Capacity established for each Unit immediately following restoration would be at least ninety percent (90%) of its Contracted Capacity, and (ii) the Availability of each Unit over the six (6) months immediately following restoration would exceed seventy-five percent (75%) of its Actual Availability over the six (6) months immediately preceding the date such damage occurred; (c) damage to the Facility (by Force Majeure or any other cause) rendered it substantially incapable of generating electricity, and the Parties agreed (or in the absence of such agreement an Expert determined in accordance with Section 15) that the Facility could be restored to the condition Page 37 described in Section 12.2.1(b) within thirty (30) months or less from the date the damage occurred, and the Generator fails to complete such restoration within thirty (30) months from the date the damage occurred or within any lesser period agreed by the Parties or determined by an Expert; (d) the Generator is dissolved or liquidated, other than voluntary dissolution or liquidation as part of a reorganization or reincorporation; (e) the Generator makes a general assignment of this Agreement or any of its rights hereunder or of its interest in the Facility for the benefit of its creditors; (f) the Generator enters into voluntary insolvency proceedings or is adjudicated bankrupt under any insolvency law as debtor; (g) the Generator fails to comply with or operate in conformity with any material obligation of this Agreement; (h) the Commercial Operation Date of either Unit fails to occur by its Scheduled Commercial Operation Date; (i) the Generator abandons the engineering, design, construction or operation and maintenance of the Facility for forty-five (45) days or longer and, after receiving notice from EGAT, fails (i) to indicate within ten (10) days its intent to resume such activities within a period of time agreeable to EGAT, and (ii) to resume such activities within such agreed period of time; (j) there is a transfer of an interest in the Generator which falls outside the permitted transfers set out in Section 24 and EGAT's prior written approval of such transfer, to the extent required by Section 24, has not been given, and such default continues unremedied for a period of thirty (30) days from the date on which such transfer occurred; (k) without the prior written consent of EGAT, the Generator amends the Fuel Purchase Agreement or Fuel Transportation Agreement, or upon termination of the Fuel Purchase Agreement or Fuel Transportation Agreement enters into a new Fuel Purchase Agreement or Fuel Transportation Agreement, and the terms of such amendment or new Fuel Purchase Agreement or Fuel Transportation Agreement are such that the Generator's ability to satisfy its obligations under this Agreement or EGAT's rights under this Agreement are adversely affected; (l) during any period of thirty-six (36) consecutive months, the Actual Availability of the Units falls below sixty percent (60%) of the Actual Availability that would be achieved were both Units operated at their Contracted Capacity for all of the hours in such thirty-six (36) month period, provided that the accrual of such thirty-six (36) month period shall exclude periods during which: (i) it is not lawful for the Generator to operate the Facility, Page 38 (ii) the Generator is affected by Force Majeure or Governmental Force Majeure, or (iii) the Facility is being restored in accordance with Section 14.7; or (m) the Generator fails to achieve Financial Close by the Scheduled Financial Close Date or by such date fails to provide EGAT with copies of written commitments from the Sponsors (or any of their Affiliates) to provide capital contributions to the Generator in amounts sufficient to enable the Generator to fund development, construction and completion of the Facility. 12.2.2 In addition to any other remedy available to it, EGAT shall be entitled to immediately terminate this Agreement by written notice to the Generator for Events of Default by the Generator pursuant to subsections (a) (following thirty (30) day period specified in subsection (a)), (b), (d), (e), (f), (i), (j) (following the thirty (30) day period specified in subsection (j)), (l) and (m) of Section 12.2.1. In the case of subsections (c), (g), (h) and (k) of Section 12.2.1, EGAT shall give written notice describing such Event of Default and the Generator shall be given sixty (60) days from receipt of such notice to cure the default. If the default cannot be cured within sixty (60) days with the exercise of reasonable efforts, the Generator shall have an additional period of time of one hundred and eighty (180) days in which to cure the default, provided always that the Generator shall, throughout such additional period, exercise reasonable, continuous efforts to cure the default and continue to perform all of its other obligations under this Agreement during such period of cure. EGAT may (but shall have no obligation to) grant any additional period of time within which to cure any default. If the Generator fails to cure the default within the relevant prescribed period or any additional period granted by EGAT at its sole discretion, then EGAT may, in addition to any other rights and remedies available to it, immediately terminate this Agreement and consider the Generator in material breach of its obligations under this Agreement. 12.2.3 After any termination of this Agreement, EGAT may exercise any rights or remedies it has at law, including seeking monetary compensation for damages, injunctive relief or specific performance. 12.3 STEP-IN RIGHTS 12.3.1 EGAT shall have the right, but under no circumstances the obligation, to assume operational responsibility for the Facility (in the capacity of an operator only) in the place and instead of the Generator in order to continue operation of the Facility or complete any necessary repairs so as to assure uninterrupted availability of electrical energy from the Facility. Such step-in rights shall arise upon the occurrence and continuance of an Event of Default with respect to the Generator which could reasonably be expected to materially adversely affect the Generator's ability to operate and maintain the Facility in accordance with this Agreement. Page 39 EGAT shall not exercise such step-in rights until any applicable cure period specified in Section 12.2.2 has expired, provided that EGAT may step-in at any earlier time at the request of the Financing Parties if a right for the Financing Parties to step-in has arisen under the Financing Documents. For so long as the Financing Documents remain in effect, EGAT shall not exercise step- in rights hereunder (i) without first obtaining the consent of the Financing Parties, or (ii) if operation of the Facility has been assumed by any Financing Party or any approved assignee or designee of the Financing Parties. The Generator shall use its reasonable efforts to cause the Financing Parties specifically to acknowledge such step-in rights of EGAT in the Financing Documents. EGAT may require issues and conditions in addition to those addressed in this Section 12.3.1 to be clarified to EGAT's satisfaction before EGAT exercises the step-in rights provided hereunder. In particular, the Generator shall: (a) assign to EGAT or its designated agent or contractor, within two (2) Business Days of the event giving rise to EGAT's rights, the Generator's rights in and to all agreements necessary to operate the Facility; and (b) take all steps necessary to permit EGAT to exercise as operator of the Facility the Generator's rights under all permissions and licenses to the extent such rights are necessary for EGAT to operate the Facility and provide EGAT with access to all design manuals, construction drawings and other documentation required to operate the Facility. 12.3.2 During any period in which EGAT exercises its right to assume the operations of the Facility pursuant to this Section 12.3, EGAT shall continue making Availability Payments and Energy Payments to the Generator in accordance with the terms of this Agreement. In no event shall EGAT's decision to operate the Facility be deemed to be a transfer of title or a transfer of the Generator's obligations as owner thereof, but EGAT shall be deemed to be only the operator of the Facility. During any period when EGAT shall be operating the Facility, EGAT shall: (a) be entitled to reasonable remuneration for EGAT's services as an operator charged at then international rates of remuneration for comparable services; and (b) meet any payments due from the Generator, including payments for fuel, maintenance, repairs, insurance, taxes and other operating costs of the Facility, together with all regularly scheduled payments under the Financing Documents of principal, interest, fees, indemnities, reserves, and other amounts owing (in each case pro-rated for the amount attributable to such period), but only to the extent that the Generator is unable to meet any such payments. The Parties shall cooperate with each other and execute and deliver such documents as may be necessary or desirable to accomplish the foregoing. The remuneration and payments referred to in subsections (a) and (b) of this Section 12.3.2 which become payable during any such period shall be regarded as funds Page 40 advanced by EGAT to the Generator. EGAT shall be entitled to payment of such amounts in full and with interest calculated at the Default Rate from the date such payment is due. EGAT shall obtain such payment by deduction from Availability Payments and Energy Payments due to the Generator including, where such deduction is insufficient to repay EGAT fully within the step-in period, the continuation of such deduction after the end of such step-in period, provided that such amounts shall be subordinated to amounts owed to the Financing Parties. 12.3.3 During any period when EGAT is operating the Facility, EGAT shall exercise its reasonable efforts to produce and deliver electrical energy to the EGAT System, subject to the Facility being operable at the time of EGAT's takeover or later being made operable by repairs or otherwise. Throughout such period of time, EGAT shall exercise due care in operating and maintaining the Facility in accordance with Prudent Utility Practices. EGAT shall have no more liability to the Generator than would a third party operation and maintenance contractor with respect to the operation and maintenance of the Facility by EGAT during the exercise of such step-in rights hereunder. For the avoidance of doubt, such liability shall not include any liability for failure to provide Availability. 12.3.4 EGAT shall have the right to discontinue making payments under Section 12.3.2 and to terminate this Agreement in accordance with Section 12.2.2 if at any time EGAT reasonably determines that the Event of Default leading to such exercise by EGAT of its step-in rights cannot be cured, or that the Generator is unlikely to repay, or to be able to repay, the funds advanced by EGAT under Section 12.3.2. EGAT shall also have the right on fifteen (15) days' prior written notice to the Generator to return the operational responsibility for the Facility to the Generator, provided that EGAT shall return the Facility to the Generator in a condition no worse than that immediately prior to the assumption of the operational responsibility for the Facility by EGAT, ordinary wear and tear excepted. Notwithstanding the foregoing, EGAT shall not be responsible for or have any liability resulting from any conditions of the Facility or at the Site that existed prior to EGAT's exercise of its step-in rights. 12.3.5 The operation of the Facility by EGAT shall not relieve EGAT from its obligations to perform under this Agreement. The failure by EGAT to meet its obligations as a responsible operator of the Facility under Section 12.3.3 shall not give rise to an Event of Default with respect to the Generator for which EGAT shall have the right to exercise remedies under Section 12.2.3. For the avoidance of doubt, notwithstanding the provisions of this Section 12.3.5, EGAT shall retain all those rights provided under Section 12.3.4. 12.3.6 Upon the curing of the Event of Default which has led to the exercise by EGAT of its step-in rights, EGAT shall return the operation of the Facility to the Generator with reasonable promptness. Page 41 12.4 OTHER RIGHTS TO TERMINATE Without prejudice to any other remedy to which either Party may be entitled for breach of this Agreement, the Parties agree that Sections 12, 14.6 and 14.7 state the only circumstances in which either Party may unilaterally terminate this Agreement. 13. SECURITIES AND LIQUIDATED DAMAGES 13.1 ESTABLISHMENT OF DEVELOPMENT SECURITY On the Execution Date the Generator shall provide to EGAT the Development Security in the form of a direct-pay letter of credit or a letter of guarantee or a cash escrow account acceptable to EGAT in an amount equal to five hundred (500) Baht per kW of the sum of the Contracted Capacities of the Units in order to secure the Generator's performance of its obligations under this Agreement. The Generator shall maintain the Development Security until the Commercial Operation Date of the Second Unit. The Development Security shall be obtained from one or more Thai banks which are listed in Schedule 21 or which satisfy the credit standards set out below. If the Generator provides the Development Security in the form of a letter of credit, the letter of credit shall be issued either (i) for a term not to expire before the Commercial Operation Date of the Second Unit, or (ii) on the condition that such letter of credit expressly provides to EGAT the right to draw down the amount of the letter of credit prior to termination of the letter of credit, if it has not been extended for any additional period of time that may be required to cover the period through the Commercial Operation Date of the Second Unit. If the Generator provides the Development Security in the form of a letter of guarantee, the guarantee shall be substantially in the form set out in Schedule 12. EGAT will appraise on a yearly basis the value of all non-cash securities provided as the Development Security. If the credit rating of any Thai bank from which the Generator has obtained the Development Security falls below BBB+ as measured by Standard and Poor's Ratings Group, Baal as measured by Moody's Investors Services or AA as measured by the Thai Rating Information Services, then EGAT may at its sole discretion require the Generator to post additional or replacement security from a Thai bank with a rating not less than those stated above in order to compensate for the change in value of the Development Security. If there is a failure to comply with this provision, EGAT may terminate this Agreement pursuant to Sections 12.2.1(g) and 12.2.2. 13.2 EGAT'S RIGHT TO RETAIN DEVELOPMENT SECURITY AS LIQUIDATED DAMAGES The Generator acknowledges and understands that EGAT has entered into this Agreement in reliance on and in consideration of the Generator's representation that the Units will be in operation no later than their respective Scheduled Commercial Operation Dates, and that EGAT will include the Units in its various capacity forecasts. The Generator further acknowledges and understands that in order to meet its obligations to its retail and wholesale customers as a public utility, EGAT must have adequate assurance that construction of the Facility is proceeding in a timely fashion in order to forecast adequately and meet the EGAT System's capacity needs as well as to avoid incurring production costs higher than those planned by EGAT. Page 42 Based on the foregoing, the Generator agrees that EGAT shall have the right in each instance to retain so much of the Development Security as is set out below, plus accrued interest thereon, as liquidated damages if any one or more of the following milestone dates have not been satisfied (unless any such milestone date has not been met due to Force Majeure or the fault of EGAT) within the time periods herein established: (a) One quarter of one percent (0.25%) for each of the detailed engineering drawings, reports, and certificates that EGAT has not received from the Generator in accordance with Section 11(a); provided, however, that the total amount able to be assessed against the Generator for failure to provide such drawings, reports and certificates shall not exceed five percent (5%) of the amount of the Development Security; (b) Ten percent (10%) if EGAT has not received all required environmental permits and other Governmental Approvals required to construct the Facility in accordance with Section 11(b); (c) Five percent (5%) if EGAT has not received any extracts or other evidence of the execution of the contracts for the procurement of major equipment in accordance with Section 11(e); (d) Five percent (5%) if EGAT has not received the Fuel Purchase Agreement and the Fuel Transportation Agreement, if any in accordance with Sections 9.1.3 and 11(g); (e) Ten percent (10%) if EGAT has not received copies of the principal Financing Documents in accordance with Section 11(h). For purposes of this Section 13.2(e), satisfactory copies of the principal Financing Documents shall consist of binding commitments of the Financing Parties and equity participants sufficient to fund one hundred percent (100%) of construction and permanent financing; and (f) Fifteen percent (15%) if the Generator shall have failed to commence construction in accordance with Section 11(i). EGAT shall return the remaining portion of the Development Security together with all interest accrued thereon, if any, following the payment of any amounts due to EGAT hereunder to the Generator upon thirty (30) days after the earlier of (i) satisfaction of the requirements for additional security in accordance with Section 13.5 after the Commercial Operation Date of the Second Unit, and (ii) the termination of this Agreement in accordance with Section 12.1, 12.2, 14.6 or 14.7. Notwithstanding the foregoing, EGAT shall return to the Generator fifty percent (50%) of that portion of the Development Security retained by EGAT in accordance with this Section 13.2 if the Commercial Operation Date of the First Unit occurs by its Scheduled Commercial Operation Date and fifty percent (50%) of such portion of the Development Security if the Commercial Operation Date of the Second Unit occurs by its Scheduled Commercial Operation Date. If the Commercial Operation Date of either Unit fails to occur by its Scheduled Commercial Operation Date, in addition to any amounts retained by EGAT in accordance with this Section due to the Generator's failure to meet any of the milestones and the Commercial Operation Date of either Unit, the Generator shall pay liquidated damages to EGAT in accordance with Sections 2.10.3, 2.10.5 and 19.2. Page 43 13.3 LIQUIDATED DAMAGES FOR CONTRACTED CAPACITY DEFICIENCIES If the Dependable Contracted Capacity of either Unit on its Commercial Operation Date is less than ninety-five percent (95%) of its Contracted Capacity, the Generator shall pay to EGAT on a one-time basis only for such Unit, a sum equal to four thousand (4,000) Baht per kW for the difference between such Dependable Contracted Capacity of the Unit and ninety-five percent (95%) of the Unit's Contracted Capacity as liquidated damages for the detrimental impact upon EGAT's generation planning. EGAT shall be entitled to recover the amount of such liquidated damages from the Development Security, and the Generator shall pay EGAT any amount of such liquidated damages which exceeds the available amount of the Development Security in accordance with Section 19.2. Notwithstanding subsequently established increases in the Dependable Contracted Capacity of the Unit pursuant to Section 2.11, EGAT shall not be required to refund any portion of the liquidated damages previously paid to EGAT pursuant to this Section 13.3. 13.4 PAYMENTS FROM THE SECURITY To the extent EGAT is owed damages as a result of the Generator's breach of this Agreement (other than for a failure to meet the milestones set out in Section 13.2 or for a deficiency in the Contracted Capacity of either Unit under Section 13.3) and EGAT has previously not been compensated therefor, appropriate amounts of the Development Security shall be retained by EGAT. The return of the Development Security to the Generator shall not prejudice the rights of EGAT to claim compensation arising from this Agreement. 13.5 ADDITIONAL SECURITY 13.5.1 As soon as reasonably practicable, but no later than six (6) months after the Commercial Operation Date of the Second Unit, and before the return of the Development Security under Section 13.2, the Generator shall execute in favor of EGAT mortgages over the buildings, machinery and real property assets comprising the Facility. The mortgages shall secure the Generator's performance of its obligations to EGAT under this Agreement up to an amount equal to one billion (1,000,000,000) Baht and shall be subordinate at all times to the amounts secured under the mortgages and security interests granted to the Financing Parties up to the greater of: (a) the sum of: (i) all amounts secured under or contemplated to be secured under the Financing Documents at Financial Close (including amounts payable to providers of interest rate swap agreements or other reasonable hedging arrangements required by the Financing Parties or issuers of letters of credit in respect of foreign currency exchange reserve requirements or debt service reserve requirements, but excluding the amount of any cost overrun facilities relating to the construction of the Facility other than the amount of the overrun facilities that are drawn down upon for (i) capital improvements which are required by Changes-in-Law, changes to the Grid Code, Force Majeure or Prudent Utility Practices, (ii) increased costs resulting from or attributable to Page 44 EGAT's delay or failure in performing its obligations under this Agreement, or (iii) any other uses, provided that in the case of this subclause (iii) the amount of equity committed or infused by or on behalf of the Generator into the Project is greater than the sum of (i), (ii) and (iii) by one billion (1,000,000,000) Baht), plus (ii) the amount of any additional financing obtained by the Generator after the Financial Close for additional working capital needs or capital improvements which are required by Changes-in-Law, changes to the Grid Code, Force Majeure (as approved by EGAT) or Prudent Utility Practices; or (b) the fair market value of the Project for the remaining useful life of the Facility as reasonably determined by the Financing Parties at the time of any additional financing or refinancing minus one billion (1,000,000,000) Baht. 13.5.2 If requested by the Generator, EGAT and the Generator shall from time to time, in connection with any financing or refinancing by the Generator, execute subordination agreements giving effect to the arrangements described in Section 13.5.1 and such other documents as may be requested by the Financing Parties to evidence the subordination contemplated in Section 13.5.1. EGAT acknowledges that it shall have no rights to exercise any of its rights under the mortgages executed in its favor pursuant to Section 13.5.1 during any period in which any Financing Documents are in force and effect until such time as the Financing Parties have exercised their mortgage rights to enforce their remedies. 13.5.3 The Generator shall bear its own costs and all reasonable costs incurred by EGAT in connection with the negotiation and execution of the mortgage granted to EGAT and, when such is requested by the Generator, in connection with the subordination agreements, consents, releases and related documents required by any Financing Parties from time to time, and all other documents in connection therewith, and shall pay the mortgage registration fees to register the mortgage and for re-registrations required in connection with refinancings or additional financings. 13.5.4 Subject to the continuing observation of the restrictions set out in Section 13.5.1, the Generator shall be entitled to refinance the Project after the Commercial Operation Date of the Second Unit. The Generator shall obtain EGAT's prior written consent for any refinancing of the Project before the Commercial Operation Date of the Second Unit. EGAT shall provide such consent if in its judgment the refinancing will not have a material adverse impact on EGAT's interests in the completion of the Facility in accordance with the terms of this Agreement. In the case of a refinancing, EGAT agrees that the Financing Parties shall continue to enjoy priority over EGAT with regard to their respective security interests in the Facility. EGAT further agrees to execute any consents reasonably requested by the Financing Parties for subsequent refinancings or financings (or, if necessary, a release of its mortgage) from time to time in order to enable any subsequent or additional secured Financing Party to enjoy the priority contemplated under Section 13.5.1 and the Generator agrees to re-register the mortgage granted to EGAT, if applicable. Page 45 13.6 REASONABLE LIQUIDATED DAMAGES The Parties acknowledge that where liquidated damages for either the Generator's or EGAT's failure to perform their respective obligations are set out in this Section 13 and Section 2, such liquidated damages (i) are reasonable and appropriate measures of the damages for such delays or such failures, (ii) do not represent a penalty or consequential damages for losses sustained by EGAT or the Generator as a result of such failures, and (iii) shall be the exclusive remedies for the failure to achieve the milestone obligations set out in Section 11, provided that such liquidated damages are not intended to compensate either Party for the damage that may result from termination of this Agreement as a result of the continuation of such failures. 14. FORCE MAJEURE 14.1 OVERVIEW 14.1.1 For the purposes of this Agreement, Force Majeure shall mean an event, condition, or circumstance, including and the effects thereof, beyond the reasonable control and without the fault or negligence of the Party claiming Force Majeure, which, despite all reasonable efforts of the Party claiming Force Majeure to prevent it or mitigate its effects, causes a delay or disruption in the performance of any obligation imposed hereunder. Subject to the foregoing, Force Majeure shall include: (a) unusually severe weather conditions; (b) epidemic or plague; (c) acts of war (whether war has been declared or is undeclared), acts of force by a foreign nation, or embargo; (d) strike or work stoppage (other than those solely affecting the Party claiming the same as Force Majeure), riots or acts of terrorists; (e) Change-in-Law; (f) failure (other than a failure due to an act or omission of the Generator) to obtain or renew any required Governmental Approval relating to the ownership, construction, financing, operation or maintenance of the Facility, or the performance of the obligations under this Agreement; (g) accident, earthquake, sabotage fire or explosion; (h) expropriation or compulsory acquisition of the Facility, any material assets or rights, any shares or other interest of the Generator, or any other act or omission by any Governmental Authority (other than (i) lawful actions due to an act or omission by the Generator or its contractors not in compliance with Law, or (ii) the enforcement of the terms of this Agreement or the Project Agreements in accordance with the dispute resolution procedures contemplated thereunder) which adversely affects the Generator or any of its rights or the performance of its obligations under this Agreement or any Project Agreement relating to the Facility to which the Generator is a party; and Page 46 (i) any Force Majeure affecting the performance of any Person that is a party to any material maintenance, construction, service, fuel supply or other material contract between the Generator and such Person relating to the ownership, construction, operation or maintenance of the Facility. 14.1.2 For purposes of this Agreement, GOVERNMENTAL FORCE MAJEURE shall mean those events of Force Majeure described in Section 14.1.1(c), (e), (f) and (h) in which the action or inaction of Governmental Authorities is the controlling or contributing force which determines or causes the occurrence of such events or the continuation of the effects thereof. For the avoidance of doubt, (i) events of Force Majeure shall not include Governmental Force Majeure for purposes of Sections 14.4 and 14.6, and (ii) if an event of Governmental Force Majeure occurs before the privatization of EGAT and is continuing when EGAT is privatized, the event shall continue to be treated as Governmental Force Majeure irrespective of whether the provisions relating to Governmental Force Majeure have been eliminated pursuant to Section 27.1. 14.1.3 For the avoidance of doubt, mechanical or electrical breakdown or failure of equipment, machinery or plant owned or operated by either Party due to the manner in which such equipment, machinery or plant has been operated or maintained (whether or not by such Party) shall not itself constitute Force Majeure. 14.1.4 Subject to the limitations set out in this Agreement, if either Party is rendered unable by reason of a Force Majeure to perform, wholly or in part, any obligation set out in this Agreement, then upon such Party giving notice as specified in Section 14.2 and full particulars of such event, such obligations of such Party shall be suspended or excused to the extent of such Force Majeure. 14.2 NOTICE OF FORCE MAJEURE AND CONSEQUENCES The Party claiming the Force Majeure shall as soon as reasonably practicable following the occurrence of Force Majeure: (a) notify the other Party of the Force Majeure, identifying the nature of the event and the duration of its effect which the Party claiming Force Majeure believes to be reasonably likely; (b) afford the other Party reasonable access to its facilities for obtaining further information about the event, including the Facility or EGAT System, for site inspection; (c) use, at its own cost, all reasonable efforts to remedy its inability to perform and to resume full performance hereunder as soon as practicable; (d) keep such other Party reasonably apprised of such efforts; and (e) provide written notice of the resumption of performance hereunder. The foregoing shall be conditions to the ability of a Party to obtain relief from its obligations under this Agreement due to Force Majeure. Page 47 14.3 LIMITATIONS The Party claiming Force Majeure shall not be entitled to suspend performance under this Agreement for any greater scope or longer duration than is required by the Force Majeure or the delay occasioned thereby. Without otherwise limiting the payment rights and obligations under Section 14.4, during any period of Force Majeure or Governmental Force Majeure, EGAT shall continue to make Availability Payments in accordance with Schedule 2 for any Availability provided by the Generator that EGAT remains capable of Dispatching. Neither Party shall be relieved of its obligations under this Agreement nor shall any obligations of a Party be suspended solely because there may be increased costs or other adverse economic consequences incurred through the performance of such obligations. Obligations of the Parties that are required to be completely performed prior to the occurrence of Force Majeure shall not be excused as a result of such occurrence. The failure or inability of either Party to satisfy a payment obligation that has arisen under this Agreement shall not be excused by Force Majeure. 14.4 PAYMENT RIGHTS AND OBLIGATIONS DURING FORCE MAJEURE 14.4.1 If Force Majeure affecting the Generator occurs after the Commercial Operation Date of either Unit, EGAT shall make Availability Payments to the Generator only to the extent the Unit is Available to deliver electrical energy to EGAT. 14.4.2 EGAT shall make Availability Payments from the Scheduled Commercial Operation Date of either Unit (adjusted as described below) if Governmental Force Majeure affecting either Party occurs before the Commercial Operation Date of the Unit and delays the occurrence of its Commercial Operation Date past its Scheduled Commercial Operation Date. The amount of each such Availability Payment shall be calculated using the Contracted Capacity of the Unit. For the purposes of determining the date such Availability Payments shall commence, the Scheduled Commercial Operation Date of the Unit (i) shall be extended by one day for each day by which the occurrence of the Commercial Operation Date of the Unit is delayed due to causes attributable to the Generator, but (ii) shall not be extended pursuant to Section 10.5.1 for such Governmental Force Majeure. EGAT shall make such Availability Payments until the earlier of (i) the discontinuation of such Governmental Force Majeure (including the effects thereof), or (ii) the termination of this Agreement pursuant to Section 14.6.3. 14.4.3 If Governmental Force Majeure affecting either Party occurs after the Commercial Operation Date of either Unit, EGAT shall continue to make Availability Payments to the Generator with respect to the Unit. Each such Availability Payment shall be: (a) in an amount equal to the average of the Availability Payments made to the Generator with respect to the Unit over the period of six (6) months preceding the Governmental Force Majeure, excluding periods of Planned Outages or Force Majeure; (b) if the Governmental Force Majeure occurs less than six months after the Commercial Operation Date of the Unit, in an amount equal to the average of Availability Payments made to the Generator with respect to Page 48 the Unit over the period from its Commercial Operation Date to the Governmental Force Majeure, excluding periods of Planned Outages or Force Majeure; or (c) if the Governmental Force Majeure occurs before the end of the first Billing Period after the Commercial Operation Date of either Unit, in an amount calculated using the Dependable Contracted Capacity in effect for the Unit on the day before the Governmental Force Majeure occurred. EGAT shall make payments in accordance with this Section until the earlier of (i) discontinuation of such Governmental Force Majeure (including the effects thereof), or (ii) the termination of this Agreement pursuant to Section 14.6.4. 14.4.4 If the Commercial Operation Date of the First Unit fails to occur by its Scheduled Commercial Operation Date due to Force Majeure affecting the New Main Transmission Line, from the Scheduled Commercial Operation Date of the Unit (adjusted as described below) EGAT shall pay the Generator its costs of servicing debt drawn down and expended by the Generator before or on the date such Force Majeure occurred and any unavoidable costs the Generator necessarily or reasonably incurs thereafter. For the purposes of determining the date such payments shall commence, the Scheduled Commercial Operation Date of the First Unit (i) shall be extended by one day for each day by which the occurrence of its Commercial Operation Date is delayed due to causes attributable to the Generator, but (ii) shall not be extended pursuant to Section 10.5.1 for Force Majeure affecting the New Main Transmission Line. If Force Majeure affecting the New Main Transmission Line occurs after the Commercial Operation Date of the First Unit and before the Commercial Operation Date of the Second Unit, EGAT shall pay the Generator the greater of (i) Availability Payments with respect to the First Unit in amounts determined in accordance with Section 14.4.5(a), (b) or (c), or (ii) the Generator's costs of servicing debt drawn down and expended before or on the date such Force Majeure occurred and any unavoidable costs the Generator necessarily or reasonably incurs thereafter. EGAT shall commence making such payments on the date such Force Majeure occurs. EGAT shall make payments pursuant to this Section 14.4.4 until the earlier of (i) the discontinuation of such Force Majeure (including the effects thereof), or (ii) the termination of this Agreement pursuant to Section 14.6.2. If any payments made under this Section 14.4.4 (other than Availability Payments with respect to the First Unit) include amounts which are applied to reduce the principal of debt under the Financing Documents, the Parties shall consult each other in good faith to determine any equitable adjustment to the Availability Payments required to prevent EGAT from compensating the Generator a second time after the Commercial Operation Date of either Unit for the same principal amounts. 14.4.5 If Force Majeure affecting EGAT occurs after the Commercial Operation Date of the Second Unit, EGAT shall pay the Generator its costs of servicing debt drawn down and expended by the Generator before or on the date such Force Majeure occurred and any unavoidable costs the Generator necessarily or reasonably incurs after such date. EGAT shall make such payments to the Generator during any period of Force Majeure which affects EGAT after the Page 49 Commercial Operation Date of the Second Unit until the aggregate of all such periods of Force Majeure affecting EGAT equals six (6) months. Thereafter, EGAT shall make Availability Payments to the Generator during any period of Force Majeure that affects EGAT. Such Availability Payments with respect to each Unit shall be: (a) in an amount equal to the average of the Availability Payments made to the Generator for the Unit over the period of six (6) months preceding the Force Majeure, excluding periods of Planned Outages or Force Majeure; (b) if the Force Majeure occurred less than six (6) months after the Commercial Operation Date of the Unit, in an amount equal to the average of Availability Payments made to the Generator with respect to the Unit from its Commercial Operation Date to the date the Force Majeure occurred, excluding periods of Planned Outages or Force Majeure; or (c) if the Force Majeure occurs before the end of the first Billing Period after the Commercial Operation Date of the Unit, in an amount calculated using the Dependable Contracted Capacity in effect for the Unit on the day before the Force Majeure occurred. EGAT shall make payments in accordance with this Section 14.4.5 until the earlier of (i) discontinuation of the Force Majeure (including the effects thereof), or (ii) the termination of this Agreement pursuant to Section 14.6.2. 14.4.6 Beginning on the date that the aggregate of periods of Force Majeure affecting EGAT reaches six (6) months, EGAT shall pay the Generator an amount representing the portion of Availability Payments that were suspended in accordance with Section 14.4.5 during such periods of Force Majeure. Such amount shall be: (a) the sum of the Availability Payments that would have been paid pursuant to Section 14.4.5 (adjusted as set out in Section 14.4.7) during such periods of Force Majeure if such periods of Force Majeure had occurred after preceding periods of Force Majeure affecting EGAT had reached an aggregate of six (6) months; less (b) the sum of all payments made by EGAT to the Generator pursuant to Section 14.4.5 during such periods of Force Majeure. EGAT shall pay this amount to the Generator over a period of twenty-four (24) months in equal monthly instalments added to the Availability Payments made during such period, provided that (i) EGAT shall pay such instalments whether or not its obligation to make Availability Payments is excused in whole or in part during such twenty-four (24) month period, and (ii) if this Agreement is terminated before the end of such twenty-four (24) month period, EGAT shall pay the sum of the unpaid instalments upon termination. 14.4.7 Whenever EGAT makes Availability Payments to the Generator in accordance with Section 14.4.2, 14.4.3, 14.4.4 or 14.4.5, such payments shall be: Page 50 (a) decreased by all costs which, as a result of either Force Majeure or Governmental Force Majeure, the Generator either did not incur or reasonably need not have incurred without materially and adversely affecting the condition of the Facility or its ability to resume generation of electricity upon the discontinuation of Force Majeure or Governmental Force Majeure; (b) decreased by the proceeds of any business interruption insurance received by the Generator as a result of the Force Majeure or Governmental Force Majeure; (c) decreased by the amount of any Availability Payments made for Actual Availability pursuant to Section 14.3; and (d) increased by any additional costs necessarily or reasonably incurred by the Generator as a result of the Force Majeure or Governmental Force Majeure. 14.4.8 If the Dependable Contracted Capacity that is established for either Unit on its Commercial Operation Date is less than its Contracted Capacity, then any Availability Payments made to the Generator before the Unit's Commercial Operation Date in accordance with Section 14.4.2 shall be recalculated using the Dependable Contracted Capacity established for the Unit on its Commercial Operation Date. If the Availability Payments made to the Generator with respect to the Unit before its Commercial Operation Date exceed the amount reached by the recalculation, EGAT shall be entitled to deduct an amount equal to the excess from future payments due to the Generator by EGAT together with interest on such amount at the Overdraft Rate. Such deductions shall be made from such future payments pro-rata over the same period of time in which the excess Availability Payments were made. 14.5 PAYMENTS DURING EXTENSION OF TERM During any extension of the Term under Section 10.5.3 (or, if pursuant to Section 2.10.4 or 14.4.2 EGAT has made Availability Payments with respect to either Unit before its Commercial Operation Date, beginning on the date in the Term after which the application of Table 1 of Schedule 2 to determine Availability Payments for the Unit has been completed), EGAT shall be entitled to receive electrical energy from the Generator by making payments to the Generator in amounts determined as follows: (a) Energy Payments calculated in accordance with Schedule 3 and fixed operation and maintenance costs calculated in accordance with Schedule 2 with respect to each Unit for a period representing the same number of days for which EGAT made (i) Availability Payments for the Unit pursuant to Sections 2.10.4, 14.4.2, 14.4.3, 14.4.4 and 14.4.5, or (ii) payments for the Unit pursuant to Section 14.4.6; (b) if the aggregate of periods of Force Majeure affecting EGAT during the Term (before any adjustment pursuant to Section 10.5.3) is less than six (6) months, EGAT shall make Availability Payments with respect to each Unit for the same number of days in such extension as the aggregate of such periods of Force Majeure, provided that (i) such Availability Payments shall be calculated using the rates set out in Schedule 2 that would have applied during such periods of Force Majeure, and (ii) such Availability Payments shall be reduced by amounts Page 51 paid by EGAT to the Generator during such periods of Force Majeure pursuant to Sections 14.3 and 14.4.5; and (c) Availability Payments to the extent of each Unit's Availability for any portion of such extension attributable to Force Majeure affecting the Generator after the Commercial Operation Date of the Second Unit, provided that (i) such Availability Payments shall be calculated using the rates set out in Schedule 2 that would have applied during such periods of Force Majeure, and (ii) such Availability Payments shall be reduced by the amount of any payments made to the Generator with respect to the Unit pursuant to Section 14.4.1. 14.6 TERMINATION 14.6.1 Subject to Section 14.7, if Force Majeure affecting the Generator occurs before or after the Commercial Operation Date of the Second Unit and continues for a period exceeding one (1) year, either Party may terminate this Agreement by giving the other Party thirty (30) days written notice of termination. 14.6.2 If Force Majeure affecting the New Main Transmission Line occurs before the Commercial Operation Date of the First Unit and continues for a period of twenty-four (24) months, EGAT may terminate this Agreement by giving the Generator thirty (30) days written notice of termination. If any other Force Majeure affecting EGAT occurs before or after the Commercial Operation Date of the First Unit, EGAT may terminate this Agreement by giving the Generator thirty (30) days written notice after such Force Majeure has continued for twelve (12) months. Upon any termination of this Agreement in accordance with this Section 14.6.2, EGAT shall purchase the Generator's right, title and interest in and to the Facility and all other assets of the Generator for an amount which shall be: (a) the aggregate amount outstanding on the date of such purchase under the Financing Documents, including reasonable termination costs due under such Financing Documents, and under any loans from shareholders to the Generator; plus (b) an amount equal to the sum of all amounts of registered and paid-up share capital issued by the Generator and any share premiums received by the Generator; plus (c) an amount equal to any earnings retained by the Generator (including statutory reserves); less (d) the proceeds of any insurance received by the Generator as a result of such Force Majeure. 14.6.3 Subject to Section 14.7, if Governmental Force Majeure affecting either Party occurs before the Commercial Operation Date of the Second Unit and continues for a period exceeding one (1) year, either Party may terminate this Agreement by giving the other Party thirty (30) days written notice of termination, whereupon EGAT shall purchase the Generator's right, title, and interest in and to the Facility and all other assets of the Generator for an amount which: Page 52 (a) if EGAT has elected to terminate this Agreement, shall be the sum of (i) the purchase price as calculated in Section 14.6.2, plus (ii) a return on the amount determined in Section 14.6.2(b) at the rate of fifteen percent (15%) per annum, calculated from the date of the investment in the Generator to the date of EGAT's purchase hereunder; or (b) if the Generator has elected to terminate this Agreement, shall be the purchase price as calculated in Section 14.6.2. 14.6.4 Subject to Section 14.7, if Governmental Force Majeure affecting either Party occurs after the Commercial Operation Date of the Second Unit and continues for a period exceeding one (1) year, EGAT may terminate this Agreement by giving the Generator thirty (30) days written notice of termination, whereupon EGAT shall purchase the Generator's right, title, and interest in and to the Facility and all other assets of the Generator for an amount which shall be agreed between the Parties, provided that termination of this Agreement shall not take effect until such amount is agreed. Such agreed amount shall be an amount which: (a) is not less than the aggregate amount outstanding under the Financing Documents on the date of such purchase, including reasonable termination costs payable under the Financing Documents and an amount equal to any earnings retained by the Generator (including statutory reserves); and (b) takes into account the Term of this Agreement remaining on the date such amount is agreed, the condition and historical performance of the Facility, the remaining useful life and the economic value of the Facility's generating capacity to either Party over the remainder of its useful life, the depreciated cost of the Facility on the books of the Generator, the Generator's achieved return on equity, and the nature of the Governmental Force Majeure and the ability to cure such Governmental Force Majeure. If the Parties are unable to reach agreement on such amount within sixty (60) days after the date EGAT gives the Generator notice of termination, the inability to reach agreement on such amount shall be treated as a dispute and subject to resolution in accordance with Section 15. 14.7 RECONSTRUCTION If damage to the Facility by Force Majeure after the Commercial Operation Date of the First Unit renders the Facility substantially incapable of generating electricity, the Parties shall determine (or in the absence of agreement by the Parties an Expert shall determine in accordance with Section 15) whether within thirty (30) months from the date such damage occurred, the Facility can be restored to a condition such that (i) the Dependable Contracted Capacity established for each Unit immediately following restoration would be at least ninety percent (90%) of its Contracted Capacity, and (ii) the Availability of each Unit over the six (6) months immediately following restoration would exceed seventy-five percent (75%) of its Actual Availability over the six (6) months immediately preceding the Force Majeure. If it is determined that the Facility can be restored to such a condition within thirty (30) months or less from the date such damage occurred, this Agreement may not be terminated under Section 14.6.1, 14.6.3 or 14.6.4 and the Generator shall commence Page 53 restoration of the Facility. Notwithstanding the foregoing, the Generator shall not be required to commence such restoration and this Agreement may be terminated immediately by either Party if, within a reasonable period of time from the date such damage occurred, either (i) the Generator cannot obtain any approval required by the Financing Parties for such restoration, or (ii) the Generator cannot arrange any additional funding required for such restoration on commercially reasonable limited recourse financing terms. If it is determined that the Facility cannot be restored to the condition described above within thirty (30) months from the date such damage to the Facility occurred, or if the Generator is not required to commence restoration under circumstances referred to in the preceding paragraph, this Agreement may be terminated immediately by either Party and the provisions of Section 14.6.1, 14.6.3 or 14.6.4 shall apply. 15. DISPUTE RESOLUTION 15.1 RESOLUTION 15.1.1 The Parties agree to make a diligent, good faith attempt to resolve all disputes arising under or in connection with this Agreement in an equitable manner and in accordance with procedures to be agreed upon before either Party commences dispute resolution by Experts or arbitration. This attempt shall involve discussions between designated representatives of each Party, and then, if such representatives are unable to resolve the dispute pursuant to this Section 15.1.1 within ninety (90) days, the Parties shall appoint an independent Expert or commence an arbitration in accordance with Section 15.1.2 or 15.2. 15.1.2 If such dispute involves in whole or in part (i) a technical engineering issue, then the Parties will in good faith attempt to appoint a suitably experienced and qualified independent engineering firm reasonably satisfactory to both of them, (ii) a financial issue, then the Parties will in good faith attempt to appoint a financial advisor or investment bank reasonably satisfactory to both of them, or (iii) any other issue with respect to which referral to an Expert is provided hereunder, then the Parties will in good faith attempt to appoint an Expert with appropriate expertise for the subject matter reasonably satisfactory to both of them, in each case to act in relation to such dispute and to render a final and binding determination in respect thereof. Absent fraud or wilful misconduct in respect of an Expert's determination, the Parties hereby waive any rights to appeal or review of such determination by any court or tribunal. The Parties shall share the cost of the Expert equally. 15.2 ARBITRATION 15.2.1 If the dispute involves any type of issue not otherwise addressed in Section 15.1.2, or if the Parties are unable to agree upon an acceptable Expert pursuant to Section 15.1.2, or if the Expert does not render a decision within thirty (30) days after completion of the hearing of the matter or if the dispute is not resolved by the Expert within one hundred and fifty (150) days after the referral to the Expert, then either Party may commence arbitration ten (10) days after giving notice to the other Party. Nothing herein shall prevent a Party from commencing arbitration at any time (i) when the delay required for performance hereunder might materially and adversely affect such Party's interest, or (ii) when the other Party fails to fulfill its obligations under this Section 15. Page 54 15.2.2 The arbitration shall be conducted in accordance with the Rules of Arbitration and Conciliation of the International Chamber of Commerce as in effect at the time of the arbitration or as otherwise agreed upon by the Parties (the RULES). 15.2.3 The arbitral tribunal shall consist of three (3) arbitrators. Each Party shall appoint one arbitrator with, in the case of a dispute of a technical nature, knowledge and experience in such technical matters. The two arbitrators so appointed shall appoint the third arbitrator who shall serve as the chairman of the arbitral tribunal. If a Party fails to appoint its arbitrator within a period of ten (10) days after receiving notice of the arbitration, or if the two arbitrators appointed cannot agree upon the third arbitrator within a period of ten (10) days after appointment of the second arbitrator, then such arbitrator shall be appointed pursuant to the Rules. 15.2.4 If the Court of Arbitration of the International Chamber of Commerce is required or requested to appoint an arbitrator, it shall appoint only a person with experience in international commercial agreements and, in particular, the implementation and interpretation of contracts relating to the design, engineering, construction, operation and maintenance of electrical power generating facilities (and if the dispute concerns a technical issue, a person who has knowledge and experience in technical matters). No arbitrator shall be a present or former employee or agent of, or consultant or counsel to, either Party or any Affiliate thereof or any Governmental Authority. 15.2.5 The arbitration shall be conducted in Thailand using the English language unless the use of the Thai language is agreed upon by the Parties. All documents or evidence presented at such arbitration in a language other than in English shall be accompanied by a certified English translation thereof. The arbitrators shall decide the dispute by majority of the arbitral tribunal and shall state in writing the reasons for its decision. Any monetary award of the arbitral tribunal shall be denominated and payable in Baht. 15.2.6 Any decision or award of an arbitral tribunal appointed pursuant to Section 15 shall be final and binding upon the Parties. The Parties hereby waive any rights to appeal or seek review of such a decision or award by any court or tribunal, excluding any statutory defenses or rights of appeal in enforcement proceedings under the Arbitration Act of Thailand (B.E. 2530, or as it may be amended after the Execution Date) that cannot legally be waived. The Parties further undertake to carry out without delay the provisions of any arbitral award or decision, and each agrees that any such award or decision, may be enforced by the Parties against assets of the relevant Party wherever they are located and a judgment upon any arbitration award may be entered by any court or tribunal having jurisdiction. Subject to Section 21, either Party may publicize or otherwise disclose to others the contents of any decision of the arbitral tribunal. 15.2.7 The costs of such arbitration shall be determined and allocated between the Parties by the arbitral tribunal in its award. 15.2.8 Unless otherwise agreed in writing, the Parties shall continue to perform their respective obligations under this Agreement during the pendency of any proceeding by the Parties in accordance with this Section 15. Page 55 15.2.9 The provisions of Section 15.2 shall survive the termination of this Agreement until all obligations which are intended to survive termination have expired. 16. LIMITATION OF LIABILITY 16.1 INDEMNIFICATION 16.1.1 Except as otherwise specifically provided in this Agreement, or unless the damage or injury arises out of, results from, or is caused by, the breach of this Agreement by a Party or by the negligence or misconduct of a Party's own officers, directors, employees, agents, Affiliates, contractors or subcontractors, neither Party shall be liable to the other for any claims, judgments, liabilities, losses, costs, expenses or damages of any kind or character (including loss of use of property) in connection with damages or destruction of property or personal injury (including death) arising out of the performance of the Agreement, including the design, construction, maintenance or operation of property, facilities or equipment owned or used by the other Party, or the use of, misuse of or contact with the electrical energy delivered or purchased hereunder. 16.1.2 Each Party shall indemnify and hold the other Party, and its officers, directors, Affiliates, agents, employees, contractors and subcontractors, harmless from and against any and all claims, judgments, losses, liabilities, costs, expenses (including reasonable attorneys' fees) and damages of any nature whatsoever for personal injury, death or property damage (except workers' compensation claims) caused by any act or omission of the indemnifying Party or the indemnifying Party's own officers, directors, Affiliates, agents, employees, contractors or subcontractors that arises out of or are in any manner connected with the performance of this Agreement, except to the extent such injury, death or damage is attributable to the negligence or misconduct of, or breach of this Agreement by, the Party or its officers, directors, Affiliates, agents, employees, contractors or subcontractors seeking indemnification hereunder. 16.1.3 The Generator shall defend, indemnify and hold EGAT, and its officers, directors, Affiliates, agents, employees, contractors and subcontractors, harmless from and against any and all claims, judgments, liabilities, losses, costs, expenses (including reasonable attorneys' fees) and damages (i) under every applicable environmental law or regulation arising out of the condition of the Site, the Generator's ownership or operation of the Facility, or the Generator's construction of the New Transmission Facilities, including the discharge, dispersal, release, storage, treatment, generation, disposal or escape of pollutants or other toxic or hazardous substances from the Facility, the contamination of the soil, air, surface water or groundwater at or around the Site or any pollution abatement, replacement, removal, or other decontamination or monitoring obligations with respect thereto, and (ii) under any Law arising out of the Generator's construction, testing or commissioning of the New Transmission Facilities, except to the extent such damages under this Section 16.1.3 are attributable to the negligence or misconduct of, or breach of this Agreement by EGAT, its officers, directors, Affiliates, agents employees, contractors or subcontractors. 16.1.4 EGAT shall defend, indemnify, and hold the Generator, its officers, directors, Affiliates, agents, employees, contractors, and subcontractors, harmless from Page 56 and against any and all claims, judgments, liabilities, losses, costs, expenses (including reasonable attorneys' fees), and damages under every applicable environmental law or regulation arising out of the condition of or EGAT's ownership or operation of the New Main Transmission Line, and the New Transmission Facilities and EGAT's Connection (after their transfer to EGAT pursuant to Section 2.8.6), including the discharge, dispersal, release, storage, treatment, generation, disposal, or escape of pollutants or other toxic or hazardous substances from any of such facilities, the contamination of the soil, air, surface water or groundwater at or around any of such facilities or any pollution abatement, replacement, removal, or other decontamination or monitoring obligations with respect thereto, except to the extent such damages are attributable to the negligence or misconduct of, or breach of this Agreement by the Generator, its officers, directors, Affiliates, agents, employees, contractors, or subcontractors. 16.1.5 In no case shall EGAT be liable for damage or destruction of property, facilities or equipment operated by the Generator solely as a result of EGAT's Dispatch or the Generator's operation of the Facility, provided such Dispatch by EGAT was in accordance with the terms of this Agreement and the Grid Code. 16.2 CONSEQUENTIAL DAMAGES Neither Party shall be liable to the other Party for any indirect, incidental, consequential or punitive damages as a result of the performance or non-performance of the obligations imposed pursuant to this Agreement, including failure to deliver or purchase electrical energy hereunder, irrespective of the causes thereof, including fault or negligence. For the avoidance of doubt, (i) neither the Generator's Minimum Take Liability under the Fuel Purchase Agreement nor reasonable termination costs under the Financing Documents shall be regarded as indirect, incidental, consequential or punitive damages, and (ii) the indemnification provisions set out in Section 16.1 shall not be construed as giving indemnity against indirect, incidental, consequential or punitive damages. 17. CHANGE-IN-LAW 17.1 TAX CHANGE ADJUSTMENT On or before the fifth (5th) Business Day after the close of each quarter in any calendar year following the Execution Date the Generator shall (i) determine the amount of any increase or reduction in Taxes (excluding corporate income or similar taxes imposed on or measured by the overall net income of, but only to the extent generally applicable to, Persons doing business in Thailand) paid or payable by the Generator in respect of the Project for the preceding three Billing Periods resulting from any Change- in-Law (or the previous three months if such Change-in-Law occurs prior to the Commercial Operation Date of the First Unit), and (ii) submit to EGAT a certificate setting forth in detail reasonably satisfactory to EGAT the basis of and the calculations for such amount of increase or reduction, including a description of the spare parts purchased by the Generator during such period if the Generator is seeking compensation under this Section 17.1 for Taxes paid or payable on such spare parts. EGAT and the Generator shall promptly determine, in good faith, any necessary adjustments to the Availability Payments or the Energy Payments to equitably reflect any such increase or reduction in Taxes with the intent that the financial position of the Generator shall not be affected in any material respect by such Change-in-Law, provided that the Generator shall not be Page 57 entitled to receive interest on any previously paid or incurred cost except to the extent that the adjustment required under this Section 17.1 shall be delayed due to the negligence of EGAT. Each Party shall cooperate in good faith with the other Party in connection with any such determination. Thereafter, the Availability Payments or the Energy Payments and such other payments (if applicable) shall be adjusted to reflect such increase or reduction and applied in the formulae set out in Schedules 2 and 3. 17.2 CHANGE-IN-LAW ADJUSTMENT 17.2.1 If there is a Change-in-Law which requires the Generator to make any material capital improvement or other material modification to the Facility in order to comply with any Law, the Generator shall submit to EGAT a certificate setting forth in detail reasonably satisfactory to EGAT the costs of such capital improvement or other modification, including financing costs, if any, related thereto. EGAT and the Generator shall promptly determine as set out below, in good faith, any necessary adjustments to the Availability Payments to equitably compensate the Generator for such costs. Each Party shall cooperate in good faith with the other Party in connection with any such determination. For the purposes of this Section 17.2.1, a material capital improvement or other material modification to the Facility shall mean one or more capital improvements or other modifications having an aggregate cost in excess of twenty million (20,000,000) Baht for any calendar year. In determining whether such aggregate cost exceeds twenty million (20,000,000) Baht for any calendar year, the amount representing the total cost of any capital improvement or other modification (after any reduction made to such amount pursuant to Section 17.2.4) shall be deemed to be expended on the date in the calendar year on which the Change-in-Law becomes effective. If such aggregate cost exceeds twenty million (20,000,000) Baht for any calendar year, the Availability Payments shall be adjusted to reimburse the Generator the portion of such aggregate cost in excess of twenty million (20,000,000) Baht. 17.2.2 If there is a Change-in-Law (other than in respect of Taxes) which the Generator believes in good faith will materially increase the costs or materially decrease the revenues of the Generator in connection with the financing, construction, operation or maintenance of the Facility, then the Generator shall submit to EGAT a certificate setting forth in detail reasonably satisfactory to EGAT the basis of and the calculations for the amount of such increase in costs or decrease in revenues. EGAT and the Generator shall promptly determine, in good faith, any necessary adjustments to the Availability Payments or the Energy Payments to equitably reflect such increase in costs or decrease in revenues with the intent that the financial position of the Generator shall not be affected by such Change-in-Law. Each Party shall cooperate in good faith with the other Party in connection with any such determination. For the purposes of this Section 17.2.2, a material increase in costs or material decrease in revenues means any one or more Change-in-Law events resulting in an increase in costs and/or decrease in revenues in excess of five million (5,000,000) Baht for any calendar year. 17.2.3 If there is a Change-in-Law (other than in respect of Taxes) which EGAT believes in good faith will materially decrease the costs or materially increase the revenues of the Generator in connection with the financing, construction, operation or maintenance of the Facility, then EGAT shall submit to the Page 58 Generator a certificate setting forth in detail reasonably satisfactory to the Generator the basis of and the calculations for the amount of such decrease in costs or increase in revenues. EGAT and the Generator shall promptly determine, in good faith, any necessary adjustments to the Availability Payments or the Energy Payments to equitably reflect such decrease in costs or increase in revenues with the intent that the financial position of the Generator shall not be affected by such Change-in-Law. Each Party shall cooperate in good faith with the other Party in connection with any such determination. For the purposes of this Section 17.2.3 a material decrease in costs or material increase in revenues means any one or more Change-in-Law events resulting in a decrease in costs or increase in revenues in excess of five million (5,000,000) Baht for any calendar year. 17.2.4 As soon as practicable after the Generator becomes aware of any Change-in-Law which could reasonably be expected to give rise to an adjustment pursuant to Section 17.2.1 or 17.2.2, the Generator shall notify EGAT of the Change-in-Law and the expected effect on the costs and revenues of the Generator. After the Generator determines that it will be required to make any additional operating or capital expenditures for which the Generator may be entitled to an adjustment to the Availability Payments or the Energy Payments pursuant to Section 17.2.1 or 17.2.2, the Generator shall consult with EGAT regarding such expenditures and Generator shall use all reasonable efforts to implement EGAT's recommendations, if any, to minimize such expenditures consistent with Prudent Utility Practices and the Generator's obligations under this Agreement. If the Generator makes any such capital expenditure without so consulting with EGAT, the amount treated as the cost of the capital improvement or modification to the Facility for purposes of Section 17.2.1 shall be limited to the cost of EGAT's reasonably determined proposal for such improvement or modification to accommodate the Change-in-Law. In the event the Generator initiates consultation with EGAT and (i) EGAT objects to the Generator's proposed expenditure as not being the lowest cost option within a reasonable period of time, and (ii) EGAT demonstrates that there is a lower- cost alternative that complies with the Change-in-Law which is consistent with Prudent Utility Practices and will not adversely affect the costs or manner of operations or maintenance and economic life of the Facility, then the amount treated as the cost of the capital improvement or modification to the Facility for purposes of Section 17.2.1 shall be the cost of the alternative demonstrated by EGAT. 17.2.5 For purposes of this Section 17.2, a change in Grid Code shall be treated as a Change-in-Law. 17.2.6 If a change in an environmental Law requires the Generator to meet a standard which exceeds a standard set out in Schedule 8, the costs attributable to making the Facility or the operation thereof meet such standard shall be subject to reimbursement in accordance with the Section 17.2.1 or 17.2.2, provided that the Generator shall not be entitled to any reimbursement under Section 17.2.1 or 17.2.2 for any portion of such costs which are attributable to making the Facility or the operation thereof comply with any standard set out in Schedule 8. Page 59 17.3 BOI PRIVILEGES 17.3.1 EGAT acknowledges that the Availability Payments contemplated to be paid to the Generator pursuant to this Agreement have been determined based on the assumption that the Generator shall have received certain investment promotion and tax incentives pursuant to the Thailand Office of the Board of Investment Announcement No. 1/1993 on Policies and Criteria for Investment Promotion, Board of Investment Announcement No. 2/1993 on List of Activities Eligible for Investment Promotion and Board of Investment Announcement No. 2/1995 on Provision of Support for Power Generation Activity to be Developed by Independent Power Producers. 17.3.2 If the Thailand Office of the Board of Investment (other than due to an act or omission of the Generator) fails to grant the Generator the investment promotion and tax incentives referred to in Section 17.3.1 at the same tax rates and for the same exemption or incentive periods contemplated under the Board of Investment Announcements described in Section 17.3.1, or subsequent to the granting thereof a Change-in-Law reduces the investment promotion and tax incentives first granted, the Generator may request from EGAT an equitable adjustment in the Availability Payments. Any request by the Generator for such an equitable adjustment shall include a certificate setting forth in details reasonably satisfactory to EGAT the increased costs, expenses, Taxes, decreased revenues and reduced return on equity resulting from such failure to obtain or such subsequent reduction in any such investment promotion and tax incentives. To the extent necessary, the Parties shall promptly determine, in good faith, any necessary adjustments to the Availability Payments or Energy Payments to equitably reflect the impact of such failure to obtain or such subsequent reduction in the investment promotion and tax incentives with the intent that the financial position of the Generator shall not be affected. 18. CONFIRMATION STATEMENT 18.1 CONFIRMATION OF AVAILABILITY AND METERED ENERGY The Generator shall prepare and submit to EGAT a daily Confirmation Statement no later than three (3) Business Days after the day to which it relates. In addition, the Generator shall prepare and submit to EGAT a Meter Reconciliation Statement following the annual meter test or any other meter test conducted pursuant to Section 2.4.3. The Meter Reconciliation Statement shall set out the results of any such test and any adjustments to be made or other action to be taken following the test. 18.2 ACCESS TO INFORMATION If available, the Generator shall provide such information as EGAT may reasonably request to verify a Confirmation Statement provided that such information is not readily available to EGAT by any other means. 18.3 REVIEW OF CONFIRMATION STATEMENT AND METER RECONCILIATION STATEMENT EGAT shall review the Confirmation Statement and any Meter Reconciliation Statement. Each Party shall notify the other Party in writing as soon as practicable, and in any event within fourteen (14) Business Days after having received the Confirmation Statement or Meter Reconciliation Statement of any errors or omissions which the Page 60 reviewing Party believes should be corrected. Subject to any alleged errors or omissions notified by the reviewing Party to the other Party in writing pursuant to this Section 18.3, the information contained in a Confirmation Statement or Meter Reconciliation Statement shall, save in the case of fraud or manifest error and subject to Section 18.6, be deemed to have been approved by both Parties on the fifteenth (15th) Business Day after the Confirmation Statement or Meter Reconciliation Statement shall have been received. 18.4 DISPUTES If the Parties cannot agree on whether any information contained in a Confirmation Statement or Meter Reconciliation Statement is complete or correct within fourteen (14) Business Days after the Confirmation Statement or Meter Reconciliation Statement was received, the dispute shall be referred to an Expert for determination in accordance with Section 15.1.2 or settled by arbitration in the circumstances in which arbitration is provided under Section 15.2.1. 18.5 FINAL CONFIRMATION STATEMENT Any Confirmation Statement which has been approved by both Parties, or deemed to have been approved in accordance with Section 18.3, or which is approved by a final decision of an Expert or arbitration, shall be a final confirmation statement (FINAL CONFIRMATION STATEMENT). The information contained in a Final Confirmation Statement shall be binding on both Parties for the purposes of this Agreement save in the following circumstances: (a) (other than in the case of a determination by an Expert or by arbitration) in the case of misrepresentation and subject to Section 18.6; or (b) in the event of any adjustment pursuant to Section 18.8. 18.6 DISPUTES LIMITATION Nothing in this Section 18 shall prevent either Party from disputing the information contained in or referred to in a Confirmation Statement or Meter Reconciliation Statement at any time where it is reasonable under all the circumstances so to do, provided that no dispute shall be raised in relation to information regarding a Settlement Period after the first anniversary of the day during which such Settlement Period occurred. 18.7 EFFECT OF CONFIRMATION STATEMENT The Final Confirmation Statement (or pending resolution of any outstanding disputes, the Confirmation Statement) shall be used by the Generator to prepare Payment Invoices/Credit Notes as required by Section 19. 18.8 ENERGY PAYMENT ADJUSTMENTS 18.8.1 Where a Meter Reconciliation Statement shows that an adjustment in the amount due is required and the meter inaccuracy cannot be attributed to a particular Settlement Period, the adjustment (in MWh) shown in such Meter Reconciliation Statement shall be converted by a monetary adjustment factor Page 61 (MA) at a rate (in Baht/MWh) calculated in accordance with the following formula: MA = y/x where: x = the total metered Net Electrical Generation at the Metering Point for the relevant quarterly period as shown (unadjusted) in such Meter Reconciliation Statement; y = the total amount paid as components of the Energy Payments (calculated by reference to the terms FCharge//x// and VCharge//x// in the equations in Schedule 3) in respect of such metered Net Electrical Generation in the relevant quarterly period (determined on the basis of such terms). 18.8.2 For the avoidance of doubt, where a Meter Reconciliation Statement shows that an adjustment is required and the meter inaccuracy can be attributed to a particular Settlement Period, the number of MWh delivered in that Settlement Period shall be so adjusted and the adjustment payments shall be made to or by the Generator as appropriate. 18.9 INTERFERENCE WITH METERING If either Party shall interfere with Metering in a manner which gives rise to a need for a meter adjustment necessitating an additional payment or rebate to the other Party, such payment shall be made or rebate paid together with interest thereon at the Default Rate for the period for which such payment or rebate is outstanding. 19. BILLING AND PAYMENT 19.1 PAYMENT INVOICE/CREDIT NOTE The Generator shall prepare and issue to EGAT a Payment Invoice/Credit Note in the form set out in Schedule 6 within three (3) Business Days after the completion of all Final Confirmation Statements for the Billing Period. If there is a dispute over a Confirmation Statement, the Generator may, from the fifteenth (15th) Business Day after it is received by EGAT, treat that Confirmation Statement as a Final Confirmation Statement for the purposes of preparing the Payment Invoice/Credit Note for the applicable Billing Period. Such Payment Invoice/Credit Note shall set out either (i) the net amount of the Availability Payments due to the Generator from EGAT for that month (if the aggregate amount of the Availability Payments exceeds the aggregate amount of the deductions from Availability Payments for that month), or (ii) the net amount of the rebate due to EGAT from the Generator for that month (if the aggregate amount of the Availability Payments is less than the aggregate amount of the deductions from Availability Payments for that month). The Payment Invoice/Credit Note shall reflect any adjustments of invoice or credit amounts required by any Meter Reconciliation Statement in accordance with Sections 2.4.4 and 18.1. Page 62 The Generator shall calculate in accordance with paragraph 4.1.2 of Schedule 2 of this Agreement the adjustment, if any, required to be made in respect of the difference between (a) the Baht/US$ exchange rate used by the Generator in the preparation of such Payment Invoice in accordance with paragraph 4.1 of Schedule 2 of this Agreement and (b) the Baht/US$ exchange rate applicable on the date of payment by EGAT of such Payment Invoice (such adjustment, the FX ADJUSTMENT). The Generator shall issue an adjustment invoice or credit note to EGAT, as applicable, setting forth in sufficient detail the calculation of the FX Adjustment within five (5) Business Days after the date of payment by EGAT of each Payment Invoice. EGAT shall pay the amount shown on any FX adjustment invoice within thirty (30) days after receipt of such invoice. Any FX Adjustment credit note issued by the Generator shall be taken into account in the first Payment Invoice prepared following the issuance of such credit note, provided, however, that the Generator shall pay the amount set forth in any FX Adjustment credit note to EGAT in cash or cash equivalent in accordance with Section 19.3 in the event that such Payment Invoice has not been prepared and submitted to EGAT for any reason within thirty (30) days of when otherwise required to be submitted to EGAT in accordance with this Agreement. Neither Party shall be liable for interest in respect of the FX Adjustment for the period before the date payment or credit of the FX Adjustment is due. The FX Adjustment shall not be subject to adjustment pursuant to Paragraph 4.1 of Schedule 2 of this Agreement. The undisputed amount shown in the Payment Invoice/Credit Note as payable by EGAT or the Generator shall be paid within thirty (30) days after receipt of such invoice or issuing of such credit note. 19.2 OTHER PAYMENTS Except where expressly provided to the contrary any payment to be made by either Party under this Agreement shall be made within thirty (30) days after the Party liable to make payment receives a demand from the other Party for the same. 19.3 PAYMENT PROCEDURE Any sums payable pursuant to this Agreement shall be made by check or by the deposit of funds by wire transfer into a Thai bank account as may be notified by the receiving Party to the paying Party in writing from time to time or by such other means as the Parties may agree. Bank charges will be the receiving Party's expense. Each Party shall notify the other of the details of the bank account to which sums due to that Party shall be credited, identifying such bank account by means of the bank sort code number, the bank account number and bank account title. Any payment that becomes due and payable on a day that is other than a Business Day shall be paid on the first (1st) Business Day thereafter. 19.4 APPLICATION OF PAYMENTS Any payments received by one Party from the other under this Agreement shall be applied in or towards settlement of amounts payable to the recipient, with the longest outstanding amount being settled first, provided that this Section 19.4 shall not apply in respect of any amount which is disputed in good faith in accordance with this Agreement. Page 63 19.5 INTEREST Any amount (other than one which is disputed in good faith in accordance with this Agreement) determined to be properly due from one Party to the other pursuant to this Agreement and remaining unpaid after the due date for payment shall bear interest at the Default Rate from and including the due date as so determined until but excluding the date that it is received by the Party entitled to it. Interest shall accrue at the Default Rate on a day to day basis and shall be compounded monthly. 19.6 DISPUTED ITEMS If any sum or part of a sum shown on an invoice submitted by one Party is disputed in good faith by the other Party, and it is subsequently determined in accordance with the dispute resolution provisions set out in Section 15 that any amount withheld by the other Party should have been properly payable to the Party submitting such invoice, the other Party shall pay to the Party submitting such invoice interest in respect of such disputed amount at the Default Rate from and including the date that the amount in question was due up to but excluding the date on which the Party submitting such invoice receives payment. The undisputed amount of each invoice shall be paid promptly notwithstanding a dispute about any other amount invoiced. If any sum or part of a sum shown on an invoice submitted by one Party is paid but is subsequently disputed or questioned, and is subsequently agreed or determined not to have been properly payable, then such Party shall refund the amount which was not properly payable together with interest at the Default Rate from and including the date of receipt up to but excluding the date of repayment. Whenever any payment or refund is required to be made upon resolution of any dispute under this Section 19.6, appropriate adjustments in respect of VAT shall be made by the Parties including the issuing of credit notes, invoices (receipted or otherwise) and the payment of VAT or further sum of VAT. Any dispute pursuant to the provisions of this Section 19.6 shall be referred to an Expert for determination in accordance with Section 15.1.2. 19.7 TAXES AND FINES 19.7.1 Taxes and Fees The Generator shall pay when due all present and future Taxes (whether national or local) imposed in connection with the ownership, operation and maintenance of the Facility, and shall pay all other duties, assignments, levies, fees, costs and expenses of any kind (whether or not to a Governmental Authority) necessary to assure the performance of its obligations under this Agreement, except as otherwise provided in Section 12.3 or below. EGAT shall pay when due all present and future (whether national or local) VAT imposed on the sale to EGAT and purchase by EGAT of electricity under this Agreement. It is expressly understood that each Party shall be separately responsible for all Taxes imposed on its overall net income. 19.7.2 Fines Any fines, penalties or other costs incurred by the Generator or its agents, officers, directors, employees, Affiliates, contractors or subcontractors for non-compliance by the Generator, its agents, officers, directors, employees, Affiliates, contractors or subcontractors with the requirements of any Laws or Page 64 Governmental Approvals shall not be reimbursed by EGAT but shall be the sole responsibility of the Generator. If any fines, penalties or other costs are assessed against EGAT or its agents, officers, directors, employees, Affiliates, contractors or subcontractors by any Governmental Authority due to the non- compliance by the Generator with any Laws, the Grid Code or Governmental Approvals, the Generator shall indemnify and hold harmless EGAT against any and all losses, liabilities, damages and claims suffered or incurred because of the failure of the Generator to comply therewith. The Generator shall also reimburse EGAT for any and all legal or other expenses (including attorneys' fees and expenses) reasonably incurred by EGAT in connection with such losses, liabilities, damages and claims. If any fines, penalties or other costs are assessed against the Generator or its agents, officers, directors, employees, Affiliates, contractors or subcontractors by any Governmental Authority due to the non-compliance by EGAT with any Laws, the Grid Code or Governmental Approvals, EGAT shall indemnify and hold harmless the Generator against any and all losses, liabilities, damages and claims suffered or incurred because of the failure of EGAT to comply therewith. EGAT shall also reimburse the Generator for any and all legal or other expenses (including attorneys' fees and expenses) reasonably incurred by the Generator in connection with such losses, liabilities, damages and claims. 19.8 SET-OFF All payments to be made by either Party under this Agreement shall be made without set-off, counterclaim, withholding or deduction, including any set- off, counterclaim, withholding or deduction for or on account of Taxes, except as expressly provided in this Agreement or required by applicable Law. 20. INDEXATION 20.1 If any index or external price reference for a particular date or period is not available when required for the purposes of this Agreement, the Parties shall seek to agree to use such other index or price reference for such dates or periods as shall be appropriate in the circumstances. 20.2 If any index or external price reference referred to in this Agreement ceases to be published or if the basis on which it is calculated is materially altered, the Parties shall seek to agree to use such other index or price reference as shall be appropriate in the circumstances. 20.3 Any dispute under Section 20.1 or 20.2 that cannot be resolved by agreement within fourteen (14) days after the dispute arises shall be referred to an Expert for determination in accordance with Section 15. 20.4 This Section 20 is without prejudice to any other provision of this Agreement which provides for periodic review of any indexes or external price references which are used for the purposes of this Agreement. Page 65 21. CONFIDENTIALITY AND ANNOUNCEMENTS 21.1 GENERAL RESTRICTIONS ON THE PARTIES Neither Party shall at any time, whether before or after the expiration or earlier termination of this Agreement, divulge or suffer or permit its officers, directors, employees, Affiliates, agents, contractors or subcontractors to divulge to any other person any confidential information relating to this Agreement or any other information labeled "CONFIDENTIAL" which may be provided to such Party (the RECEIVING PARTY) by the other Party pursuant to this Agreement or the Grid Code, or in the course of negotiating this Agreement or otherwise concerning the operations, contracts, commercial or financial arrangements or affairs of the other Party except: (a) in the circumstances set out in Section 21.2; (b) to the extent otherwise expressly permitted by this Agreement; or (c) with the prior consent of the other Party. 21.2 EXCEPTIONS The restrictions imposed by Section 21.1 shall not apply to the disclosure of any information: (a) which now or hereafter comes into the public domain other than as a result of a breach of an undertaking of confidentiality; (b) which is required to be disclosed in compliance with the conditions of any licenses or any document referred to in any such license with which the Receiving Party is required to comply; (c) which is required to be disclosed by any other requirement of Law or Government Authority; (d) required by any court, arbitrator or administrative tribunal or the Expert in the course of proceedings before it to which the Receiving Party is a party, provided that such parties, to the extent permitted by applicable laws, shall be bound by the provisions contained in this Section; (e) to the employees, directors, Affiliates, agents, proposed assignees, consultants or professional advisors of the Receiving Party, in each case on the basis set out in Section 21.3, provided that such parties shall be bound by the provisions contained in this Section 21; (f) to the Financing Parties or insurers or their respective consultants and advisors, provided that the Receiving Party agrees to keep such information confidential on terms no less onerous than those set out in Section 21.1; and (g) as may be required to comply with the Grid Code. Page 66 21.3 INTERNAL PROCEDURES With effect from the date of this Agreement each Party shall adopt procedures within its organization for ensuring the confidentiality of all information which it is obligated to preserve as confidential under Section 21.1. Those procedures shall be as follows: 21.3.1 The confidential information will be disseminated within the Receiving Party only to persons who need such information to carry out the functions which they are employed to carry out. 21.3.2 The confidential information shall not be used by the Receiving Party for the purpose of obtaining for such Party or any Affiliate thereof or for any other Person any contract or arrangement for the supply of electricity to any Person without the prior consent of the originator of such confidential information. 21.3.3 Employees, directors, Affiliates, agents, proposed assignees, consultants and professional advisors of the Receiving Party will be made fully aware of such Party's obligations of confidence in relation to confidential information and such Party will be responsible for any failure by such Persons to comply with such obligations as if they were parties to this Agreement. 21.3.4 Any copies of the confidential information, whether in hard copy or computerized form, shall clearly identify the confidential information as confidential. 21.4 PUBLIC ANNOUNCEMENTS 21.4.1 Subject to Section 21.4.2, no public announcement or statement regarding the signature, performance or termination of this Agreement shall be issued or made unless both Parties shall have been furnished with a copy of the proposed announcement or statement and shall have approved it (such approval not to be unreasonably withheld or delayed). 21.4.2 Neither Party shall be prohibited from issuing or making any public announcement or statement which is required to be made to comply with any applicable Law or the regulations of any recognized stock exchange upon which the share capital of such Party (or any parent company of such Party) is from time to time listed or dealt in or in response to a requirement of Governmental Authority. 22. INSURANCE AND INDEMNITIES 22.1 INSURANCE REQUIRED The Generator shall fully apprise EGAT of the insurance requirements proposed by the Financing Parties (including draft documentation thereon) and the Generator shall use reasonable efforts to implement recommendations on such requirements reasonably made by EGAT. The Generator shall obtain and maintain in effect such insurance policies and coverage as is required by Law, the Financing Documents and Prudent Utility Practices, including: Page 67 (a) "Comprehensive or Commercial General Liability" insurance with combined single limits for bodily injury and property damages in amounts per occurrence and in the aggregate as required by the law of Thailand; (b) "Workers' Compensation" insurance that complies with the laws of Thailand; (c) "Comprehensive Automobile Liability" insurance with combined single limits for bodily injury and property damage in amounts per occurrence and in the aggregate covering vehicles owned, borrowed or hired; (d) "All Risks Property Coverage" insurance and "Boiler and Machinery" insurance against damage to the Facility (on a "replacement cost" basis) in amounts and subject to deductibles in accordance with this Section 22.1; (e) "Excess Liability" insurance with a limit per occurrence and in the aggregate in an amount to be in excess of the limits of insurance provided in subsections (a) and (c) above; and (f) "Business Interruption" insurance in amounts and subject to deductibles in accordance with this Section 22.1. The Generator shall maintain throughout the Term of this Agreement the scope and type of insurance coverage (other than "Business Interruption" insurance) as is initially required to be obtained and maintained by the Financing Documents, provided the types of insurance and the amount thereof are reasonably acceptable to EGAT. The Generator shall not reduce the scope of such insurance without the prior written consent of EGAT, such consent not to be unreasonably withheld or delayed. 22.2 ENDORSEMENTS The Generator shall cause its insurers to amend its Comprehensive or Commercial General Liability Policy and, if applicable, any Excess Liability Policy and All Risks Property Coverage with the following endorsement items (a), (b) and (c), and to amend its Workers' Compensation and Automobile Liability policies with endorsement item (c): (a) EGAT and its officers, directors, employees and agents are additional insureds under the policy; (b) the insurer waives all rights of subrogation against EGAT, its officers, directors, employees and agents; and (c) notwithstanding any provision of the policy, the policy may not be cancelled, non-renewed or materially changed without the insurer giving thirty (30) days' prior written notice to EGAT. All other terms and conditions of the policy remain unchanged. 22.3 CERTIFICATES REQUIRED At least sixty (60) days prior to the date set for the commencement of construction and annually upon renewal or otherwise in accordance with the terms of the relevant insurance policies, the Generator shall provide for EGAT's review and approval evidence of the insurance required by Section 22.1 in a form acceptable to EGAT. The Page 68 Generator shall also provide EGAT with copies of the receipts appropriate to the annual premiums in respect of the insurance coverages and endorsements. Failure of the Generator to obtain the insurance coverages required by this Section 22 or to provide EGAT with the certificates or copies of receipts, shall in no way relieve the Generator of the insurance requirements of this Section 22 or limit the Generator's obligations and liabilities under any provision of this Agreement. 22.4 APPLICATION OF PROCEEDS For the Term of this Agreement, and subject to the requirements of the Financing Documents and any rights or remedies thereunder, the Generator shall apply any and all insurance proceeds received in connection with any damage to the Facility toward the repair, reconstruction or replacement of the Facility. 23. REPRESENTATIONS AND WARRANTIES 23.1 The Generator represents and warrants to EGAT as follows: (a) The Generator is a corporation duly organized, validly existing and in good standing under the laws of Thailand and is qualified and in good standing in each other jurisdiction where the failure so to qualify would have a material adverse effect upon the business or financial condition of the Generator or the Facility, and the Generator has all requisite power and authority to conduct its business, to own its properties and to execute, deliver and perform its obligations under this Agreement. (b) The execution, delivery and performance by the Generator of this Agreement has been duly authorized by all necessary corporate action, and does not and will not (i) require any consent or approval of the Generator's Board of Directors, shareholders or any other third Party, other than those that have been obtained (evidence of which shall be, if it has not already been, delivered to EGAT), or (ii) result in a breach of, or constitute a default under, any provisions of the Generator's constitution or incorporation documents, any indenture, contract or agreement to which it is a party or by which it or its assets may be bound, or violate any law, rule, regulation, order, writ judgment, injunction, decree, determination or award at present in effect having applicability to the Generator. (c) Each Project Agreement constitutes or, when executed will constitute, a legal, valid and binding obligation of the Generator and is enforceable by and against the Generator in accordance with its terms. Upon the exercise of any step in rights under Section 12.3 or the occurrence of any purchase of the Project by EGAT under Section 14.6, EGAT shall have the right, but not the obligation to assume the rights and obligations of the Generator as provided in such Project Agreements. Moreover, each Project Agreement: (i) will include no terms or conditions which conflict with the provisions of this Agreement, (ii) will not provide that any unsecured creditor of the Generator shall be given higher priority as a creditor than EGAT, other than rights which may arise by operation of Law, Page 69 (iii) will include terms and conditions (including the selection of counterparties and suppliers) that can reasonably be expected to enable the Project to be successfully completed as contemplated in this Agreement, (iv) will include acknowledgments of the counterparties thereto that, to the extent required to do so in order to give effect to the purposes of this Agreement, they shall cooperate in the exercise by the Parties of the step-in and buyout rights and rights related thereto as provided in this Agreement, such rights to include the right of EGAT (but not its obligation) to exercise on behalf of or assume the Generator's rights under that Project Agreement, and (v) in the case of the Financing Documents, will include an acknowledgment by the Financing Parties of the restrictions contained in Section 25.4 relating to assignment by the Financing Parties. (d) No Governmental Approval by any Governmental Authority or pursuant to any Law as in effect on the date hereof, other than those that have been obtained, or to be obtained when required, is necessary for the due execution, delivery and performance by the Generator of this Agreement. (e) This Agreement constitutes a legal, valid and binding obligation of the Generator and is enforceable against the Generator in accordance with its terms. (f) There is no pending or, to the best of the Generator's knowledge, threatened action or proceeding affecting the Generator before any court, Governmental Authority or arbitrator that could reasonably be expected to materially and adversely affect the financial condition or operations of the Generator or the ability of the Generator to perform its obligations hereunder, or that purports to affect the legality, validity or enforceability of this Agreement. 23.2 EGAT represents and warrants to the Generator as follows: (a) EGAT is a juristic person duly established pursuant to the EGAT Act and is duly organized and validly existing under the laws of Thailand and has the full legal right, power and authority to conduct its business, to own its properties and to execute, deliver and perform its obligations under this Agreement. (b) The execution, delivery and performance by EGAT of this Agreement has been duly authorized by all necessary action, and does not and will not (i) require any consent or approval of EGAT's Board of Directors or any other third party, other than those that have been obtained (evidence of which shall be, if it has not already been, delivered to the Generator), or (ii) result in a breach of, or constitute a default under, any provisions of EGAT's constitutive or enabling documents, any indenture, contract or agreement to which it is a party or by which it or its assets may be bound, or violate any law, rule, regulation, order, writ, judgment, injunction, decree, determination or award at present in effect having applicability to EGAT. (c) No Governmental Approval by any Governmental Authority or pursuant to any Law in effect on the date hereof, other than those that have been obtained, or are Page 70 to be obtained, is necessary for the due execution, delivery and performance by EGAT of this Agreement. (d) This Agreement constitutes a legal, valid and binding obligation of EGAT and is enforceable against EGAT in accordance with its terms. (e) There is no pending or, to the best of EGAT's knowledge, threatened action or proceeding affecting EGAT before any court, Governmental Authority or arbitrator that could reasonably be expected to materially and adversely affect the financial condition or operations of EGAT or the ability of EGAT to perform its obligations hereunder, or that purports to affect the legality, validity or enforceability of this Agreement. 24. EQUITY UNDERTAKING 24.1 RESTRICTIONS ON TRANSFERABILITY 24.1.1 Subject to Section 24.2, the Generator shall ensure that after the Execution Date and until the first anniversary of the Commercial Operation Date of the Second Unit, no Sponsor (or any of its respective Affiliates) shall transfer any of its equity ownership interest in the Generator: (a) to any Affiliate, other Sponsor or other Person if such transfer will reduce such Sponsor's (or such Sponsor's Affiliates') equity ownership interest in the Generator to fifty percent (50%) or less of its equity ownership interest in the Generator existing on the Execution Date; and (b) to any Person other than such Sponsor's Affiliates or the other Sponsors without the prior written approval of EGAT, such approval not to be unreasonably withheld or delayed. 24.1.2 Subject to Section 24.2, the Generator shall ensure that after the first anniversary of the Commercial Operation Date of the Second Unit until the fifth (5th) anniversary of such date, no Sponsor (or any of its respective Affiliates) shall transfer any of its equity ownership interest in the Generator: (a) to any Affiliate, other Sponsor or other Person if such transfer will reduce such Sponsor's (or such Sponsor's Affiliates') equity ownership interest in the Generator to twenty-five percent (25%) or less of its aggregate equity ownership interest in the Generator existing on the Execution Date; or (b) to any Person other than such Sponsor's Affiliates or the other Sponsors without the prior written approval of EGAT, such approval not to be unreasonably withheld or delayed. 24.2 QUALIFICATIONS TO EQUITY TRANSFER RESTRICTIONS During the periods that the restrictions set out in Section 24.1 are applicable: (a) EGAT shall be given at least fourteen (14) days' prior notice of any transfer by a Sponsor (or any of its Affiliates) of any interest in the Generator to any other Person; Page 71 (b) any Sponsor or transferee of such Sponsor shall have the right to transfer its interest in the Generator notwithstanding the restrictions set out in Section 24.1 above so long as such transfer is approved in writing by EGAT, such approval to be made or withheld at EGAT's sole discretion; (c) any Sponsor or transferee of such Sponsor shall have the right to pledge its direct or indirect interest in the Generator by way of security to any of the Financing Parties or to any insurer of the investment in the Project, notwithstanding the restrictions set out in Section 24.1 above; and (d) any transferee shall be subject to the same conditions imposed hereby on transfers made by it as are imposed with respect to transfers by the Sponsors except a transferee who acquires shares in the Generator pursuant to an initial public offering of such shares which conforms to the requirements of the Securities Exchange Commission of Thailand. 25. MISCELLANEOUS PROVISIONS 25.1 AMENDMENTS This Agreement may not be amended except by an agreement in writing signed by the Parties. 25.2 WAIVERS OF RIGHTS 25.2.1 No delay or forbearance by either Party in exercising any right, power, privilege or remedy under this Agreement shall operate to impair or be construed as a waiver of such right, power, privilege or remedy. For the avoidance of doubt any waiver by either Party of the obligations of the other Party shall be evidenced by an agreement in writing signed by the Parties. Any single or partial exercise of any such right, power, privilege or remedy shall not preclude any other or further exercise thereof or the exercise of any other right, power, privilege or remedy. 25.2.2 The obligations of the Parties hereunder are civil and commercial in nature rather than governmental. To the extent that either Party may be or hereafter become entitled, in any jurisdiction, to claim for itself or its property, assets or revenues immunity (whether by reason of sovereignty or otherwise) in respect of its obligations under this Agreement from service of process, suit, jurisdiction of any court, judgment, order, award, attachment (before or after judgment or award), set-off, execution of a judgment or other legal process, and to the extent that in any such jurisdiction there may be attributed to either Party or to any of such Party's property, assets or revenues such an immunity (whether or not claimed), each Party hereby irrevocably agrees not to claim and hereby irrevocably waives such immunity to the fullest extent permitted by the laws of such jurisdiction. 25.3 NOTICE 25.3.1 Save for Notices which are given pursuant to the Grid Code (as to which the procedures provided for in the Grid Code shall apply) or Section 5, any notice or other communications to be given by one Party to the other under, or in connection with the matters contemplated by, this Agreement shall be sent to Page 72 the address given and marked for the attention of the Person specified in Schedule 5 or such other address or facsimile number of such Person whom one Party shall from time to time designate by written notice to the other. 25.3.2 Save for Notices which are given pursuant to the Grid Code, any notice or other communication to be given by one Party to the other Party under, or in connection with the matters contemplated by, this Agreement shall be in writing and shall be given by letter delivered by hand or sent by first class prepaid post (airmail if from abroad) or facsimile transmission, and shall be deemed to have been received: (a) in the case of delivery by hand, when delivered; (b) in the case of first class prepaid post, on the third day following the day of posting or (if sent by airmail from abroad) on the sixth day after the day of posting; or (c) in the case of facsimile transmission at the time of receipt. 25.4 ASSIGNMENT 25.4.1 Neither Party shall assign any of its rights or obligations, in part or in whole, under this Agreement without the prior written consent of the other Party, provided that such consent shall not be withheld or delayed if the Party wishing to assign has demonstrated to the reasonable satisfaction of the other Party that the proposed assignee has adequate legal, financial and technical status and ability to observe and perform the obligations of the assignor under this Agreement. 25.4.2 No assignment pursuant to Section 25.4.1 shall be effective unless and until the assignor has procured the proposed assignee to covenant directly with the other Party to observe and perform all the terms and conditions of this Agreement, and has provided to the other Party a certified copy of the assignment (omitting the consideration therefor and any other commercial terms thereof). 25.4.3 No assignment pursuant to Section 25.4.1 shall be effective unless at the same time there is assigned or novated to the assignee the assignor's interest in this Agreement, and any other agreements between the Parties that are necessary to the Facility or its operation. 25.4.4 The preceding provisions of this Section 25.4 shall not apply to an assignment by the Generator of its right, title and interest in and to the Facility or this Agreement by way of security to any Financing Party in accordance with the Financing Documents. EGAT agrees to negotiate with the Generator and the Financing Parties in good faith for the purposes of entering into (i) a consent to the collateral assignment of this Agreement, and (ii) a consent to provide for the security of Financing Parties (including rights and appropriate time to cure the Generator's defaults) which the Generator may reasonably request and which does not materially adversely affect the rights of EGAT hereunder, provided that the Generator will reimburse EGAT for all reasonable costs and expenses incurred in relation thereto. Any assignment permitted under this Section 25.4.4 shall be substantially in the form set out in Schedule 19. Page 73 25.4.5 Notwithstanding the foregoing provisions of Section 25.4.4, as a condition to any such consent EGAT shall require that: (a) any substitute for the Generator under this Agreement that may be appointed by the Financing Parties, or any designee or transferee of the Financing Parties or any purchaser of the Generator or of any of its rights, title and interest under this Agreement from the Financing Parties upon a foreclosure sale or other exercise by them of their security under the Financing Documents, shall have adequate legal, financial and technical status and ability to observe and perform the obligations of the Generator under this Agreement; (b) any such substitute, designee, transferee or purchaser shall agree in writing to be bound by all the terms, conditions and provisions of this Agreement; and (c) the Financing Parties shall have given EGAT at least thirty (30) days' prior notice of the assignment. EGAT shall have the right to reject such assignment if it does not conform to the conditions set out herein. 25.4.6 Unless expressly agreed to by the other Party, no assignment, whether or not consented to, shall relieve the assignor of its obligations hereunder if its assignee fails to perform. 25.5 EFFECT OF ILLEGALITY If for any reason whatsoever any provision of this Agreement is or becomes invalid, illegal or unenforceable, or is declared by any court of competent jurisdiction or any other Governmental Authority to be invalid, illegal or unenforceable or if such Governmental Authority: (a) refuses or formally indicates an intention to refuse, authorization of any of the provisions of or arrangements contained in this Agreement (in the case of a refusal either by way of outright refusal or by way of a requirement that this Agreement be amended or any of its provisions be deleted or that a Party give an undertaking or accept a condition as to future conduct); or (b) formally indicates that to continue to operate any provision of this Agreement may expose the Parties to sanctions under any law, order, enactment or regulation, or requests any Party to give undertakings or to accept conditions as to future conduct in order that such Party may not be subject to such sanctions; and, in all cases, whether initially or at the end of any earlier period or periods of exemption then, in any such case, the Parties will negotiate in good faith with a view to agreeing one or more provisions which may be substituted for such invalid, unenforceable or illegal provision which substitute provisions are satisfactory to all relevant Governmental Authorities and produce as nearly as is practicable in all the circumstances the appropriate balance of the commercial interests of both Parties. The remaining provisions of this Agreement shall remain in full force and effect and shall not be affected by such invalid, illegal or unenforceable provision. Page 74 25.6 ENTIRE AGREEMENT This Agreement and the "Agreement regarding Power Purchase Agreement" entered into between the Parties on the date hereof contain or expressly refer to the entire agreement between the Parties with respect to its subject matter and expressly excludes any warranty, condition or other undertaking implied at Law or by custom and supersedes any and all previous agreements and understandings between the Parties with respect to its subject matter. Each of the Parties acknowledges and confirms that it does not enter into this Agreement in reliance on any representation, warranty or other undertaking by the other Party not fully reflected in the terms of this Agreement. 25.7 COUNTERPARTS This Agreement is executed in two (2) original copies, one each for EGAT and the Generator, each of which when executed and delivered shall constitute an original, but both counterparts shall together constitute but one and the same instrument. 25.8 CURRENCY All payments to be made by either Party to the other Party hereunder shall be in Baht. 25.9 LANGUAGE This Agreement is being executed and delivered in the English language and all modifications, amendments and waivers of and notices given pursuant to any provision of this Agreement shall be in the English language. All other documents, notices and communications, written or otherwise, between the Parties in connection with this Agreement, shall be in either English or Thai language as the Parties deem practicable. However, the Parties agree that the Grid Code shall be in the English language and the communications related thereto shall be in either English or Thai as appropriate. 25.10 THIRD PARTIES This Agreement is intended solely for the benefit of the Parties. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assignees. Nothing in this Agreement should be construed to create any duty or liability to, or standard of care with reference to, any third parties. 25.11 INCONSISTENCIES AND CONFLICTS 25.11.1 In the event of any inconsistency or conflict between the provisions of this Agreement and the Grid Code, the provisions of the Grid Code shall prevail. 25.11.2 In the event of any inconsistency or conflict referred to in Section 25.11.1 existing at the date of this Agreement or arising subsequently, the Parties shall, without prejudice to their rights in respect of a change in the Grid Code, seek to negotiate an amendment to this Agreement which removes the inconsistency or conflict. If the Parties cannot agree on what amendment should be made to this Agreement the dispute shall be referred to an Expert. Page 75 26. GOVERNING LAW AND JURISDICTION 26.1 GOVERNING LAW This Agreement shall be governed by and construed in all respects in accordance with the laws of Thailand. 26.2 WAIVER Each Party irrevocably waives any objection which it may have now or hereafter to the laying of the venue of any proceedings in any court and any claim that any such proceedings have been brought in an inconvenient forum, and further irrevocably agrees that a judgment in any proceedings brought in the courts of Thailand shall be conclusive and binding upon such Party and may be enforced in the courts of any other jurisdiction. 26.3 ARBITRATION For the avoidance of doubt, all disputes arising under or in connection with this Agreement shall be resolved in accordance with Section 15 and nothing contained in Section 26.1 or 26.2 shall be construed as permitting either Party to commence proceedings in any court in any jurisdiction except as may be necessary to enforce an arbitration award or the final determination of a dispute by an Expert. 27. PRIVATIZATION OF EGAT 27.1 The Parties acknowledge that it is the present intention of the Government of Thailand to corporatize and eventually privatize EGAT. At such time that (i) EGAT shall have been privatized, and (ii) the Government of Thailand and all other Governmental Authorities shall cease to Control EGAT, then the Parties shall use their best efforts to obtain the Financing Parties' approval to delete the definition of Governmental Force Majeure and the provisions of this Agreement regarding Governmental Force Majeure, it being the intention of the Parties and the Financing Parties that the need for such provisions would then not be appropriate, and EGAT shall not bear the risk of Governmental Force Majeure as provided for in this Agreement. The events, conditions and circumstances previously described as Governmental Force Majeure shall nevertheless continue to constitute Force Majeure. 28. PERMISSION UNDER EGAT ACT 28.1 This Agreement is the permission issued by EGAT to the Generator pursuant to Section 37 of the EGAT Act, and this permission shall remain valid throughout the Term of this Agreement. Except for those stated in this Agreement, there is no other condition to such permission. Page 76 IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their respective duly authorized officers as of the date first above written. ELECTRICITY GENERATING AUTHORITY OF THAILAND Witness:_____________________________ By:___________________________ (Mr. Viroj Nopkhun) (Mr. Viravat Chlayon) Deputy-Governor-Planning and Policy Governor GULF POWER GENERATION CO., LTD. Witness:_____________________________ By:___________________________ (Mr. Robert M. Edgell) (Mr. Sarath Ratanavadi) Director Director By:___________________________ (Mr Gerard P. Loughman) Director Page 77 EX-21 4 SUBSIDIARIES AND PARTNERSHIPS EXHIBIT 21 EDISON MISSION ENERGY SUBSIDIARIES AND PARTNERSHIPS ----------------------------- As of March 13, 1998 Domestic - -------- Aguila Energy Company (LP) American Bituminous Power Partners, L.P. (Delaware limited partnership) American Kiln Partners, Limited Partnership (Delaware Limited partnership) Anacapa Energy Company (GP) Salinas River Cogeneration Company (Partnership) Arrowhead Energy Company Balboa Energy Company (GP) Smithtown Cogeneration, L.P. (Delaware Partnership) Bergen Point Energy Company (GP) TEVCO/Mission Bayonne Partnership (Delaware general partnership) Blue Ridge Energy Company (GP) Bretton Woods Cogeneration, L.P. (Delaware limited partnership) Bretton Woods Energy Company (GP & LP) Bretton Woods Cogeneration, L.P. (Delaware limited partnership) Camino Energy Company (GP) Watson Cogeneration Company (Partnership) Capistrano Cogeneration Company (GP) James River Cogeneration Company (North Carolina Partnership) Centerport Energy Company (GP & LP) Riverhead Cogeneration I, L.P. (Delaware Partnership) Chesapeake Bay Energy Company (formerly Woodland Energy Company) (GP) Delaware Clean Energy Project (Delaware General Partnership) Chester Energy Company Holds option to purchase piece of property (vacant land) located in or near Richmond/ Chesapeake, Virginia Clayville Energy Company Oconee Energy, L.P. (Delaware limited partnership) Colonial Energy Company (formerly Hentland Farm Energy Company)-Inactive Coronado Energy Company Oconee Energy, L.P. Crescent Valley Energy Company (Inactive) Delaware Energy Conservers, Inc. (Delaware corporation) - Inactive Del Mar Energy Company (GP) Mid-Set Cogeneration Company (Partnership) Desert Sunrise Energy Company (Nevada Corporation) - Inactive Devereaux Energy Company (LP) Auburndale Power Partners, Limited Partnership (Delaware limited partnership) East Maine Energy Company (Inactive) Eastern Sierra Energy Company (GP & LP) Saguaro Power Company, A Limited Partnership (Partnership) Edison Mission Energy Funding Corp. (Delaware corporation) Edison Mission Energy Interface Ltd. (Canadian company) The Mission Interface Partnership 1 Edison Mission Operation & Maintenance, Inc. Mission Operations de Mexico, S.A. de C.V. El Dorado Energy Company (GP) Auburndale Power Partners, Limited Partnership (Delaware limited partnership) EMP, Inc. (Oregon Corporation) (GP & LP) GEO East Mesa Limited Partnership (Partnership) GEO East Mesa Electric Company (Nevada corporation) Four Counties Gas Company (Inactive) Hanover Energy Company Chickahominy River Energy Corp. Commonwealth Atlantic Limited Partnership (Delaware Partnership) Holtsville Energy Company (GP & LP) Brookhaven Cogeneration, L.P. (Delaware Partnership) Indian Bay Energy Company (GP & LP) Riverhead Cogeneration III, L.P. (Delaware Partnership) Jefferson Energy Company (GP & LP) (Inactive) Kings Canyon Energy Company (Inactive) Kingspark Energy Company (GP & LP) Smithtown Cogeneration, L.P. (Delaware Partnership) Laguna Energy Company (Inactive) La Jolla Energy Company (Inactive) Lake Grove Energy Company (Inactive) Lakeview Energy Company Georgia Peakers, L.P. (Delaware partnership) Lehigh River Energy Company (GP) Longview Cogeneration Company (formerly Columbia River Cogeneration Company and prior to that, formerly Cabrillo Energy Company) - Inactive Madera Energy Company (GP) Brookhaven Cogeneration , L.P. (Delaware Partnership) Madison Energy Company (formerly Sunshine Generators, Inc.) (LP) Gordonsville Energy L. P. (Delaware partnership) Mission/Eagle Energy Company Mission Energy Construction Services, Inc. (formerly Glenwood Springs Property, Inc.) Edison Mission Energy Fuel Edison Mission Energy Oil and Gas Four Star Oil & Gas Company Edison Mission Energy Petroleum Pocono Fuels Company (Inactive) Southern Sierra Gas Company TM Star Fuel Company (California general partnership) Mission Energy Holdings, Inc. Mission Capital, L.P. (Delaware limited partnership) owned 97%/3% by EME respectively Mission Energy Holdings International, Inc. (formerly Patapsco Energy Company) (Owns 100% of MEC International B.V.) Mission Energy Indonesia (formerly Chula Energy Company) - Inactive Mission Energy Mexico (Inactive) 2 Mission Energy New York, Inc. (formerly, Allegheny Energy Company) (GP & LP) Brooklyn Navy Yard Cogeneration Partners, L.P. (Delaware Partnership) Mission Energy Wales Company (formerly San Jacinto Energy Company) Mission Hydro Limited Partnership (UK limited partnership) Mission Energy Westside, Inc. (formerly Sun Coast Energy Company) - Inactive Mission Triple Cycle Systems Company (GP) Triple Cycle Partnership (Texas general partnership) Northern Sierra Energy Company (GP) Sobel Cogeneration Company (California general partnership) North Jackson Energy Company (Inactive) Ortega Energy Company Panther Timber Company (GP) American Kiln Partners, Limited Partnership (Delaware limited partnership) Paradise Energy Company - Inactive Pleasant Valley Energy Company (GP) American Bituminous Power Partners, L.P. (Delaware Partnership) Prince George Energy Company (LP) Hopewell Cogeneration Limited Partnership (Delaware partnership) Hopewell Cogeneration Inc. (Delaware corporation) Hopewell Cogeneration Limited Partnership (Delaware partnership) Quartz Peak Energy Company (LP) Nevada Sun-Peak Limited Partnership (Nevada partnership) Rapidan Energy Company (GP) Gordonsville Energy, L.P. (Delaware Partnership) Reeves Bay Energy Company (GP & LP) North Shore Energy, L.P. (Delaware Partnership) Northville Energy Corporation (New York corporation) Ridgecrest Energy Company (GP) Riverhead Cogeneration I, L.P. (Delaware Partnership) Rio Escondido Energy Company - Inactive Riverport Energy Company (GP & LP) Riverhead Cogeneration II, L.P. (Delaware Partnership) San Gabriel Energy Company (Inactive) San Joaquin Energy Company (GP) Midway-Sunset Cogeneration Company, L.P. (Partnership) San Juan Energy Company (GP) March Point Cogeneration Company (Partnership) San Pedro Energy Company (GP) Riverhead Cogeneration II, L.P. (Delaware Partnership) Santa Ana Energy Company (GP) Riverhead Cogeneration III, L.P. (Delaware Partnership) Santa Clara Energy Company (GP) North Shore Energy, L.P. (Delaware Partnership) Northville Energy Corporation (New York corporation) Silverado Energy Company (GP) Coalinga Cogeneration Company (Partnership) Silver Springs Energy Company Georgia Peaker, L.P. (Delaware limited partnership) 3 Sonoma Geothermal Company (GP & LP) Geothermal Energy Partners Ltd. (California partnership) South Coast Energy Company (GP) Harbor Cogeneration Company (Partnership) Southern Sierra Energy Company (GP) Kern River Cogeneration Company (California general partnership) Thorofare Energy Company Viejo Energy Company (GP) Sargent Canyon Cogeneration Company (Partnership) Vista Energy Company (New Jersey Corporation) (GP & LP) Western Sierra Energy Company (GP) Sycamore Cogeneration Company (California general partnership) International - ------------- Edison Mission Energy Asia Pte. Ltd. (formerly Mission Energy Asia Pte. Ltd.) (Singapore) Edison Mission Energy Asia Pacific Pte. Ltd. (Singapore) Edison Mission Energy Fuel Company Pte. Ltd. (Singapore) Edison Mission Operation and Maintenance Services Pte. Ltd. (Singapore) P.T. Edison Mission Operation and Maintenance Indonesia (Indonesia) Edison Mission Energy Holdings Pty Ltd (Australia) (formerly Mission Energy Holdings Pty Ltd) Edison Mission Operation & Maintenance Kwinana Pty Ltd (formerly Mission Operations (Kwinana) Pty Ltd (Australia) Edison Mission Operation & Maintenance Loy Yang Pty. Ltd. (formerly Mission Energy Management Australia Pty. Ltd.) (Australia) Mission Energy Development Australia Pty. Ltd. Mission Energy Holdings Superannuation Fund Pty Ltd. Mission Energy (Kwinana) Pty Ltd Kwinana Power Partnership (Australian G.P.) Edison Mission Energy International B.V. (formerly MEC Mission B.V.) (Netherlands) Edison Mission Energy Power (Mauritius) EME Victoria B.V. (Inactive) Hydro Energy B.V. (Netherlands company) Edison Mission Energy Espana (formerly Energias Hidraulicas, S.A.) (Spain corporation) Iberica de Energias, S.A. (Spain corporation) Electrometalurgica del Ebro, S.A. (Spain corporation) Monasterio de Rueda, S.L. (inactive) Iberian Hy-Power Amsterdam, B.V. (Netherlands Antilles corporation) Hidroelectrica de Olvera, S.A. (Spain corporation) Hidroelectrica del Sossis, S.A. (Spain corporation) Loy Yang Holdings Pty Ltd (Australia) Edison Mission Energy Holdings Pty Ltd (Australia) Mission Energy Holdings Superannuation Fund Pty Ltd.Edison Mission Energy Australia Ltd (formerly Mission Energy Australia Ltd. (an Australian public company) Edison Mission Operation &Maintenance Kwinana Pty. Ltd. Edison Mission Operation & Maintenance Loy Yang Pty. Ltd. Mission Energy (Kwinana) Pty. Ltd. Edison Mission Energy Australia Ltd. 4 Mission Energy Ventures Australia Pty. Ltd. Latrobe Power Pty Mission Victoria Partnership Latrobe Power Partnership Loy Yang Joint Venture MEC Esenyurt B.V. (Netherlands) Doga Enerji Uretim Sanayi ve Ticaret A.S. (Turkish corporation) Doga Isi Satis Hizmetleri Ticaret L.S. Doga Isletme ve Bakim Ticaret L.S. MEC IES B.V. (Netherlands) formerly MEC ESA B.V. ISAB Energy Services s.r.l. (Operator of ISAB ) MEC India B.V. (Netherlands) Edison Mission Energy Power (Mauritius corporation) MEC Indo Coal B.V. (Netherlands) P.T. Adaro Indonesia (Indonesia) MEC Indonesia B.V. (Netherlands) P.T. Paiton Energy Company (Indonesia) MEC International Holdings B.V.(Netherlands) MEC Laguna Power B.V. (Netherlands company) Gulf Power Generation Co. Ltd. (Bangkok corporation) MEC Perth B.V. (Netherlands) Kwinana Power Partnership (Australian GP) MEC Priolo B.V. (Netherlands) ISAB Energy S.r.l. MEC San Pascual B.V. (Netherlands) San Pascual Cogeneration Company International B.V. MEC Sidi Krir (formerly MEC Colombia B.V.) (Netherlands) MEC Wales B.V. (Netherlands) Mission Hydro Limited Partnership (UK) EME Generation Holdings Ltd. EME Victoria Generation Ltd. Mission Energy Development Australia Pty Ltd Gippsland Power Pty Ltd Energy Capital Partnership Enerloy Pty Ltd Mission Energy Italia s.r.l. (Rep. office in Italy) P.T. Mission Operation and Maintenance Indonesia (Indonesian company) Mission Energy Interface Ltd. (Canadian company) The Mission Interface Partnership (Province of Ontario general partnership) Mission Energy Company (UK) Limited (UK private limited company) Derwent Cogeneration Limited (UK private limited company) Edison Mission Energy Limited (UK private limited company) Mission Energy Services Limited (UK private limited company) Mission (No. 2) Limited (UK private limited company) Pride Hold Ltd. (UK corporation) Lakeland Power Development Company (UK corporation) Lakeland Power Ltd. (UK corporation) Mission Hydro (UK) Ltd. Mission Hydro Ltd. Partnership (UK) First Hydro Holdings Company First Hydro Finance plc First Hydro Company P.T. Edison Mission Operation and Maintenance Indonesia (Indonesia) 5 EX-27 5 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM EDISON MISSION ENERGY AND SUBSIDIARIES FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1997 JAN-01-1997 DEC-31-1997 585,883 0 76,935 0 0 694,587 3,142,551 201,564 4,985,145 339,802 2,532,121 150,000 0 64,130 762,472 4,985,145 0 785,606 0 353,718 0 0 223,478 185,515 57,363 128,152 0 (13,126) 0 115,026 0 0
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