X - Ds -M -yR) - Document of The World Bank FOR OFFICIAL USE ONLY MICROF'ICHE COPY MICROFICHE COPY ~~~~~~~~Report No. 10465-TH Report No. 10465-TH Type: ('AR) MAHAMMAD), / X80478 / D8 04'7/ EAlIE STAFF APPRAISAL REPORT THAILAND BONGKOT GAS TRANSMISSION PROJECT JUNE 11, 1992 Industry and Energy Operations Division Country Department I East Asia and Pacific Region This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EOUIVALENTS (As of December 15, 1991) Currency Unit - Baht (B) US$1.0 - B 25.52 B 100 US$3.92 UNITS AND EOUIVALENTS bbl barrel bcEf billion cubic feet bpd barrels per day btu British thermal unit CWh gigawatt hours kcal kilocalorie KWh kilowatt-hour koe kilogram oil equivalent km kilometer lb pound mcf thousand cubic feet mmbtu million British thermal unit mmcfd million standard cubic feet per day MW megawatt ppm parts per million tcf trillion cubic feet toe tons of oil equivalent tonne metric ton (- 2,205 lb) ABBREVIATIONS AND ACRONYMS ADB Asian Development Bank CNG Compressed Natural Gas cO Carbon monoxide CO2 Carbon dioxide DMR Department of Mineral Resources EA Environmental Assessment ECCT Energy Conservation Center of Thailand EGAT Electricity Generating Authority of Thailand JDA Joint Development Area JEXIM Japan Exim Bank LNG Liquified Natural Gas LPG Liquified Petroleum Gas MIS Management Information System MOF Ministry of Finance NEA National Energy Administration NEB National Environmental Board NEPC National Energy Policy Committee NEPO National Energy Policy Office NESDB National Economic and Social Development Board PTT Petroleum Authority of Thailand PTTEP PTT Exploration and Production Co. Ltd. SCADA Supervisory Control and Data Acquisition PTT's FISCAL YEAR October 1 to September 30 FOR OMCIAL USE ONLY THlAILcAND BONGKOT GAS TRANSMISSION PROJECI Loan and Prolect Summary Borrower: Petroleum Authority of Thailand (PTT) Guarantor: Kingdom of Thailand Amount: US$105 mil:ion equivalent Terms: 17 years, including a grace period of 4 years, at the Bank's standard variable interest rate. Project Objectives: The objective of the project is to increase the gas supply capabilities of Tha4.land by: a) expanding the gas transmission system; b) strengthening the institutional functioning of PTT; and c) making more efficient use of capital resources in the gas sector through annual review of PTT's investment program. Proiect Description: The project consists of the following components: (a) a 32-inch, 175 km long submarine pipeline from the Bongkot gas field to the existing Erawan production complex; (b) a 24-inch, 160 km long submarine pipeline from Erawan to a terminal at Khanom; (c) a new Supervisory Control and Data Acquisition (SCADA) and telecom system and renovation of the existing system; (d) a riser platform; (e) equipment including additional compression capacity; (f) upgrading of PTT's Management Information System (MIS) and training of staff; and (g) a study for preparation of safety and environmental standards, and a study for a second pipeline. Benefits: The proposed project would have significant economic and environmental benefits. The gas will be used for power generation, in a combined-cycle plant, which has been shown to be part of Thailand's least-cost solution to power generation. The economic benefits of the project are derived from the value of fuel (mainly fuel oil) displaced by gas, corrected for the differential in thermal efficiency. In addition, the project produces a significant volume of condensate saleable in international markets. Environmentally, natural gas is a clean and low-polluting fuel compared to alternative sources of energy. Risks: Risks for the project revolve around two areas: (a) the availability cf sufficient gas reserves; and (b) the cost of producing such reserves. The gas reserves have been assessed and certified to be about 1.5 tef, the volume on which the proposed project is based. This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. The risk of insufficient gas reserves is consequently low. The risks associated with potential increase in production costs stem from the complex nature of the reservoirs. This risk has been mitigated by taking into account appropriate contingencies in setting cost parameters, and benefitting from the experience of another gas producer, which has operated nearby since 1981. - iii- f&stimatpd Cost: Local Foreign Total Pipe material (Line pipe) - 77.2 77.2 Pipeline coating & construction 15.0 121.2 136.2 TOTAL equipment - 20.0 20.0 SCADA/telecom/civil work 6.7 6.6 13.3 Riser pl tform - 38.0 38.0 Engineering consultancy 3.5 11.5 15.0 Studies and training 0.3 2.9 3.2 Taxes and duties 13.0 - 13.0 Base Cost 38.5 277.4 315.9 Physical contingency 3.1 22.2 25.3 Price contingency 0.8 6.0 6.8 Total project cost 42.4 305.6 348.0 -^ther cogts: Interest during construction and others costs 2.6 19.4 22.0 Total Financing Required 45.0 325.0 370.0 Financing Plan: Local Foreign Total Japan Exim Bank 7.0 45.0 52.0 Asian Development Bank 8.0 50.0 58.0 U.S. Exim Bank 0.7 6.6 7.3 Conr-ercial Borrowing 10.0 46.0 56.0 PTT Internal Cash 15.1 76.6 91.7 IBRD 4,2 100.8 105.0 Total Financing Required 45.0 325.0 370.0 Estimated Disbursements: Bank FY 19 1994 1995 ------(USS million)------ Annual 75 21 9 Cumulative 75 96 105 Economic Rate of Return: 26X sM : IBRD No. 23485 and IBRD No. 23519 - iv - THAILAND BONGKOT GAS TRANSMISSION PROJECT Staff Appraisal Repore TAbl2 of Contents Page No. I. THE ENERGY SECTOR A. The Role of Energy in the Thai Economy . . . . . . . . . . . 1 B. Energy Resources and Production . . . . . . . . . . . . . . 1 C. Energy Consumption and Demand . . . . . . . . . . . . . . . 2 D. Future Prospects for Energy . . . . . . . . . . . . . . . . 5 E. The Institutional Framework . . . . . . . . . . . . . . . . 5 F. Sectoral Issues and Strategy . . . . . . . . . . . . . . . . 6 II. TIE GAS SECTOR A. Background . . . . . . . . . . . . . . . . . . . . . . . . 9 B. Gas Reserves ............. 9 C. Production of Gas . . . . . . . . . . . . . . . . . . . . 10 D. Gas Availability . . . . . . . . . . . . . . . . . . . . . 10 E. Gas Demand . . . . . . . . . . . . . . . . I . . . . . . 12 F. Gas Pricing . . . . . . . . . . . . . . . . . . . . . . 15 G. Experience with Previous Bank Loans . . . . . . . . . . . 15 H. Rationale for the Bank Involvement . . . . . . . . . . . 16 III. PROJECT A. Project Background . . . . . . . . . . . . . . . . . . . . 18 B. Project Objectives . . . . . . . . . . . . . . . . . . . . 18 C. Project Description . . . . . . . . . . . . . . . . . . . 18 D. Status of Project Preparation . . . . . . . . . . . . . 23 E. Environmental and Safety Aspects . . . . . . . . . . . . . 23 F. Project Implementation and Schedule . . . . . . . . . . . 25 G. Project Costs . . . . . . . . . . . . . . . . . . . . . . 26 H. Project Financing Plan . . . . . . . . . . . . . . . . . . 27 I. Procurement and Disbursement . . . . . . . . . . . . . . . 28 J. Monitoring, Reporting and Supervision . . . . . . . . . . 31 This report is based on the findings of an appraisal mission to Thailand in December 1991, comprising Messrs./Mme. N. Farhandi (Task Manager), M. Hanson-Costan (Financial Analyst), H. Schober (Project Engineer), T. Fitzgerald (Petroleum Specialist) and Y. Ziv (Environmental Specialist). Hr. H. Razavi (ESMOD) reviewed the economics of the project. The Peer Reviewers were: Messrs./Mme. A. Hashayekhi (FODG4), A. Malbotra (ASTEG) and D. Mehta (EA1IE). The project was cleared by Messrs. C. Madavo, Director EAl and V. Nayyar, Chief EAlIE. -V IV. BORkOWER A. Ba^kground . . . . . . . . . . . . . . . . . . . . . . . . 33 B. Organization . . . . . . . . . . . . . . . . . . . . . . . 33 C. Staffing and Training ... . . . . . . ..... . . . . 34 D. Operations and Management ... . . . ... . . . . . . . 36 V. FINANCIAL ANALYSIS A. Past Performance .... . . . ...... . . . . . . . . 39 B. Present Financial Position ... . . . . . . . . . . . . . 41 C. Financial Outlook .... . . . . . . . . . . . . . . . . 42 D. Investment Program and Financing Plan . . . . . . . . . . 44 VI. PROJECT JUSTIFICATION AND. RISKS A. Economic Benefics ........... .... .... . 46 B. Environmental Benefits ........ ... .. .. .. . 47 C. Project Risks . . . . . . . . . . . . . . . . . . . . . . 48 VII. AGREEMENTS REACHED AND RECOMMENDATION A. Agreements .49 B. Recommendation .51 1. Commercial Energy Balance .52 2. Commercial Energy Demand .53 3. Prices of Selected Energy Products . . . . . . . . . . . . . . 55 4. Geology and Petroleum Reserves .... . . . . . . . . . . . . 58 5. Present Gas Production and Consumption . . . . . . . . . . . . 62 6. Forecast of Natural Gas Supply/Demand . . . . . . . . . . . . 63 7. Projected Gas Demand by EGAT ..... . . . . . . . . . . . . 66 S. Project Diagrammatic Description . . . . . . . . . . . . . . . 67 9. Bongkot Field ....... .. .. .. .. .. .. . .. . . 68 10. Summary of Environmental Assessment . . . . . . . . . . . . . 72 11. Project Implementation Organization . . . . . . . . . . . . . 82 12. Project Implementation Schedules . . . . . . . . . . . . . . 83 13. Annual Capital Expenditures . . . . . . . . . . . . . . . . . 84 14. Schedule of Disbursement . . . . . . . . . . . . . . . . . . . 85 15. PTT's Past Financial Performance . . . . . . . . . . . . . . . 86 16. PTT's Financial Projections . . . . . . . . . . . . . . . . . 89 17. PTT's Capital Investment Program . . . . . . . . . . . . . . . 96 18. Economic and Financial Analysis . . . . . . . . . . . . . . . 97 19. Selected Documents and Data Available in the Project File . 101 CHART : PTT Organization MAPS : IBRD No. 23485 and IBRD No. 23519 I. THE ENERGY SECTOR A. The Role of Energy in the Thai cqonmy 1.1 Sinca '.987, GDP growth in Thailand has averaged 11.5X, making Thailard the fastest growing economy in the world. Commercial energy, particularly oil and gas, plays a critical role in Thailand's economy because (a) Thailand '.. a relatively modest endowment of commercial energy resources and (b) the country's dramatic industrialization in ree~ent years has led to a sharp increase in the consumption of commercial energy. Demand for commercial energy continues to far exceed domestic supplies. This gap is lik6ly to intensify in the future, in view of the continued and rapid economic growth expecteu in Thailand and the uncertair. prospects of discovering further major oil and gas reserves. '.2 Like other middle-income, oil-importing countries, Thailand's nomy is greatly affected by the price of oil. In the earlv 1980s, when country faced sharp increases in oil import prices and then the oil I absorbed over one third of the country's export earnings, Thailand was ab_ ro maintain growth, but only at the expense of high inflation, large fiscal md ex-rnal deficits, and heavy international borrowings. While the Government implemented fiscal policy measures to revive the economy, the dec'.ne in the price of oil in 1986 was the single most important factor i., brii-irg about a surplus in the country's current account. Furthermore, ti i Government's decision to retain most of the oil windfall, rather than n sing it on to consumers, helped to increase national savings, resulting in increased investments. 1.3 Despite the country's impressive economic growth, per capita energy consumption in Thailand and the type of energy consumed is that of a middle-income developing country: a modest 320 kilogram oil equivalent (koe) consumption of energy per capita (compared with the average 420 koe for all Asia) and a relatively high share (35X) of traditional fuels in the final energy consumption. This is explained by the size of the rural population and the relatively high price of commercial energy compared with rural income levels, which places commercial energy beyond the reach of the lower-income group. B. Energy Resources and Production 1.4 As of end-1990, the remaining recoverable reserves of oil in Thailand totalled about 260 million barrels, including about 195 million barrels of condensate, which would have to be produced in association with offshore gas, and about 65 million barrels of crude oil. Possible additional oil reserves are estimated at about 125 million barrels, consisting of about 65 million barrels of condensate in off-shore gas fields and 60 million barrels of oil (see para. 2.2). Oil production in Thailand is currently limited to Phet crude from the Sirikit oil field in -2- Kamphaeng Phet Province, which amounted to 22,000 barrel per day (bpd) in 1990. In addition, about 19,000 bpd of condensate were produced in association with gas from offshore fields in the Gulf of Thailand. To meet the country's oil demand, Thailand imported 145,000 bpd of finished petroleum products, and 208,000 bpd of crude for processing in its local refineries. Natural Gas 1.5 Natural gas has been discovered mostly by companies exploring for oil. As of end-1990, the remaining proved and probable reserves of natural gas in inailand totalled about 7 tcf. Possible additional gas reserves are estimated at about 3.7 tcf. Gas production in 1991 was about 770 mmcfd, of whnich 670 mmcfd were produced from the offshore fields. Hydro Power 1.6 Thailand's hydropower potential, excluding that of its two main international rivers--the Mekong and the Salween--is estimated at 9,300 MW, of which about 2,250 MW (with an annual generation capability of 5,400 6Wh) has already been harnessed. Thailand is also importing 750 GWh from Lao PDR and Malaysia. Higher iulvestment costs and environmental concerns are the major constraints for further development of hydro power in Thailand. 1.7 Thailand is endowed with relatively low grade coal resources, generally categorized as lignite. Thailand's geological coal resources amount to 2.2 billion tons (about 450 million toe), of which an estimated 800 million tons are economically exploitable reserves. Almost 70X of these resources are located in the Mae Moh Basin in northern Thailand which is exploited solely by EGAT, the largest user of coal. The production of local coal in 1990 was about 9.8 million tons. In addition. Thailand imported 0.3 million tons of coal in 1990, for use in the industrial sector. C. Energy Consumption and Demand 1.8 In 1990, total supply of commercial energy in Thailand was about 28 million tons of oil equivalent (toe). This was a two and a half fold increase over 1980. Petroleum represented 701 of the total supply; natural gas 16X, lignite 91, hydro power 4Z, and coal 1Z. Since Thailand exports very little commercial energy, the entire supply was consumed in the country. Table 1.1 summarizes the past consumption and the prospects for commercial energy demand in Thailand. A detailed energy balance is given in Annex 1. -3- Table 1.: PRIMARY CONMERCIAL ENERGY-CONSUMPTION AND PROJECTED DEMAND (1985-2005) (million toe) Primary Commercial 1985 1990 1995 2000 2005 Energy _ _ _ _ _ _ _ _ _ _ Petroleum 10.8 19.6 32.7 43.5 49.4 Natural Gas a/ 2.6 4.5 6.9 9.1 9.0 Hydro power 1.0 1.1 1.4 2.0 1.6 Coal/Lignite 1.6 2.8 5.0 10.4 21.0 TOTAL 16.0 28.0 46.0 65.0 81.0 Average Growth p.a. - .9% 10.4X 7.2X 4.5X SOU: PM T a/ Dry gas-suppty conutraint. 1.9 Final commercial energy consumption in the economy continues to be dominated by the transport sector, which in 1990 accounted for 40X, followed by the industrial and commercial sectors, accounting for 30% and 24X respectively. Traditional fuel (fuelwoods, charcoal, and agricultural residues) continues to represent a significant albeit rapidly declining share of energy consumption in the rural residential sector. Petroleum 1.10 Demand for petroleum products ir 1990 was about 201 higher than in 1989. Since 1985, LPG consumption has grown at an annual average rate of 111. largely because of its increasing use in the residential sector, but also in petrochemical industries. Gasoline consumption has grown at an average 12X p.a. since 1985, reflecting increased consumption in the transport sector.1' Demand for jet and aviation fuel grew at 11 p.a. becausr of increased air travel. Fuel owl demand grev at about 13X a year, due to increased demand from industries and sea vessels as well as its continum.ng use in electricity generation. Diesel oil consumption grew at 121 p-a. and had the highest Powth between 1987 and 1990, averaging about 14.61 p.a. These rates of 6?owth were realized despite an increase of about 1.9 Baht per lite' ..L the retail prices of petroleum products. Table 1.2 summarizes tlO -Ast consumption and the projected demand for petroleum products in Thailand. _J Automobil sale In 1990 grow at 45%. Transport sector consumpUon also grew because of Increased transport of agrIculural products and of construction raw materials as well as the expansion of fisheries (and related boaUng). -4- TI1able.a: PETROLEUM PRODUCTS CONSUMPTION AND PROJECTED DEMAND (1985-2005) (thousand bpd) 1985 1990 1995 2000 2005 Avg. Grcwth I ~~~~~~~~~~~~p.a. ___ _______ (1990-2005) LPG = 18 30 40 50 80 6.8% GASOLINE 36 65 95 130 1'" 5.2X JET/KEROSENE a/ 24 40 60 80 120 7.6% DIESEL OIL 95 170 290 400 '.o 7.3% FUEL OIL 39 90 165 210 j _6 _ 3.9% TOTAL 212 395 650 870 | 990 6.3% SOURCE: PTT a/ Assumed demand for keroene temairis constant at 2000 bpd botween 1990-2005 1.11 In 1990, Thailand imported its crude oil from the Middle East (641), and .-rom Malaysia and Brunei (36%). The imported crude is processed in the country's three refineries: the Bangchak Petroleum Co., Ltd. (BPC) refinery --in which PTT has a 30% interest-- with a current capacity of 65,000 bpd; the Thai Oil Co., Ltd. (TOC) refinery -- in which PTT owns a 49% interest -- with a current capacity of 107,000 bpd; and the Esso Standard Thailand Ltd. refinery --wholly owned by Esso Eastern Inc.-- with a capacity of 65,000 bpd. 1.12 The marketing of petroleum products in Thailand is shared by PTT (about 30X), Esso (24%), Shell (23%), Caltex (14%), and others (9%). As of April 1990, there were about 3,250 retail stations in Thailand. Power 1.13 Thailand's total installed generating capacity as of September 1990 was 7,970 MW, and ano.her 4,193 MW will be added by December 1994. The additional capacity includes the new 600 MW combined-cycle plant at Khanom, which will use natural gas from the proposed Bongkct project. Existing generating facilities consist of: conventional thermal plants (54%); hydropower i3%); combine'-cycle plants (15%); and combustion turbines (3%). 1.14 Per capita electricity consumption in Thailand has grown from 19 KWh in 1961 to 606 KWh in 1989. Demand for electricity, particularly in the past two to three years, has surged, with about a 15% average increase a year, fueled mainly by rapid GDP growth in the industrial rector, but also by the recent substantial expansion in the residential sector, both in urban and rural areas. The industrial sector consumed about 48% of the -5- electricity, the residential and commercial sector each about 22X, and the government and other public facilities about 81. 1.15 De-and for coal in Thailand surged during the period of high oil prices. The total share of coal consumption in commercial energy, which was less than 41 in 1980, is now about 91, or 2.2 million toe per year. This corresponds to a 17X increase per year, thre. times average GDP growth. Domestic coal supplies about 901 of demand. The power sector accounts for 801 of total coal consumption. Based on current consumption, and co;.sidering proeluction constraints due to environmental reasons, EGAT needs to start importing coal in 1996, to supplement the local supply in order to meet its power generation requirements. D. Future ProsRects for Energv 1.16 While the energy elasticity of GDP growth in Thailand between 1985 and l993 was 1.2, reflecting the continuous expansion of energy consumption in the industrial sector, the past trend is not expected to continue because of increased efficiency in energy use and, to a lesser degree, the structural shift away from heavy industry to light manufacturing and services. The Government accordingly projects that total energy consumption wi?l grow at an average rate of 8.71 a year between 1990 and the year 2000, hence an implied energy/GDP elasticity of 1. This is a realistic forecast considering projected growth of the various sectors. Oil consumption is expected to increase at the rate of 81 a year between 1990 and 2000, and natural gas consumption at 71 a year, primarily because of a supply constraint. In the power sector, the latest forecast by EGAT envisages a 14.51 base-case growth for 1992, followed by an 3.41 growth for 1993-97 and 6.9Z for 1998-2000. Demand for domestic coal is expected to increase at about 141 a year throughout this decade. Annex 2 provides PTT's detailed forecast of commercial energy demand in nailand. E. The Institutional Framework 1.17 Institutional arrangements for the regulation of Thailand's energy sector are rather complex, cutting across several ministries and agencies. The principle actors are: (a) the National Economic and Social Development Board (NESDB), the government agency responsible for the formulation of overall economic and social policy, reporting to the Office of the Prime Minister; (b) the National Energy Policy Committee (NEPC), which acts on behalf of the Cabinet on all matters related to energy policy and planning; (c) the National Energy Policy Office (NEPO), a senioi policy formulation, coordination and advisory body focused on energy matters, which serves as a secretariat to NEPC; (d) the Department of Mineral Resources (DMR), which is responsible for resource assessment, granting of licenses for exploration and production, setting and enforcing - 6 - of environmental and safety standards governing production activities, and royalty collection; (e) the National Energy Administration (NEA), under the Ministry of Science, Technology and Energy, which is responsible for development of non-conventional energy sources, energy conservation, and identification and promotion of new uses for domestic energy sources; and (f) the National Environment Board (NEB), chaired by a Deputy Prime Minister and responsible for advising the Cabinet on all aspects of environmental protection in Thailand. 1.18 While the public enterprises in the energy sector enjoy a large degree of autonomy in the conduct of day-to-day operation, the Government continues to control matters related to investment planning and financing. Recently, however, the Government is increasingly introducing measures to pave the way for commercialization of revenue-generating public enterprises. PTT is among the first state enterprise to be selected by the Ministry of Finance (MOF) for de-regulation so long as it meets a set of profitability and pruductivity performance criteria. F. Sectoral Issues and Strategy 1.19 During the past decade, the Government and the Bank have coopezated to identify and address the following issues in the energy sector: (a) Insufficiency of domestic energy resources to meet the growing demand is the most critical issue in the sector. Since the late 1970's, the Government has made serious efforts to reduce the country's dependence on imported energy. As a result, the share of imports in commercial energy declined from 94X in 1980 to 63X in 1990, primarily through increased production of domestic coal and natural gas. However, it is now recognized that further expansion of domestic energy supply is limited and the country is likely to rely more neavily on energy imports in the future. The Government is therefore attempting to devise an energy import policy which would minimize both the risk and the expected economic cost of energy imports to the country. The Government and the Bank are cooperating in exploring possibilities of importing gas and liquified natural gas (LNG) from the countries in the region (para. 2.13). (b) Heavy burden of energy investments on public resources has been recognized as an impediment to economic growth. As a result, the Government and the Bank have cooperated in investigating various avenues to promote private sector participation in the energy sector. In the power sub-sector, which is the country's most capital-intensive industry, the Government has adopted a policy towards potential commercialization of EGAT, encouragement of private independent power generation and private cogeneration. In the petroleum sector, private oil companies have taken the major share in refining and distributing petroleum products. In - 7 - the gas sub-sector, private companies dominate upstream activities. In addition, the recent reorganization of PTT into profit centered business units is an initial step towards commercialization of PTT and eventual privatization of its individual business units. (c) Subsidies and cross-subsidies in energy prices have been recognized as an important contributor to inefficient use of energy. During the 1980's, the Government introduced successive increases in power tariffs to align the rates with the cost of supply. In 1987, the Government took a major step towards. floating retail oil prices by tying local ex-refinery prices to the world market through weekly price adjustments based on Singapore-posted prices. There are some remaining distortions in the relative price structure of petroleum products. The Government is taking steps to align the relative price structure of petroleum products with the structure of international prices and domestic refining costs. The prices of selected energy products are given in Annex 3. (d) Judicious use of energy has been recognized as a necessity for coping with the economic, financial and environmental costs of energy supply. Energy conservation has become, since the introduction of the Sixth Development Plan (1988-92), a formal objective of the energy sector policy. Accordingly, the Plan provides for: (i) the establishment of the Energy Conservation Center of Thailand (ECCT) charged with promoting energy conservation through public awareness, consulting assistance, training, inspection, research and development; (ii) the establishment of the Industrial Finance Corporation of Thailand and other financing agencies to provide low-interest loans to industrial factories which adopt energy saving processes and systems; (iii) the reduction of taxes and duties on energy- efficient equipment and appliances; (iv) the establishment of educational institutes to promulgate energy knowledge to students and the public; (v) consideration for enacting an Energy Conservation Promotion Law mandating energy efficient designs for new industrial and commercial buildings and systems, and improving features of existing ones; and (vi) promoting transfer of technology including between the Government agencies and the privat_ sector. These directives are currently being put into practice by the NEA and its implementing arm, the ECCT. (e) Environmental impacts of energy nroduction and consunmtion have become a topic of public debate. The Government has recognized the significance of the issue and is fully committed to the development of the energy sector in an environmentally sound manner. Environmental concerns in the next few years will be focused on: (i) the impacts of rapid expansion of power and mining facilities; (ii) the ecological acceptability of hydropower projects involving dams; and (iii) the adequacy of the existing environmental regulatory framework for formulating policy and standards, enforcing compliance and monitoring the quality of the environment. Measures to strengthen the environmental safety of gas production, transmission and distribution are incor?orated in the proposed project (paras 3.16 - 3.22). - 9 . II. THE GAS SECTOR A. Background 2.1 The natural gas indutstry in Thailand started in August 1981, with transmission of offshore gas from Erawan field to Rayong through a 34-inch, 425- km long submarine pipeline financed by the Bank under Loan 1773-TH. The Erawan gas field is operated by Unocal, the operator of the offshore fields, under a production-sharing agreement. After extraction of gas liquids in a gas separation plant at Rayong (finarnsd by the Bank under Loan 2184-TH), the dry gas is transported to the Bangkok area through a 160-km onshore pipeline, primarily for use in EGAT's power planta but also for use in the industrial sector. The gas liquids are used to produce Liquified Petroleum Gas (LPG) for domestic consumption and to provide feedstock for Thailand's petrochemical plants. B. Gas Reserves 2.2 Due to the complex geology of the basins in the Gulf of Thailand, the reserves are distributed in many small reservoirs without easily definable limits. Hence, the reserve calculations --at least prior to significant production history-- are based on statistical occurrence rather than measured quantities. The relatively high cost associated with production of Thailand's offshore gas makes reserve estimates highly price sensitive and rather subjective. A more detailed discussion of the general geology of Thailand's sedimentary basins and its hydrocarbon reserves is given in Annex 4. A summary of the reserves is given in Table 2.1. Table 2.1: Gas and Condensate Reserves (end-1990) Offshore Gulf of Thailand Remaining Proved and Probable: 7068 Gas Developed 3868 (bef) Undeveloped : 3200 Possible Reserves Remaining Proved and Probable: 209 Condensate Developed : 138 (million bbl) Undeveloped : 71 Possible Reserves :104 Soure: Mouic. Eatlmtc - 10 - 2.3 Based on the above, the gas reserve life at the current production rate is about 28 years, and at the production rate forecasted for the year 2000 is about 23 years. This is an adequate reserve-to- production ratio (R/P). C. Production of Gas 2.4 Thailand's initial offshore gas production in 1981 from the Erawan field averaged about 200 mmcfd. Subsequent drilling by Unocal in the vicinity of the Erawan field resulted in discovery of several fields, together currently producing about 670 mmcfd. The production facilities include 34 platforms and 422 development wells, 309 of which are now producing. The current production comes from fields under Unocal's Contract I and II. The fields developed under Unocal Contract III will be brought on stream in early 1992. On February 6, 1990, a total of 1 tcf gas had been purchased by PTT from Unocal, less than nine years after the start of the operation, rather than 20 years, as indicated in the original contract. 2.5 In addition to offshore gas production, which represents about 90X of the country's total gas production, Thailand is also producing -- from the Sirikit and Namphong fields-- about 100 mmcfd of onshore gas, which is used in the nearby power plants. In accordance with the gas sales agreement signed between PTT and Esso for the Namphong gas, a reserve of not less than 1 tcf must be confirmed before a gas utilization project can be implemented. In the interim, however, natural gas at the rate of 66 mmcfd was delivered until the end of 1991, and is projected to gradually increase to 250 mmcfd by 1993. Annex 5 provides present gas consumption in Thailand. 2.6 Gas production in the Gulf of Thailand is determined by two striking features of the gas reserves: the gas fields contain many individual reservoirs of varying size and shape; and most individual reservoirs are small. Because each small reservoir depletes fairly quickly when placed in production, a large number of platforms and wells are required to recover the gas. In addition, since each production well may penetrate from 2 to 20 or more individual reservoirs, workovers and re- completions are rather frequent. These factors make both the cost of development and production relatively hig&. D. Gas Availability 2.7 The forecast of gas availability from offshore fields in the Gulf of Thailand is given in Table 2.2. - 11 - Table 2.2: Gas Availability in Gulf of Thailand (mmcfd) Production Fields Total EZwn/ zxisting 34-inch Year Unocal I & II Unocal III Doncot Unocal 12/27 Prod'n 1h0m Pipl. Space Capacity LI an Mazxi= Allowable Flow 750 850 1991 670 - - - 670 - + 80 +180 1992 590 160 - - 750 - 000 +100 1993 550 ISO 75 - 775 - - 25 + 75 1994 535 165 150 - 8S0 e0 - 20 + 60 1995 530 170 250 - 950 s0 -120* - 20 1996 470 230 250 - 950 120 - 60 + 20 1997 470 230 250 - 950 120 - s0 + 20 1998 470 230 250 150 1,100 120 -230 -130* 1999 400 300 250 250 1,200 150 -300 -200 2000 400 300 250 250 1.200 150 -300 -200 Source: PTT and Hjasion a See pars. 3.11 for discussion of ehisting pipeline. * Point at which additional transport capacity is desirable. 2.8 COther potential gas supplies --besides those from the Gulf of Thailand- - which may impact the Thai gas market include both onshore Thai gas and imports. At present, onshore gas production is limited to the non- associated gas from the Namphong field and associated gas from the Sirikit field (para. 2.5). Namphong was originally estimated to contain 1,500 bec of producible reserves and therefore a nipeline from the Namphong field to the Bangkok area was contemplated. However, the additional drilling resulted in reducing the estimated level of original reserve. Therefore, no major additional onshore gas supplies are predicted prior to the year 2000. 2.9 Faced with a limited supply of domestic gas and its rapid economic expansion, Thailand is looking to its neighboring countries for gas. This includes Martaban offshore gas in Myanmar, offshore Malaysia gas, and any new gas discoveries in the Cambodian and Vietnamese portions of the Gulf of Thailand. The offshore Martaban field with 2,500-4,000 bef of producible reserve is a suitable candidate because of its low development and operating costs and high-caliber reservoir. Discussions between Thailand and Hyanmar have been ongoing for several years without producing any discernible result due to economic and political difficulties in Myanmar. Gas imports from Myanmar are therefore not likely to materialize before the year 2000. 2.10 Due to the limited market in southern Thailand and the distances involved from the Malaysian gas fields to major Thai markets, it is not expected that significant gas imports from Malaysia will materialize in the foreseeable future. A more likely scenario for imports from Malaysia involves the extension of a Gulf of Thailand trunkline, to join the Joint Development Area (JDA), a gas field shared between Thailand and Malaysia. The development of JDA, however, requires additional exploratory work before an appraisal program can be contemplated. -12 2.11 The eastern portions of the gas-rich Pattani Trough and Malay Basin extend into Cambodia and Vietnam territory, making Thai imports potentially viable. However, exploration is only in the initial stages. Furthermore, any pipeline would need to traverse the disputed areas for Thailand to utilize existing infrastructure to import gas from Cambodia or Viet Nam. At present, import potential seems remote, making the import of gas from Vietnam and Cambodia unlikely before the year 2000. 2.12 Therefore, no additional gas supplies of consequence, either from onshore domestic sources or imports, are likely to impact the Thai gas market before the year 2000. Domestic offshore gas supplies will be the most likely source to provide increased gas production. Unless new discoveries are made in the Gulf of Thailand, the 1,400 - 1,500 mmcfd plateau production expected in the late 1990s should become the target level. Identified reserves should be sufficient to maintain production at this level for eight to ten years, with expected new discoveries produced to prolong this plateau further. 2.13 Thailand has recently been considering importing LNG from Indonesia or Malaysia. Given the high net-back value of gas in Thailand's economy (particularly in the power sector) and its environmental advantages, the option of importing LNG deserves further assessment. One key consideration in importing LNG is that unlike other imported fuels (e.g., oil and coal), LNG requires commitments to be made well ahead of time because of the magnitude and long lead time of the investment required. Another consideration is that imports have to be of a sufficient scale to justify the necessary infrastructure. This requires a concerted effort on the part of the Government, in part motivated by environmental considerations, to promote the use of LNG as a major fuel source and adopt appropriate pricing policy and other policies to bring about an adequate level of usage. The Government is initiating a "fuel option" study, which includes assessing the issue and options in importing LNG to Thailand. E. Gas Demand 2.14 There is ample demand for natural gas in Thailand for the foreseeable future. Table 2.3 gives the supply/demand forecast for natural gas in Thailand and Annex 6 provides a detailed breakdown. The supply/demand forecast indicates that Thailand will face a deficit in gas supply for the foreseeable future. The Government's projection indicates that the country's demand for natural gas will reach 1,975 mmcfd by the year 2000, with about 1,400 mmcfd going to the power sector (including 610 umcfd for combined-cycle power plants). These relatively conservative estimates are based on the needs of currently identified end-users, without taking into account rapid GDP growth in the future and the environmental benefits associated with the utilization of natural gas. It is estimated that if the gas supply is not constrained, the country's gas consumption could reach 2,500 mmcfd by the year 2000. - 13 - Table 2.3: NATURAL GAS SUPPLY/DEMAND PROFILE (1990-2005) (mmcfd) 1990 1995 2000 2005 SUPPLY Domestic (Offshore & Onshore)' 550 960 1,010 1,005 (Proposed Bongkot Project) (200) (250) (250) Import Potential (JDA) 0 0 250 250 TOTAL SUPPLY 550 960 1,260 1,255 DEMAND Feedstock (Gas Sep. Plant) 80 150 205 205 Industry 30 240 350 435 EGAT (Potential demand) 660 1,290 1,420 1,125 TOTAL POTENTIAL DEMAND 770 1,680 1,975 1,765 DEFICIT 220 720 715 510 S3URCE: PTT, and EGAT based on EGAT's power plants capability to consume S. Gas-Use Policy 2.15 While the Government has not formally adopted a gas-use policy, it has examined the gas use options in various sectors. The present allocation of gas is based on the ranking of the economic value of gas in different applications. The present policy is to extract the propane and butane (C3/C4) fractions for LPG use, and the ethane and propane (C2/C3) fractions for petrochemical feedstock. The methane (Cl) fraction, which represents about 80X of the total, is used in the industrial and power sectors. The gas in Thailand presently yields its highest economic value when used in a combined-cycle power plant. However, since the total gas demand in the industrial sector represents less than 5X of the country's potential gas demand, the Government has made a decision to meet the full demand of gas in the industrial sector, while adjusting the supply to the power sector according to gas availability. Gas Utilization for Power Generation 2.16 Due to rapid growth in electricity demand in Thailand, EGAT needs to increase its generation capacity from 7,970 MW in 1990 to 24,794 MW in the year 2000. EGAT has established that, subject to gas availability, gas offers the least-cost scheme for the country's power generation - 14 - requirementsV. The economic benefits of gas use in combined-cycle power plants and its value-added environmental benefits resulted in the share of combined-cycle power plants to increase from zero in 1980 to 16X in 1990, while the share of oil-fueled power plants declined from 48X to 221. The share of coal-fired (lignite) power plants increased from 61 to 221. In addition to economic benefits, the underlying policy for this structural shift stemmed from two objectives: reducing Thailand's dependence on imported nil and improving environmental conditions in the country. 2.17 Choices of fuel for EGAT however, are becoming increasingly limited. The remaining hydro potential is not easy to develop, because of high costs ard environmental and forestry problems. The reserves of the country's li[aite are not sufficient to meet the increased power generating requirements, and, in addition, the use of lignite creates environmental problems. Although the gas is the least-cost solution for EGAT's power generation, because of constraints in gas supply, EGAT cannot develop a reliable, long-term gas-based plan for its power generation needs. Therefore, EGAT is forced to continue to include locally produced lignite (or imported-coal-based) plants and dual-firing capability to supplement gas with fuel oil in its master plan in case of gas inavailability. EGAT's present planning calls for the share of combined-cycle plants to stay in the present range of 15-16% between now and 2006, assuming that no further gas would be available in addition to the existing reserves. The plan also calls for the share of oil-powered plants to decline from 221 to 41 by 2006, the share of local-coal-powered plants to increase marginally, from 181 to 221, but the share of imported-coal-based power plants to increase from zero in 1996 to 35% by 2006. EGAT's plan calls for switching to gas, whenever gas is available. Annex 7 gives the projected demand of gas by EGAT until 2001, for both thermal power plants and combined-cycle power plants. The projected demand represents EGAT's minimum gas requirements. If sufficient gas were available, EGAT's potential demand would be 1,420 mmcfd in the year 2000 (Table 2.3). 2.18 The size of EGAT's investment for natural-gas-based combined- cycle power plants in its Seven-Year Development Plan (1992-96) is US$1.2 billion. Furthermore, the Seven-Year Plan envisages additional investment in rehabilitation and new construction of oil-fueled power plants. For both oil and gas, EGAT needs to deal with PTT. Given this size of investment, EGAT and PTT need to coordinate more closely regarding the proper programming of investments. While such coordination at the policy level is currently through NEPO and at the corporate level between EGAT and PTT, it is believed that a more formal exchange of information between PTT and EGAT through regular, working-level meetings would produce substantial benefits. During negotiations, assurances were given by PTT that it would take the necessary measures to hold such a meeting at least every six months (para. 7.2). 2/ The methodology used by EGAT to deternine the leastoost scheme h quilb adequate. Altemative goneratlon oxpansion sequences are analyzed using computer model WGOPLAN). The timing of the plant Is dotermined by analysis of monthly load demand and avallable generating capacity. - 15 - F. Gas Pricing 2.19 Although Thailand has not yet established a comprehensive gas pricing system for produicers and consumers, the Government's underlying policy for gas pricing in sound, in that it is guided by the principle of full cost-recovery. Producer Prices 2.20 The cost of producing natural gas in Thailand is relatively expensive compared with that in Indonesia or Malaysia. This is due to the complex geological structure of the fields (para.2.6), which results in the well-head transfer price bearing the high cost of field development and production. The average well-head price for Unocal's gas ranges from US$1.77 to US$2.08 per mmbtu, while gas frov he Namphong field is about US$1.00 per mmbtu. Except for Namphong gas, : r which the price is 100l linked to the price of fuel oil, Unocal's priceb are partly indexed to fuel oil (15X - 202), and partly to Thailand's wholesale prices (25X - 30X) and to U.S. oil field machinery prices (40X - 60X), Consumer Prices 2.21 The principle applied by the Government in setting consumer prices is to link gas prices to alternative fuel prices in each activity. Currently, PTT charges two prices: one for industry and one for the power sector. The present prices of gas to industry are intended to encour-.,e LPG consumers to shift to gas, but no such incentive is provided to fuel oil users. This is because the gas has a lower net-back value when substituting for fuel oil. In 1990, the average price of gas to industry was Baht 100-120 per mmbtu. In the power sector, which uses over 902 of gas in the country, the gas yields its highest economic value. The price of gas for the power sector, i.e., EGAT, is about Baht 70 per mmbtu. The price of gas to EGAT is low because of the size of EGAT's consumption and because EGAT, as a swing customer, bears the weight of uncertainties of gas supply and has to maintain dual-fired stations. G. Experience with Previous Bank Loans 2.22 So far, the Bank has made three loans to Thailand in the oil and gas sector over the past ten years. The first loan (1773-TH) was for construction of Thailand's first gas transmission pipeline. The second loan (2184-TH) was for the construction of a gas separation plant. The third loan (2184-TH) supported oil field developmer.t. These projects were completed on schedule and within the budget, and they realized their main objectives. The Bank provided substantial institutional and technical support to PTT, especially during its early stages when PTT had very little operational experience. While several important lessons were learned from - 16 - the Bank's previous involvement, two in particular are relevant in designing the proposed project: (a) During the first year of operation of the gas separation plant (Loan 2184-TH), EGAT, PTT's major client, purchased less gas from PTT than it had originally estimated, because EGAT saw no financial incentives in using gas while the price of fuel oil was declining. Since there was no formal agreement between PTT and EGAT, EGAT simply switched its dual-fuel installations to fuel oil. PTT was not in a position to pass on to its major client the benefits of declining oil prices, because in its agreement with the gas producers, the gas price was insensitiv& to international oil prices. In the proposed project, a long term agreement has been signed between PTT and EGAT, under which PTT passes the full cost of its gas purchases from the producers to EGAT, and recovers its transmission costs (para. 3.10). (b) Although the first gas transmission project (Loan 1773-TH) remains economically sound, during its implementation the Bank learned that the hydrocarbon basins in the Gulf of Thailand are characterized by a complex geology, therefore requiring a comprehensive appraisal of the discovered gas fields before proceeding to the full development and production phase. An inadequate appraisal program could lead to substantial cost overruns. In the proposed project, the designs have taken into account risks related to the area's complex geology (para. 6.9). H. Rationale for the Bank's Involvement in the Progosed Project 2.23 The Bank has been involved in Thailand's oil and gas industry since its inception. In the course of the dialogue that has been stimulated by this involvement, the Government and the energy-affiliated agencies have continuously sought the Bank's advice in the areas of institution building, pricing, investment programming, and least-cost scheme development for meeting the country's rapidly growing energy demand. In most cases, the Government has implemented the Bank's recommendations. Some of the more important programs in this regard are currently in mid- stream, and continued support from the Bank is critical to ensuring that they will be concluded succe- fully: (a) the Bank has worked extensively with PTT to develop techniques and processes for a more rational investment programming and analysis. Continued Bank involvement will encourage further refinement and correct implementation of the investment program; (b) PTT has grown very rapidly over recent years, and as of January 1, 1992, PTT was reorganized into five business units operating on a profit- loss basis. Continued Bank involvement will help PTT in developing internal systems and procedures and managerial approaches that are appropriate to PTT's eventual privatization in which t*e individual business units might be sold separately to the public; and (c) in the proposed project, Bank support to date has enabled PTT to take a broad view at its objectives, including adopting a common-carrier approach to pipeline - 17 - development. The proposed common-carrier pipeline will encourage small independent producers to exploit marginal fields close to the pipeline, and would also promote the regional trade in gas slnce the construction of the pipeline facilitates the future importation of gas into Thailand from the neighboring countries of Vietnam and Malaysia. Furthermore, the Bark's involvement in the project has helped to resolve the gas pricing issue between PTT and EGAT which has been in dispute for ten years, and has helped attract co-financing for the project. - 18 - III. THE PROJECT A. Background 3.1 Since the commercial discovery of gas in the Bongkot field in 1976 (para. 3.5), the Government has sought ways to implement a project for economic utilization of this gas. Immediately following the award of the Production License by DMR, PTT commissioned Fluor Daniel to carry out a gas ma-ter plan study, taking into account the potential gas availability, forecasted demand, and the existing infrastructure. A conclusion of the study was that the implementation of the proposed project should be given high priority. In February 1990, PTT requested Bank financing the project. The Bank has reviewed the consultant's report and agrees that the Bongkot Gas Transmission Project constitutes a high priority investment in the master plan proposed for the country's gas transmission network. B. Project ObjectivUes 3.2 The objective of the project is to increase the gas supply capabilities of Thailand by: a) expanding the gas transmission system; b) strengthening the institutional functioning of PTT; and c) making more efficient use of capital resources in the gas sector, through annual review of PTT's investment program (para. 5.11). C rr_!lect Description 3.3 The project consists of two submarine pipelines and the associated facilities to transport the natural gas production of the Bongkot field to onshore locations in the southern and central parts of the country. Map IBRD 23485 shows the location of the offshore facilities and the routing of the pipeline. Annex 8 gives a diagrammatic description of the project's content. 3.4 The major project components are: (a) A 32-inch diameter natural gas pipeline installed in water depths ranging from 270 ft to 200 ft. The pipeline would run approximately 175 km from the production platform being installed in the Bongkot gas field to a new riser platform to be installed approximately one km from the existing Erawan production complex. The pipeline is designed to transport up to 700 mmcfd of natural gas; V' / PTT antlcpates a plateau production of 350 mmcfd from the 8ongkot field, and expects an additonal 350 mmcld In future from the JDA flold. - 19 - (b) A 24-inch diameter natural gas pipeline installed in water depths of 200 ft to landfall. The pipeline would run approximately 160 km from the new riser platform at Erawan to the terminal at Khanom. The pipeline is designed to transport up to 350 mmcfd of natural gas; (c) A new Supervisory Control and Data Acquisition (SCADA) and pipeline telecommuw cations system, including renovation of the existing SCADA system, and construction of new control buildings at Khanom and at Chonburi; (d) A riser platform to support a piping mainfold to connect the incoming gas flow from the Bongkot field to the existing 34-inch pipeline to Rayong, as well as the pipeline to Khanom; (e) Equipment including additional compression capacity for PTT's off-shore operation at Bongkot and Erawan; (f) Consultancy and management services for engineering, procurement and construction of the project facilities; (g) Upgrading of PTT's Management Information System (MIS) and the training of PTT's staff; (h) A study for preparing engineering safety and environmental standards for PTT's operations; and (i) An engineering study for a new project to transport additional gas from the Erawan platforms. The Bongkot Gas Field 3.5 The Bongkot gas field (formerly called "B" structure) will be the primary source of gas for the proposed project (IBRD Map No. 23519). The field will be developed, produced and operated by a joint-venture of three private producers and PTT Exploration and Production Co., Ltd. (PTTEP). The produced gas will be sold by the joint-venture producers to PTT, in accordance with a gas sales agreement signed in March 1990 (para. 3.9). PTT will transport the gas and sell it to EGAT, under a gas sales agreement signed in December 1991 (para. 3.10). 3.6 The Bongkot field is located about 180 km southeast of the Erawan gas field. Annex 9 provides more detailed information on the Bongkot field. On March 15, 1990, DMR transferred the concession rights in the Bongkot field to a joint-venture group. The Joint Venture (JV) assembled to develop and produce the Bongkot gas field comprises PTTEP (40X) which is a wholly-owned subsidiary of PTT, Total Exploration and Production Thailand (TOTAL) (30X), British Gas Thailand (BG) (20X) and Statoil Thailand (Statoil) (101). A Development Plan for the Production Areas (areas surrounding the previously drilled gas production wells) was submitted to DMR, and a seismic program cont.act has been signed for the Reserved Exploration Areas (the remainder of the concession area). To proceed with - 20 - development, DeGolyer and MacNaughton (D&M), an industry leader in reserve determination and experienced in working in the Gulf of Thailand, were commissioned to provide a reserve determination for the Bongkot field. After compreher.sive analysis, D&M certified 2,168.6 bcf of recoverable gas (1,494.2 bcf proved and 674.4 bcf probable additional) in the Bongkot Production Area. D&M estimates that up to 18 platforms and 160 wells will be required to achieve producing the certified reserves. They are also estimating 55X recovery from the 3,973 bef proved and probable reserves in- place. This relatively low recovery estimate (601 to 701 is normal) reflects D&M's conservative approach. 3.7 The JV partners have entered into a participation and operating agreement among themselves. TOTAL was elected Operator. The Operator will handle all normal operations, i.e., preparation of budgets. procurement and expenditures, and management of day-to-day operations, including supervision of employees seconded by other parties. The Operator will also prepare the Initial Program (the first phase of the Development Plan and Definitive Cost Estimate) which must be adopted unanimously. A more detailed description of the Operator's role is given in Annex 9. 3.8 The Development Plan for the Bongkot field is designed to produce a minimum of 1,500 bcf of gas and 24 million barrels of condensate over the life of the Gas Sales Agreement signed by JV and PTT. The cost for the first phase of the Development Plan (Definitive Cost Estimate) is estimated at US$383 million. Procurement is essentially completed and construction is under way, with production start-up planned in October 1993. The first phase (Initial Program), however, will not be sufficient to develop the 1,500 bcf of recoverable gas reserves and the associated cordensate called for in the Gas Sales Agreement. The Operator is already planning a second phase of development, but no Definitive Cost Estimate has been prepared because implementation will depend on first phase results. PTTEP (with the assistance of Statoil) has prepared a complete development plan to determine the economics of the proposed pipeline project. PTTEP's total development plan requires central production and process facilities, 13 well-platforms and 123 development wells. The total Development Plan is estimated to cost US$897 million. Considering related exploration costs of US$55 million, the total investment for producing at least 1,500 bef of gas and 24 million barrels of condensate is US$952 million. The Bank has reviewed the cost estimate and has verified the size of the investment, which is also consistent with the cost estimate prepared by D&M. Gas Sales Agreement Between PTT and Bongkot Field Producers 3.9 The Gas Sales Agreement signed between the Bongkot gas producers and PTT for the proposed project follows the same principle outlined above for the producer price (para. 2.20). Specifically, the transfer price is based on the economic cost of supply: it is linked to the price of fuel oil, and the price adjustment is based on a set of indices reflecting domestic and international inflation. The formula also includes stable floor and ceiling prices to avoid the impact of short-term fluctuations in international markets. The initial base price is set at Baht 56.14 per mmbtu, and the Agreement includes a take-or-pay covenant. The formula - 21 - appropriately ensures economic efficiency by charging the full economic costs (including a depletion premium) of gas supply, while allowing producers to cover the cost of exploration, development and production, and the Government to absorb the economic rent in the form of royalties and taxes. The discounted (at 12%) transfer price of the gas over the life of the field contractual reserve (1.5 tef) is calculated to range from US$1.98 to US$2.25 per mcf depending on the range assumed for the future prices of fuel oil (i.e., fuel oil price varying from 73% to 85X of the price of crude). While the price is relatively high, reflecting high development and production costs, the economic value of this gas for power generation is significantly higher than its cost. Gas Sales Agreement Between PTT and EGAT 3.10 Consistent with its role of purchasing and transmitting the gas to consumers, PTT seeks agreement with the major users for a price which would cover PTT's cost of purchasing gas from upstream producers, as well as its cost of gas transmission. Although PTT has supplied natural gas to its major customer, EGAT, for about a decade, no formal gas sales/purchase agreement was signed between the two entities until December 1991. During pre-app.-aisal of the proposed project, the Bank raised with PTT, EGAT and the Government the lack of a gas sales agreement as an outstanding issue which needed resolution prior to project appraisal. Subsequently, PTT and EGAT undertook extensive negotiations which resulted in the signing in December 1991 of a ten-year sales agreement between the two entities. The pricing structure stipulated under this contract -- as the price of gas to be paid by EGAT to PTT -- is composed of three components: (a) the price paid by PTT to the upstream producers (well-head price); (b) the average cost of gas transmission by PTT (throughput fee); and (c) the value-added tax (VAT), if any. A throughput fee will be assessed annuall) to ensure that it reflects PTT's transmission costs and gives it a reasonable return on its investment. The agreement provides that if PTT must invest in new transmission facilities, the throughput fee will be readjusted to take into account the new investment and will be in effect retroactively on the date when the new investment was used. The current average price of gas s'old by PTT to EGAT is Baht per 70 per mmbtu. During negotiations, agreement was reached that prior to entering into any material amendment to the existing gas sale/purchase agreements (between PTT and EGAT, and between PTT and the joint-venture gas producers), PTT shall exchange views with the Bank and shall take the Bank's views and recommendations into consideration. It was further agreed th&t amendments that would be considered as affecting the ability of PTT to perform are those dealing with the: (i) quantity of gas to be purchased by or sold to PTT; (ii) price of gas sold to or purchased by PT,; and (iii) duration of the agreements (para. 7.1a). ProRosed Second Pipeline 3.11 Over 90% of Thailand's entire supply of natural gas comes fr,l t.e Gulf of Thailand; all of that gas is currently being transported through a single 34-inch submarine pipeline from Erawan to Rayong. The pipeline has been in operation for almost nine years, and its present flow rate is about 670 mmcfd. Its maximum design capacity is 850 mmcfd. - 22 - However, the pipeline has never operated at its design capacity due to inavailability of gas supply. Periodic pipeline inspection -- the latest In 1990 -- has indicated some corrosion. PTT plans to run a more sophisticated inspection test in early 1992, which should provide more accurate information on the condition of the pipeline including its maximum allowable capacity. 3.12 The need for and the viability of the second pipeline to transport additional gas from Erawan to Rayong is a function of: (a) the present and projected production of gas from the Unocal and, to a lesser degree, from the Bongkot fields; (b) maximum allowable capacity of the existing 34-inch pipeline, depending on the result of the inspection test; and (c) concern over the security of supply, since the existing 34-inch pipeline is the only means of transporting gas to the critical consuming centers of Rayong and Bongkot for power, petrochemical, and other industrial users. 3.13 If the inspection test determines that the pipeline can be safely operated at its design capacity of 850 mmcfd, then no major dislocation of gas supply would occur until about 1998, because the existing pipeline would have sufficient capacity to transport the additional volume of gas (Table 2.2). Under this scenario, the second pipeline, which is scheduled for completion in PTT1s Master Plan in late 1995 or early 1996 -- primarily for transporting gas from Unocal's future production under Contract III -- could be delayed by two years, depending on the pace of Unocal's field development activities and subsequent production rate. Furthermore, depending on the quantity of the additional gas supply from UJnocal fields, the required increase in pipeline capacity could be achieved through installation of a booster compressor on the existing pipeline rather than constructing a new one. However, if the inspection test indicates that limitation should be imposed on the capacity of the existing pipeline, then the need for additional capacity, in the form of a second trunkline, becomes more immediate, possibly in 1995, as scheduled in the PTT Master Plan. During negotiations, agreement was reached that the results of this Inspection test would be furnished to the Bank not later than December 31, 1992, and that the Bank's comments on the results of the inspection test and the pertinent recommer.dations of the inspection report would be taken into account (para. 7.lb). 3.14 To determine the urgency of the second pipeline and the project's viability, the Bank is providing US$2 million for the required consultant's study as part of the proposed loan. The study, which will be carried out not later than October 31, 1992 (para. 7.1j), will confirm the availability and timing of the gas supply, and the optimal means of evacuating the additional gas from Erawan to the onshore consuming centers. It would establish whether the additional gas in the region justifies the construction of a second pipeline, and whether the proposed second pipeline should be constructed offshore, closer to the shore or onshore. - 23 - D. Status of Proiect Pregaration 3.15 The project is at an advanced stage of preparation. A contract for the pipeline materials (to be financed by the proposed Bank loan) has been awarded to a Japanese Consortium in accordance with the Bank procurement guidelines. A letter of intent has been issued to a firm for coating and jacketing the pipe in Malaysia. Bids for the pipelaying contract have been evaluated by PTT and its consultants, and the award is expected to be announced in April 1992. Other engineering, procurement, and related project activities are progressing at a corresponding pace. No land acquisition problem is anticipated for pipeline landfall and onshore receiving facilities since the land is owned by EGAT. The overall status of project implementation suggests no impediment to the current rate of progress, other than the possible lack of timely project financing arrangements. E. Environmental and Safety Aspects 3.16 Terms of reference for the Environmental Impact Assessment (EIA) of the project were prepared jointly by the Bank and PTT's environmental consultants, the Team Co., which was responsible for carrying out the EIA and for preparing the Environmental Assessment (EA) report. The final EA report has fully taken into account the Bank's comments, including the measures to be taken to ensure that the project complies with the Bank's environmental guidelines. Annex 10 provides the summary of the EA. 3.17 The project's negative impact on the environment is minimal because use of natural gas would be significantly less harmful to the environment than either fuel oil or coal. While natural gas consumption is not pollution free, .it is inherently cleaner than other fuels. Natural gas is free of most pollutants present in liquid and solid fuels and generates less carbon dioxide (CO2). The reduction in CO2 emission offers a highly cost-effective response to the greenhouse effect. The gas used in combined-cycle power plants emits only 40X as much CO2 as a coal-fired power plant. Treated natural gas has no sulfur content. Furthermore, the gas to be transported by the project pipeline is non-associated gas, which has much less environmental risk than the transport of oil or associated gas. Nonetheless, a few potential but more manageable environmental issues exist, including the disruption of marine life which may be caused by changes in seabed conditions in the vicinity of the pipeline during construction; the discharge of liquids such as process water, deck drainage and sewage from production and living quarters platforms; the disposal of mercury present in the gas; and the noise and vibration caused by equipment on the production platforms. The EA report fully addresses these potential issues and provides for appropriate mitigation actions such as pre- treatment of liquid effluents before discharge to the sea, safe disposal of solid wastes to approved sites on land and safe disposal of elemental mercury. The disruption of marine life is not severe because only about 0.37 square kilometer of seabed would be subject to short-term habitat destruction. Indeed, during the operation phase of the pipeline lt is - 24 - expected that the pipeline surface would provide attachment points for plant species and will provide cover for fish. The design of equipment will be in accordance with international standards for maximum safety and allowable levels of noise and vibration. Furthermore, the EA report provides analysis of alternatives, including the effect of various pipeline routings on natural biological resources such as coral reefs. Proposed measures will ensure that the environment impact, if any, will be kept within limits prescribed by Bank guidelines. During negotiations, agreement was reached that PTT will take all measures required on its part to ensure full implementation of the action plan contained in the Envizonmental Assessment Report (para. 7.1c). 3.18 The entire project design will be in accordance with applicable international safety codes and standards. Natural gas condensates are separated from the gas on the production platforms before the gas is introduced into the pipeline. However, small quantities of liquids will be present in the gas as the result of condensation of hydrocarbon gases. The condensed gases will be periodically removed from the pipeline by a "pig." The pipeline route will be adequately demarcated, especially in shipping lanes and fishing areas, to avoid potential damage to the pipeline (e.g., by a ship's anchor). The construction of the offshore facilities is being carried out by the Operator of the Bongkot gas field (for upstream facilities), and by PTT's construction contractor (for downstream facilities). The Operator, TOTAL, has extensive experience in similar operations elsewhere in the world. The construction of the downstream facilities will be carried out under the supervision of Bechtel International, which also has vast experience in this area. These companies use high standards of safety and environmental protection, and they would require the same from their sub-contractors. Furthermore, a study for developing environmental regulations for all offshore operations in the Gulf of Thailand was proposed by the Bank as part of this project. This study is part of the project but will be financed by ADB using Bank- prepared TOR. The study results should be ready long before the completion of project construction. 3.19 PTT's operational safety record has been excellent, and it is expected that operation of the new facilities will meet this high standard. The gas plant group experienced only one lost-time (14 days) accident during 1989-90; this was due to a highway collision. Over the same period, the pipeline group had no lost-time accidents, but there were two highway fatalities, one in 1988 and the other in 1990. 3.20 Notwithstanding PTT's excellent operational safety records and PTT's commitment to the environmental aspects of its operation, the relatively young age of the oil and gas industry in Thailand has not yet produced the necessary standards and regulations for safety engineering and environmental protection. PTT currently has no well-defined safety engineering standards and environmental regulation, nor does it have an adequate institutional framework to properly administer this aspect of its operation. - 25 - 3.21 PTT has commissioned the DKV Company of Sweden to carry out a one-time comprehensive safety audit of PTT's entire operation. During negotiations, agreement was reached that the results of this safety audit would be made available to the Bank not later than December 31, 1992, and the Bank's comments on the audit would be taken into account (para. 7.1d). 3.22 In addition, the proposed loan would include US$200,000 for consultancy services to help PTT prepare adequate safety engineering and environmental standards for its entire operation. It was agreed with PTT that the study for preparation of safety engineering and environmental standards would be carried out not later than March 31, 1993 (para. 7.1j). Regarding the institutional framework, PTTIS new organization, effective January 1, 1992, includes a safety and environmental committee chaired by PTT's Governor as well as safety and environmental standards divisions in each business unit. The heads of the environmental standards divisions report directly to the presidents of the respective business units. Furthermore, each division has one or more sub-divisions (e.g., for pipeline and gas plants within the natural gas business unit) to enforce the standards and regulations at the operational level. F. Prolect ImRlementation and Schedule 3.23 Overall responsibility and control over project implementation will rest with PTT. PTT has in the past implemented several similar projects including the construction of the existing 34-inch offshore pipeline financed by the Bank. PTT has appointed Lavalin/Bechtel, a consortium comprising Lavalin and Bechtel International, both of Canada, to assist in carrying out all stages of the project implementation cycle. The consortium members are reputable international engineering firms which have the experience and expertise for successful execution of the project. Annex 11 shows PTT's organization for project implementation. PTT personnel will also be assigned to the project for on-the-job training and other selected tasks. 3.24 PTT's internal schedule cal.ls for completion of the project's physical works by December 31, 1993 (Annex 12). This is a challenging target which can be achieved with the cooperation and best effort of all concerned. PTT with assistance from its consultants has instituted a critical path master plan to monitor implementation progress and to react quickly to actual and potential delays. However, to allow for the possibility of delays during testing and commissioning, the project completion date is assumed to be June 30, 1994. 3.25 EGAT has already issued the invitation to bid for procurement and installation of a 600 MW combined-cycle power plant at Khanom. The 200 MW gas turbine for the first unit will be completed in December 1993, followed with completion of the second 200 MW unit in April 1994. The 100 MW steam turbine units will be completed one year after the respective gas turbine units, i.e., December 1994 and April 1995. Annex 12 provides the completion schedule for the Khanom combined-cycle power plant. - 26 - G. Project Costs 3.26 The project is estimated to cost tha equivalent of US$348 million, including taxes and duties which amount to US$13 million. Foreign exchange costs total US$305.6 million or 88Z of total costs. Table 3.1 gives a breakdown of the project cost by major components. Annex 13 gives the breakdown of annual expenditures. The estimate is expressed in end- 1991 prices and is based on actual prices of approximately 68Z of the total project cost and on informal but firm quotation for the balance. An 8X physical contingency and a 2X price contingency have been added to the base cost estimate. The physical contingency is adequate considering the advanced stage of project design and the fact that pipeline engineering and construction involve few uncertainties. The low price contingency reflects the fact that all major procurement is on a fixed price basis, that two major contracts have already been awarded, and that most procurement will be completed by late 1992. Taxes and duties were estimated based on an average rate of 40X on all goods subject to such charges. The Government requires PTT to pay taxes and duties only for those project goods which enter Thailand's 12 mile territorial water zone. - 27 - Table 3.1: Project Cost Estimate (US$ million - 1991) llem Local Foreign Total Local Foreign Total Foreign As A (Baht Mlillion) (USS Million) % of Total Civil woiks/building 78.6 76.6 3.0 3.0 Pipe material (Una pip.) 1970.1 1970.1 - 77.2 77.2 100 Pipe coating & Jacketing 668.8 668.6 26.2 26.2 100 Pipeline construction 382.8 2424.4 2807.2 15.0 95.0 110.0 88 TOTAL equipment 510.4 510.4 - 20.0 20.0 100 SCADA/telecom 94.5 168.4 262.9 3.7 6.6 10.3 84 Riser platform - 969.8 969.8 38.0 38.0 100 Engineerng consultancy 89.3 293.5 382.8 3.5 11.5 15.0 77 MIS and training 2.5 23.0 25.5 0.1 0.9 1.0 90 Environmental study - 5.1 5.1 - 0.2 0.2 100 Second pipeline study 5.1 45.9 51.0 0.2 1.8 2.0 S0 Taxes and duties 331.8 331.8 13.0 13.0 Basio Cost MS 6 792 8061t 85 277 4 35 Physloal contngency 79.2 566.5 645.7 3.1 22.2 25.3 88 Price contingency / 20.4 153.1 173.5 0.8 6.0 6.8 88 Totai project cost 1082.2 78.8 88810 42.4 au 6 46 Other costs interest during construction and other charges 66.3 495.1 561.4 26 19.4 22.0 80 Tota financing required 1148.5 82939 9442.4 450 AM5 - pj Not required because of advanced state of procurement H. Project Financing Plan 3.27 Table 3.2 summarizes the expected financing plan: Table 3.. Project Financing Plan (US$ Million) Local Forelan = S Japan Exim Bank 7.0 45.0 52.0 14 Asian Development Bank 8.0 50.0 58.0 16 U.S Exim Bank 0.70 6.6 7.3 2 Commercial Borrowing \i 10.0 46.0 56.0 15 PTT intemal Cash 15.1 76.6 01.7 25 IBRD 4.2 t.O 8 . 10 Total Financing Required 45.0 325.0 370.0 100 \1 including PTT Bond Issuanco. - 28 - 3.28 Total financing required, including interest during construction (estimated at US$22 million based on 8X interest), would amount to US$370 million. The proposed Bank loan of US$105 million would be made directly to PTT at the Bank's standard terms for Thailand. PTT would bear the foreign exchange and variable interest rate risks of its loan, which would be guaranteed by the Government. The Bank loan would be for 17 years, including 4 years of grace, at the Bank's variable interest rate. The loan would finance 28Z of the total project financing required and 33% of its foreign expenditures. 3.29 The financing plan has been developed on the basis of extensive discussions with PTT, Japan Exim Bank (JEXIM) and the Asian Development Bank (ADB); the JEXIM and ADB representatives participated in both project pre-appraisal and appraisal. The procurement packages were designed to take into account the various co-lenders' internal requirements, the project implementation schedule, and PTT's concern regarding its large exposure to non-dollar hard currency, particularly Japanese yen. The Bank would finance the engineering consultancy and the line pipe contracts and several studies (US$105 million), while ADB and JEXIM would jointly finance the pipeline construction contract, and the U.S. Exim Bank would finance part of the the SCADA system. ADB and JEXIM jointly appraised the project in February 1992. 3.30 The Bank loan may become effective before ADB/JEXIM's loan. Since indications suggest fairly clearly that the proposed co-financing by ADB/JEXIM will materialize (both institutions have shown strong interest in lending for the proposed project and both have actively participated in the project preparation), it was determined at negotiations that cross-default and cross-effectiveness of the various loans were unnecessary. In the unlikely event that co-financing will be delayed, PTT is in a healthy financial position to fund the project financing gap from its own resources. I. Procurement and Disbursement Procurement 3.31 Procurement arrangements are summarized in Table 3.3 below. The cost of each procurement item includes its pro-rata share of the project's physical and price contingencies. - 29 - Table3 Summary of Procurement Arrangements (US$ Million) Procuroment Metods Pmlobo Element Jo ,OFr of T01;4 CNI Wods/BuIdIng 33 3.3 PIpoline Materals Qing pipe) 85.0 85.0 (85.0) (85.0) Pipe Coaing & Jacketing 28 28.3 PipeUno Contuoton 121.2 \a 121.2 TOTAL Equipment 22.0 22.0 SC4DA/Teleoomm 11.4 \ 11.4 Nier platform 41.9 41* Englnooeing Consultanoy 106. 16.6 (16.5) (16 MIS and Tralning 1.1 1.1 , (1-1) (1.1) Environmental Study 02 0.2 (0.2) (0.2) Second PIpeolne Study 2.2 2.2 (2.2) 2 9 Tzaxe and Dute 14.3 14.3 Tota 85.0 20.0 2430 348.0 (85.0) (20.0) (105.0) \a ADS and JE)M procurement proodurs. \b U.S Exm Bank procurement prooodures. Nobt: Rgure In parentheis are the respectv amounts finanod by th Bank NBF- Not Bank-Fnanced 3.32 The following five single responsibility contracts comprise the bulk of the procurement required for the project: (a) Supply and delivery of pipeline material (US$85 million), a Bank- financed component, the contract for which has been awarded under international competitive bidding (ICB) in accordance with the Bank's procurement guidellnes. Owing to its critical nature, the Bank had agreed to advance procurement for this contract; (b) Engineering consultgncy and project management contract (US$16.5 million), a Bank-financed component, the contract for which has already been awarded by PTT in accordance with the Bank's procurement guidelines for use of consultants by the World Bank Borrower; (c) Coating and jacketing the line pipe (US$28.9 million), the contract for which is to be awarded to a .1alaysian firm and to be financed by PTTVs own resources; (d) Construction of the pipeline (US$121.2 million), the contract for which will be awarded in accordance with ADB and JEXIM procurement procedures; and - 30 - (e) Supply and installation of SCADA and telecommunication facilities (US$11.4 million), the contract for which will be awarded in accordance with U.S. Exim Bank procurement procedures. 3.33 Equipment, including additional compression capacity (US$22.0 million), is needed for PTT's offshore gas pipeline operation. These items would be supplied and installed on the Bongkot production platform by TOTAL, the operator of the Bongkot gas field, in accordance with an agreement between PTT and TOTAL. Due to a lack of space on Unocal's Erawan production platform, PTT requires a riser platform to support a piping manifold to connect the incoming gas flow from the Bongkot field to the existing 34-inch pipeline to Rayong, as well as the pipeline to Khanom and the future second pipeline. The riser platform (US$41.9 million) would be designed, supplied and installed by Unocal in accordance with arrangements agreed with PTT. PTT would procure civil works and buildings (US$3.3 million) in accordance with its own procurement procedures which are satisfactory to the Bank. The remaining consultancies included in the project would be selected and appointed in accordance with the Bank's guidelines for use of consultants by the World Bank Borrowers. Disbursement 3.34 The estimated disbursement of the Bank loan is shown in detail in Annex 14 and summarized in Table 3.4 below: Table 3.4: Estimated Loan Disbursement (US$ Million) Bank FY 1993 1994 1995 Annual 75 21 9 Cumulative 75 96 105 3.35 Disbursement of the loan is based on the assumption that it will become effective in the first quarter of the Bank's fiscal year 1993. It is expected that the loan will be fully disbursed by June 30, 1994 (para. 3.24), the scheduled completion date of the project. On this basis, the closing date for the loan is set for December 31, 1994. The scheduled disbursements are faster than the standard profiles for the region and the subsector, reflecting the advanced stage of project preparation. Phasing of the estimated disbursements of the proposed Bank loan and the Bank's standard disbursement profile for the subsector are shown in Annex 14. 3.36 Due to a tight project implementation schedule and the critical nature of the pipe material in the completion schedule, PTT had to advance its contract for pipe material. Therefore, retroactive financing equivalent to US$22 million is recommended for expenses incurred after September 1, 1991, for partial payments for line pipe materials and - 31 - consultancy contracts, for amounts which already have been paid by PTT through advanced contracting approved by the Bank. Increasing the level of retroactive financing from the Bank's normal limit of 10 to about 21X of the loan amount is considered acceptable because: (a) the increased retroactive financing is required for progress payments on the pipeline oontract which has been approved in advance by the Bank; and (b) the retroactive financing will be for expenditures incurred within the allowable period (12 months before the expected date of the loan signing, and after the pre-appraisal). 3.37 The Bank loan would be disbursed against the categories outlined in Table 3.5 below: Table 3.5: Allocation of the Proposed Bank Loan (US$ million) Percentage of US$ Million expenditures financed Pipeline Materials 85.0 100l of foreign expenditures Consultancy services 16.5 1002 of expenditures Training, studies, 3.5 10OZ of expenditures MIS Total 105.0 3.38 Reimbursement for goods, services and training valued at less than US$1.0 million would be made on the basis of Statements of Expenditure (SOEs). Documentation of SOEs would be retained by PTT and made available for review by Bank supervision missions. All other disbursements would be made against full documentation. To the extent possible, withradawal applications should be consolidated into amount of US$1.0 million equivalent or more, prior to submission to the Bank. J. Monitoring. Reporting and Supervision 3.39 The Bank will monitor the progress of the proposed project in terms of physical execution and financial reporting to ensure that all conditions of the proposed loan are satisfied. For this purpose the Bank would, on average, field two supervision missions per year, during the active project phase to review project implementation, inspect job-site activities and discuss, as required, any related matters with Government and PTT officials. In addition, PTT would be required to forward periodic progress reports. During negotiations, agreement was reached with PTT regarding the format, content and frequency of these reports (para. 7.1e). The basic requirement would be quarterly progress reports for each - 32 - applicable project component and PTTVs semi-annual and annual financial and auditors reports as defined in para. 4.14. 3.40 Project supervision by the Bank would be coordinated through a supervision plan to be confirmed during loan negotiations. Bank field supervision would require a total of about 24 staff-weeks during the life of the project, of which about 14 staff-weeks would be required during the first two years of project implementation. Supervision would be carried out mainly by Bank technical and financial staff, including an environmental specialist. - 33 - IV. THE BRROWE A. hackground 4.1 The Borrower of the proposed loan would be the Petroleum Authority of Thailand (PTT), which was established in December 1978 by the Petroleum Authority of Thailand Act and became operational in July 1979. mT's objective is to engage in and promote petroleum and petrochemical activities. It was formed by the transfer of operations from two previously existing state ent6prprises: the Natural Gas Organization of Thailand and the Oil Fuel Organization. It is wholly owned by the Kingdom of Thailand and comes under the direct jurisdiction of the Ministry of Industry. 4.2 While PTT focuses primarily on gas transmission and petroleum products refining and marketing, it also is involved in upstream operations through PTT Exploration and Production Co., Ltd. (PTTEP), a wholly-owned subsidiary company which was established to handle petroleum exploration and production activities. PTT is a statutory body which, because of a technicality in the Thai petroleum law, cannot co-venture with private production companies. It does, however, participate in joint ventures through PTTEP which, as a limited company, can legally be the co-venturer. PrTEP's accounts are kept separate from those of PTT to ensure proper identification of exploration and production expenditures. 4.3 PTT has entered into joint venture agreements for downstream operations and holds shares in two refineries --the Thai Oil Company Refinery (491) and t'ne Bangchak Petroleum Co. Ltd. (301)-- and in the National Petrochemical Corporation (49X), the National Fertilizer Corporation (21X), Thai LNG Co. (101), Bangkok Aviation Fuel Services (101), Intoplane Services Compnny (171), Thai Olefins Company (401) and the Aromatics (Thailand) Company (251). In 1991, PTT invested in two new joint ventures, buying a 25.5Z share in the Thai Petroleum Pipeline Co. Ltd. and a 10 share in the Fuel Pipeline Transportation Co., Ltd. B. Organization 4.4 PTT is a well-run state enterprise, capable of managing the substantial growth in investment, exploration and production, and sales expected over the project period. It functions as a modern organization and enjoys a considerable degree of autonomy in its day-to-day operations. Although decisions concerning the investment plan and financing remain subject to government approval, PTT has essentially been deregulated and management makes the key operating decisions (para. 4.5). PTT's operational and policy decisions are made by a Board of Directors, which consists of a Chairman and 11 other members, including the Governor. With the exception of the Governor, the Board members, who are appointed by the Council of Ministers, act in a part-time capacity. The Directors include - 34 - representatives from the Ministries of Defense, Finance, Commerce, Industry, Transport and Communications and the Juridical Council. PTT also has an executive committee, comprising the Chairman of the Board and five Directors. The executive committee meets frequently and is empowered to make decisions on certain investments, contracts, staffing and other operational matters. 4.5 While PTT has in the past operated under the constraints typical of government enterprises in Thailand, it has recently been designated for deregulation under a Ministry of Finance directive which allows greater autonomy for those government-owned enterprises which meet certain efficiency criteria. As of fiscal year 1992, PTT's procurement, organizational structure, and administrative controls are no longer regulated, and salaries and benefits are no longer limited by schedules applicable to state enterprise. The major areas remaining under government supervision are the capital investment plan, which is subject to NESDB approval, and the financing of investments, which is reviewed by the Ministry of Finance. 4.6 As of January 1, 1992, PTT was reorganized on a profit center basis, with four separate buliness units reporting to the PTT Governor (the attached chart shows the company's organizational structure). The business units are as follows: (a) the downstream oil companies (including logistics and transportation, refining and marketing); (b) the natural gas activities; (c) the petrochemical facilities, and (d) central services. While the administrative departments --including human resources, finance, accounting and budget, policy and planning, public relations, and MIS-- remain in the head office, reporting to the Governor, the portions of these functions relevant to individual operating units are decentralized into each of the five business units. It is intended that the individual business units will function autonomously, and that the reorganization will prepare PTT for an eventual privatization in which the individual business units might be sold separately to the public. C. Stafflng and Training 4.7 PTT's staff level, which totaled 3,720 employees as of year-end 1991, has remained relatively constant over the past five years, with very little growth ln that period. The management and staff are competent and well qualifict. About 62Z of the staff have received some form of higher oducation. About 371 are temporary staff, largely in unskilled positions. Since most construction ls contracted out on a turnkey basis, the PTT staff does not include construction workers. - 35 - Tabl S.1: PST STAllING EVCLUSIO Increase 1986-91 FY86 FY87 FY88 FY89 FY90 FY91 X p.a. UniversLty graduates 1,023 1.161 1,239 1.398 1,361 1,364 5.92 Dlploa *ad higher professanalt educatton 435 447 434 438 497 498 2.74 BHgher vocatLnal educatLon 460 507 493 449 460 448 (0.53) Others 1.778 1,615 1,573 1.491 1.446 1.410 (4.53) Zaksl 3,696 3,730 3,739 3,776 3,764 3,720 0.13 Source: PTT 4.8 For the past several years, with Thailand's economic boom, PTT has suffered a "brain drain" of experienced technical personnel leaving the company to take mora lucrative private sector jobs. Under the system in place through FY91, PTT had been obliged to use the government salary scale published by the Ministry of Finance for all public enterprises. For technLcal employees, that scale was considerably lower than the private sector compensation levels for comparatle jobs. PTT s pay scale was therefore not sufficient to retain trained engineers, computer specialists, accountants and financial experts, chemists, geophysicists, and other scientists. With the recent deregulation, PTT has been freed from the constraints of that salary structure, and it anticipates that, with its new autonomy on salary and other personnel matters, it will be able to compete more effectively with private sector companies. As of October 1, 1991, PTT increased its salaries by an average 25X, with the increases allocated largely to technical and financial personnel. PTT plans to adjust the compensation of these employees so that after a three year period, most salaries would be within 801 of commercial levels. 4.9 Training falls under the overall responsibility of the Personnel Administration Department, and focuses on both the management and technical activities of PTT. In addition to significant in-house training programs, PTT sends employees to outside training courses, both in Thailand and abroad. In 1991, nearly 200 PTT employees attended training programs overseas. 4.10 PTT has a good record in project cost control, implementation and management. It has been borrowing from the Bank since its inception and is very familiar with the Bank's procurement guidelines. Processing of tenders and award of contracts are undertaken equitably and expeditiously. - 36 - D. Operation and Management Accounting 4.11 PTT's accounting system conforms to modern oil anu gas industry practices. PTT maintains separate accounts for each of its major activities. The natural gas financial accounts are modelled on U.S. gas industry principles, and accounts have been satisfactorily prepared for all aspects of PTT's operations. Accounting applications such as general ledgers, payroll, inventory transactions, accounts payable, and accounts receivable have been fully computerized. PTT prepares annual budgets for its capital and operating expenditures; it also prepares five-year forecasts for financial planning purposes. Periodically, reports are prepared enabling management to compare actual results against budgeted amounts. The budget process has been operating satisfactorily. 4.12 PTT's billing and collection system is adequate. Accounts receivable are an average of 45 days of sales, which is consistent with a government regulation requiring all state enterprises to collect receivables within 60 days. Audit 4.13 PTT has an Office of Internal Audit with a staff of approximately 40 auditors. The Office of Internal Audit is an effective management tool for PTT. Its responsibilities cover audits of PTT's accounting and financial functions, computer systems and programs, and operation systems. The tasks outlined to be performed by the Internal Audit Office seem appropriate. However, the Office could be strengthened by an increase in staff. Although the scope of work for audit of PTT operations is appropriate, because of the shortage of engineers on the staff of the Audit Office, it has not been possible for all of the operations to be audited each year. Rather, some sites have been audited only every few years. In addition, it is important Xhat, as shown in the new PTT organization+, structure effective January 1, 1992, the Office report directly to tf.,U Governor (it previously reported to the Deputy Governor for Special Affairs). This will empower the Internal Audit Office and help its recommendations to be taken more seriously. Accordingly, assurances were given at negotiations that not later than September 30, 1992, the Internal Audit Office will report directly to the Governor, and that the budget and staff allocation of the Office will be changed to provide for three more engineers, to be in-place not later than March 31, 1993, bringing the total number of engineers on the Office's staff to six (para. 7.2). This will enable the work to be completed as recommended. 4.14 PTT's external audit has in the past been performed solely by the Office of the Auditor General, the government organization responsible for auditing all state enterprises. While the performance of the Office of the Auditor General has been satisfactory, it is desirable that as PTT takes steps towards corporatization and potential privatization, it should also be audited by a private sector auditing firm. Accordingly, agreement was reached during negotiations that PTT in the future will be audited in accordance with the generally accepted accounting principles by a private - 37 - independent auditor acceptable to the Bank and PTT, and that PTT will submit to the Bank its audited annual financial statements within six months of the close of each fiscal year (para. 7.lf). Insurance 4.15 PTT carries insurance against loss or damage which could cause serious financial harm, and otherwise tries to limit its risks through an internal risk management system. It protects itself through all risk insurance, which provides coverage against property damage on major properties and any subsequent business interruption, protection against third party legal liabilities, protection of cargoes and against delays or damage in transportation, and protection against any catastrophic loss. The insurance is provided through the Dhipaya Insurance Co. Ltd., a state enterprise which reports to the Ministry of Finance. Most of the risks against which PTT is insured are in turn transferred to the reinsurance market through the Sedgwick Energy Group, London. PTT would continue to make these provisions, which are satisfactory to the Bank, to provide insurance against risks and in amounts consistent with appropriate practice. Taxes 4.16 PTT is required to remit a portion of its net income to the Government as determined by the Ministry of Finance on a periodic basis. Remittance to tho Government is now set at 35% of net income and it is expected to continue at that level. This is consistent with the corporatt. tax rate in Thailand as well as to most other state enterprises. 4.17 Customs duties and business taxes on imported equipment and materials for PTT projects have in the past been covered by the Government in the form of equity contributions. Ho-7ever, the Government has not agreed to PTT's requests for assuring similar concessions for projects in the future. Duties and taxes are therefore expected to be met from PTT's own resources. Management Information System 4.18 The Management Information System (MIS) of PTT consists of six separate systems, some of which were inherited from PTT's parent organizations. These systems include the SCADA system which monitors the operation of the gas separation plant and pipeline systems, a finance and accounting system, a management information system, a marketing system, and two data systems -- one for oil and one for gas. These systems will need to be adapted to PTT's new organization and they also should be integrated. Integration of the systems would facilitate the transfer of information from one function to another, both making access to information more immediate and establishing the communication links which would encourage closer integration of PTT's various departments. 4.19 Integration of the systems and adaptation of the MIS for the proposed organizational structure would most appropriately be done by - 38 - outside consultants since the MIS Department of PTT has neither sufficient staff nor the specific expertise to accomplish the scope of work required. A consultancy contract, the first phase of which would cost approximately US$1 million, would te required to complete the assignment, and has been included in the proposed project. The study will be carried out not later than December 31, 1992 (para. 7.1j). EssenLially, the first phase of the consultancy service would involve identifying how PTT's existing computer systems and those currently under development should operate under the new organizational structure implemented January 1, 1992. It would include updating the MIS master plan, which would be implemented over the next five years. This would involve developing a high level data model as a basis for identifying the total integration needs relating to PTT's data and systems; it would also involve an assessment of PTT's hardware needs. In addition, the consultant would propose the optimal structure and staffing plan for PTT's MIS department. Research and Development 4.20 PTT's Research and Development Unit is a part of the General Service Unit under the Vice-President for Technical Services. Although to date PTT's research and development efforts have centered on the marketing of petroleum products and on pollution reduction, an important future goal is to develop new applications and uses for natural gas. This would include developing residential/commercial uses for natural gas, natural gas use in the transport sector, and the cogeneration of electric power. 4.21 In the residential/commercial sector, PTT plans to investigate the use of natural gas for such purposes as air conditioning, and it hopes to improve the efficiency of gas appliances. Technological assistance will be sought from major gas utilities such as British Gas, Osaka Gas and Tokyo Gas. With regard to the transport sector, an active program is in place for developing compressed natural gas (CNG) as a motor fuel, especially as a substitute for diesel oil. The government has approved the purchase, by the Bangkok Mass Transportation Authority (BMTA), of 200 buses especially designed to operate on CNG. The buses are expected to be operational in 1993. If results are encouraging, the BMTA may eventually replace its entire 2,000 bus fleet by CNG-powered units. PTT is currently experimenting with two diesel engine buses running on CNG, and it is developing CNG fueling stations. Research and development activities with regard to co-generation will initially focus on evaluating the technical, financial and economic feasibility of using cogeneration to produce electricity for use in the gas separation plants. - 39 - V. FINANCIAL ANALYSIS A. Past Performance 5.1 PTT's performance for the period FY86-90 is summarized in Table 5.1. Detailed statements are given in Annex 15. Table 5.1: SUMMARY OF PTT's FINANCIAL OPERATING STATISTICS, FY86-90 (Debt million) Fiscal year ending September 30 1986 1987 1988 1989 1990 Revenues 38,578 38,561 41,357 45,744 58,047 Cost of Sales 32,368 33,009 34,725 39,570 49,427 Adininstrative Expenses 1,396 1,068 1,259 1,250 2,284 Depreclation 1,124 1,003 1,173 1,271 1,380 Total Operating Ezpenses 36,354 36,167 38.318 43,243 54,942 Interest Expens* 1290 1,294 1,200 1,382 1,286 Operating Incoam 2,224 2,394 3,039 2,501 3,106 Not Income 528 717 966 705 1,411 Accounts Receivable 4,668 4,882 5.705 6,541 8.336 Total Current Assets 11,957 12,748 12,259 14.362 17,954 Fixed Assets 21,534 22,521 23,940 24,873 27,111 Average Hot Fixed Assets 20,557 21,269 22,482 23.668 23,818 Total Assets 35,608 37,677 39,890 42,663 50,449 Current Liabilities 7,185 7,845 7,491 8,068 12,123 Long-Term Loans (Not) 16,494 16,156 16,292 16,320 16,302 Total Long-Tern Liabilities 17,059 16,469 16,414 16,331 16,309 Total Equity 11,363 13,363 15,986 18,264 22,017 Primary Ratios: Rate of Return (M) 11 11 14 11 13 Debt service coverage (times) 4.1 2.2 1.2 0.9 4.1 Operating ratio CZ) 94 94 93 95 95 Current ratio 1.7 1.6 1.6 1.8 1,5 Long term debt as S of total Capitalization 59 55 50 47 43 SeLf-financing ratio (I) (3-year average)t N/A N/A (73) (35) l28 /Z Including taxes, but excluding interest charged to operations and foreign exchange losses. /k On average not revalued fixed assets in operation. /£ Company records do not break out long-ternm loans received and repaid ptior to 1988, but rather reflect a not emount. Accordingly, a self-financing ratio for 1986 and 1987 cannot be properly calculated. 5.2 During the period FY86-90, PTT's revenue increased from B 38,578 million to B 58,047 million--at an average annual growth rate of nearly 11. The revenue growth was particularly dramatic in FY90, when sales increased by 26X over the FY89 level. This was the result of a substantial increase in PTT's revenues from oil operations. Sales volume of petroleum products increased from 4,770 million liters in 1989 to 6,827 million liters in 1990, for a gain of 43Z. This resulted in PTT's increasing its share of the total market from 261 in 1989 to 301 in 1990. To a large extent, PTT's operating income and net income rose with sales through the FY86-90 period. The one exception to this trend was FY89, when both operating income and net income declined. This reduction in income in 1989 - 40 - occurred primarily because PTTs gas separation plant was forced to shut down for 124 days (as opposed to 33 days in 1988) when mercury was found in the cold box. The plant outage resulted in a 44X increase in PTT's refined product imports. 5.3 During the past five years, PTT has been a strong financial performer. This is primarily indicated in its rate of return (ROR) on net revalued assets in operation, which has remained at or above 11 during the period. <(Assets were revalued using government-published inflation indices for fixed assets.) Due largely to the unevenness of debt repayment obligations, PTT's self-financing ratio (SFR) has been volatile. Indeed, in FY88 and FY89 PTT's total debt service was larger than its internal cash generation reduced by the increase in non-cash working capital. After being negative for two years, PTT's self-financing ratio (which was 731 in FY88 and 35X in FY89) then jumped to 1281 in FY90. This dramatic swing in the SFR was primarily caused by a 971 drop in PTT's long-term loan repayment obligation, from B 4,081 million in FY89 to B 126 million in FY90. PTT financed its debt service obligations primarily through a reduction in cash. While it will be important for PTT to smooth out its future long-term loan repayment schedule (para. 5.4), it is notable that during the FY86-90 period, PTT financed 421 of its total capital investment program with internally-generated funds (Table 5.2). Also, it will continue to be advisable for PTT to re-finance some of its debt to lengthen maturities and to reduce the percentage of debt financed in yen. Accordingly, for future calculations of debt service coverage and self- financing ratios, refinancing will be excluded from debt service figures so long as the term of the debt, including the refinanced portion, does not exceed 801 of the useful life of the assets financed by the debt (para. 5.9). Table 5.2 PTT's FIMNIG MM, FY86-90 Bebt U8 X (dLLion) CatlUon) Capital Inestomt 15,437 605 100 TotaiL Ca~Ltal Invmtmmnt 15In37 Scurcas of Funde Zatasul Cash Generation 27,892 1,093 180 Less: Debt Sorvias 15,446 605 100 Workka Capital Requirmment 5.843 229 36 Net Intornal CGh Generation LAU E M 3orrowl"8\6 7,069 277 46 Lose Sncroeas/Add deorease In cash (1,127) (44) (7) Oth.r 1,865 73 12 Totl ource. of Fund. ILA fin i jV UorowirSo reflect nuib: for M8S-90 only sLnoo c°°pay records do not break out lon-tez loans received and repaid In FY66 and FY87 but rather reflect a not uamt. - 41 - 5.4 PTT's borrowings have been heavy, and the amount of its .debt has been expanded substantially by the appreciation of the Japanese yen, the currency in which about 30X of PTT's debt is denominated (para. 5.6). An uneven debt repayment schedule (para. 5.3), exacerbated by mushrooming foreign exchange losses (at year end FY90, the total unrealized exchange loss on the revaluation of loans for completed projects was B 2,888 million), caused PTT's debt service coverage ratio to drop to 0.9 times in FY89. However, PTT is a financially sound organization. Its debt service coverage ratio averaged 2.3 times during the FY86-90 period and was 4.1 times in FY90. PTT's capital structure remains satisfactory (long-term debt was less than 601 of total capital throughout the five years, falling from 591 in FY86 to 431 in FY90). To avoid erratic financial performance, PTT should in the future consider arranging a more level debt repayment schedule or plan debt refinancing to lengthen loan terms so that they correspond more closely to the useful lives of the assets financed. B. Present Financial Position 5.5 PTT's financial position as of fiscal year end 1991 is healthy, with a self-financing ratio of 1211, an ROR of 131, and a debt service coverage of 4.1 times. These robust ratios were caused in part by a substantial sales increase of 341 in FY91 (this on top of the ample 261 increase of FY90): operating income increased by 571 over FY90's level; net income went up by 1311. They are also reflections of the uneven capital investment program and debt service obligations of PTT. Capital investment in FY91 amounted to only B 3,113 million, which was a decline of 461 from the FY90 level, and the debt service requirement, at B 2,028 million, was 341 lower than the average of the previous five years. The ratios have, however, given PTT a strong balance sheet which positions it well for its future operations. As of September 30, 1991, PTT's debt to total capitalization ratio was 341 and its current ratio was 1.8 times; accordingly, PTT is in a strong position to take on the expanded capital investment program which is anticipated for the next few years. 5.6 Although PTT's FY91 debt to total capitalization ratio is low enough to give PTT ample flexibility (para. 5.5), PTT nevertheless has significant foreign exchange losses: its debt has been expanded by about 201 due to currency fluctuations. As of September 30, 1991, PTT had long-term debt (net of current maturities) of B 15,480 million, of which about 301 was denominated in Japanese yen. Since the Baht has weakened substantially against the yen, PTT had incurred foreign exchange losses of B 2,606 million. A 1986 Ministry of Finance directive required all. state enterprises to revalue foreign currency loans as of September 30 of each year, and spread the loss over the remaining term of the loans. PTT treats its foreign exchange loss in accordance with this policy. The policy is not in compliance with Generally Accepted Accounting Principles, which provide that except in the case of devaluation, the foreign exchange loss should be written off each vear as it occurs. However, because the yen tends to both appreciate and depreciate against the dollar (the currency to which the Baht is essentially tied), the Thai Government policy provides a - 42 - smoothing effect which the Bank mission determined to be acceptable. While the Thai foreign exchange accounting policy would not be appropriate in an environment in which the local currency always depreciated against the foreign currencies, it is acceptable in the Thai context and in fact precludes the wide swings in earnings which would result if foreign exchange losses were written off year by year as they occurred. C. Financial Outlook 5.7 PTT's healthy financial performance is projected to continue throughout the next five years. The challenge for PTT in the near-term will be to assimilate and finance the expected sizeable expansions in its capital investment. Its current financial strength should allow it to do this without excessive difficulty. Key indicators of PTT's financial performance for the period FY91-96 are presented in Table 5.3, and detailed projections are shown in Annex 16. Table 5.3 8UMMARY OF PTIS PINANCIAL OPERATING STATISTICS, FY91 - 96 (Baht miLlion) Fiscal Year Endina Sentember 30 1991 1992 1993 1994 1995 1996 Revenuas 77,357 79,945 88,994 104,756 125,697 139,925 Coat of Sales 65,775 69,076 77,446 91,347 110,000 122,405 Administrative Expenses 2,194 2,367 2,859 3,330 3,795 4,262 Depreciation 1,566 1,496 1,568 2,284 2,597 2,803 Total Operating Expenses/a 72,489 75,653 84,423 99,507 119.448 133,178 Interest Exponse 1,206 1,245 2,207 3,063 3,508 3,151 Operating income 4,868 4,292 4,571 5,249 6,250 6,748 Not income 3,255 2,682 2,127 1,917 2,568 3,464 Accounts Receivable 6,612 9,413 9,892 11,306 13,424 14,739 Total Current Assets 20,676 20,744 22,846 25,795 29,932 34,772 Investments in Subs. and Affiliates 5,276 8,308 11,115 15,017 17,398 17,713 Property, Plant end Equip. (Net) 27,201 26,644 29,698 39,666 41,720 60,020 Averago Not Fixed Assets 25,464 26,923 28,171 34,682 40,693 50,870 Total Assets 54,205 62,388 74,501 92,465 106,738 114,496 Current Liabilities 11,385 11,903 12,396 14,760 17,045 18,608 Long-Term Loens (Net) 15,480 20,050 29,645 42,356 49,325 50,923 Total Equity 27,332 30,427 32,452 35,341 40,360 44,957 Pzlmary ratios: Rate of return (Z) /k 13 16 16 15 15 15 Debt service coverage (times) 4.1 3.1 2.3 1.8 1.7 1.9 Operating ratio (Z),/ 94 96 96 96 96 96 Current ratio (times) 1.8 1.7 1.8 1.7 1.8 1.9 Debt as X of total capital 36 40 48 55 55 53 UeLf-financLng ratio (Z) (3-year average) 121 25 16 25 25 38 /^ IncludLng taxes, but excluding interest charged to operations and foreign exchenge losses /k On average not revalued fixsd assets 1n operation - 43 - 5.8 Although PTT's sales revenues are expected to increase only 3.41 in FY92, sales growth for the FY92-96 period is projected to be 151 per year. Most of this increase is in the sales volume of petroleum products, which are expected to grow on average 14X per annum. Petroleum prices are forecast to remain fairly steady through the five-year period. Total gas flow is expected to increase at a slower rate, averaging 4X per year: the increase would come from gas flowing through the proposed pipeline. Gas prices for existing gas are forecast to remain fairly constant; prices for gas flowing through the proposed Bongkot Pipeline, beginning in 1994, are projected to be about 161 higher than for the for existing flows. (Further information regarding these assumptions is included in Annex 16 and is provided in greater detall in the project file). PTT's net income is projected to decrease through FY94. This is due largely to increases in interest expense in FY93 and FY94 (resulting from the incremental debt required to finance PTT's expanding capital investment plan: PTT's total debt service obligation will jump 771 in FY93, and another 391 in FY94). PTT's operating ratio, which was 941 in FY91, will rise to 961 in FY92 and remain at that level throughout the projected period. The ROR is projected to remain at or above 131 between FY92 and FY96. PTT's net property, plant, and equipment which will be revalued each year according to an index published by the Ministry of Finance, will increase at about 171 p.a. from B 27,201 million in FY91 to B 60,020 million in FY96. 5.9 Due to PTT's expected continued high level of profitability, its self-financing ratio over the medium term is forecast to remain at healthy A'S is. Except in FY93 (when internal cash generation will not be sufficient to cover the projected higher interest expenses and still contribute 251 toward the substantial capital investment program), the ratio will range between 251 and 381. The SFR is projected to be about 161 in FY93. Agreement was reached at negotiations that, except in 1993, PTT would generate funds from internal sources equivalent to not less than 251 of the annual average of its capital expenditures incurred, or expected to be incurred, for that fiscal year, the previous fiscal year, and the next following fiscal year. For its fiscal year ending in September 30, 1993, PTT would generate funds from internal sources equivalent to not less than 151 of the annual average of its capital expenditures (para. 7.lg). 5.10 PTT's capital structure is projected to remain satisfactory throughout the FY92-96 period. The debt to total capital ratio is expected to average 501 and remain at or below 551 on a revalued asset basis. The debt service coverage ratio is estimated to range between 1.7 and 3.1 times throughout the projected period. Agreement was reached at negotiations that PTT's debt-equity ratio (calculated after the revaluation of PTT's assets) will not exceed 60/40 and that its debt service coverage ratio will be at least 1.3 times. Debt refinancing would not be included as repayment of debt for debt service ratio calculation purposes so long as the term of the debt, including the refinanced portion, does not exceed 801 of the useful life of the assets financed by that debt. Indeed, such refinancings are encouraged as a way for PTT to smooth its schedule of debt service obligations (para. 7.lh). - 44 - D. Investment Prok * and Financing Plan 5.11 Annex 17 provides PTT's FY92-FY96 Investment program, which amounts to about US$2.3 billion. The investment program was reviewed by the Bank mission and the necessary adjustments were made to provlde for a more realistic implementation schedule. It was agreed that the Bank would work closely with PTT in developing future investment programs and coherent poli^ies for PTT's joint-venture participation. The Bank and PTT have agreed that the Bank should be consulted about the revisions and preparation of PTT's long-term investment plan in order to make more efficient use of capital resources in the gas sector (para. 3.2). During negotiations, agreement was reached on annual review of PTT's investment program by the Bank, with PTT required to take into account the Bank's comments (para 7.1i). 5.12 A financing plan for PTT over the project period (FY92-96) is presented in Table 5.4. Tablo 5.4.t PTT's FIRICNO PLAN, PY92-96 asht US$ 3 (millon) (Million) Capital Investment 59,310 2,324 100 Total Capital InvOstment ,59.10 AM 100 sources of Funds Internal Cash Generation 43,966 1.723 74 Leas: Debt Servico 22,094 866 37 Working Capital Requlresnt 7,271 285 12 Not Internal Cash Generation 1*4601 32 Borrowings 44,363 1.738 75 Less Inereas/Add doorease in cash 396 16 1 Other (50) (2) 0 Total Souroes of Pundo a,i59.910 Li 12 5.13 The proposed project, including interest during construction, represents about 19X of the overall investment program during the FY92-96 period. The proposed Bank loan of US$105 million is expected to meet about 41 of mT's total financing requirements for the perlod. During the FY92-96 period, PTT expects to meet 251 of its total capital requirements from internally generated funds. 5.14 Borrowings from external sources amount to 751 of PTT's financing requirements for FY92-96. ITT's sources of foreign borrowings are expected to be the Bank (with its 17 year term, 4 year grace period, - 45 - and interest rate of approximately 7X), the Overseas Economic Cooperation Fund of Japan (with a 30 year term, 10 years of grace, and 2.5X interest rate), the Japan Export-Import Bank (with a 15. year term, 5 years of grace and approxiartely 71 interest rate), and foreign commercial banks (typically with 10 year terms, 2 years of grace, and pricing at approximately London Interbank Offered Rate (LIBOR). PTT expects to raise funds locally by issuing bonds and by borrowing from local commercial banks. - 46 - VI. JUSTIFICATION AND RISKS A. Economic Benefits 6.1 Projected supply and demand of natural gas indicate that beginning in 1993-94 and continuing through the life of the proposed project, Thailand will be facing a deficit in gas supply (para. 2.14). The Government policy to cope with the deficit would be to adjust the supply to EGAT, by far the largest consumer of gas, while providing other existing consumers with their full gas requirements. The economic viability of the proposed gas project should be assessed based on the economic position of natural gas in EGAT's least-cost expansion of power generating capacity. BGAT's fuel choices in the absence of major hydro candidates are: (a) domestic coal (lignite) which, even if developed to its full potential and ignoring its environmental externalities, would not be sufficient to supply the fuel needed for the incremental power demand during the 1990s; (b) natural gas; (c) imported coal; and (d) imported fuel oil. EGAT's analysis indicates that natural gas utilized in the combined-cycle power plant represents the least-cost fuel for power generation (para. 2.16). 6.2 Although the economic viability of gas supply is demonstrated by the priority ranking of the gas option in EGAT's least-cost development plan, the internal economic rate of return (IERR) of the proposed project should be calculated based on its incremental costs and benefits. The incremental costs include: (a) capital and operation and maintenance (O&) costs of gas development and production; and (b) capital and O&M costs of gas transmission. The gas development and production costs are estimated based on the planned schedule of drilling and installation of the required facilities by the gas producers to produce 1.5 tcf of gas. These estimated costs, both capital and O&M, are investment-grade estimates and highly reliable because they have been submitted as part of the Gas Sales Agreement for the "Definitive Cost" of the field development and production plan (para. 3.8). The estimates have also been verified by DeGoyler and MacNaughton. The capital cost of the proposed project is based on PTT consultant's estimate, representing the construction cost of pipeline systems connecting the Bongkot field to Erawan platform, and the Erawan platform to Khanom. The project cost estimate is now confirmed by actual bids and quotations received from the suppliers for various project components. The O& cost for the project is assumed at 3X of the capital cost. 6.3 The incremental benefit of the proposed project is estimated based on the economic value of marginal gas supply. The marginal economic value consists of: (a) the netback value of gas used in EGAT's combined- cycle power plants; namely, the value of fuels (mainly fuel oil) displaced by gas, corrected for the differential in thermal efficiency; and (b) the net value of liquids extracted from the raw gas prior co its being used for power generation. - 47 - 6.4 For the base case, the IERR calculated is 26Z. Details, including the assumptions tused, are given in Annex 18. This hlgh rate of return Is largely due to: (a) the value of condensate (gas liquids) which is produced in association with the gas and sold in international markets for almost the same price as crude oil; and (b) the high efficiency of natural gas in combined-cycle power plants. 6.5 The analysis of the sensitivity of the IERR to the underlylng assumptions indicate that if the capital and O&M co. ;s increase by 10, the IERR decreases only by 31. Hence, the project would have to incur exceptionally high development and production costs (the main project risk due to complex reservoir geology), in order to render the project uneconomic. The sensitivity of IERR to other assumptions are: IERR (X) (a) Price of fuel oil decreases by 10; 24 (b) Capital and O& cost, up 10; 23 (c) Gas supply, down 10; 23 (d) Capital and O&M cost up 101, and gas supply down 10, 20 6.6 Assumptions used for the base case IERR are rather conservative in that the price of fuel oil is assumed to be 801 of the crude oil price projected by the Bank. Historically, the fuel oil price in the Singapore market has hovered around 85-95X of the crude oil prices. Furthermore, it is assumed that the total volume of gas which will be produced from the Bongkot field would be limited to 1,500 bcf, namely the contractual reserve. The more likely scenario is that at least 1,750 bcf of gas will be produced from the Bongkot field. The IERR was also tested assuming that the gas would displace the fuel oil on a Btu-Btu basis, hence discarding the thermal-efficiency value of the gas in power generation. The IERR calculated on this basis is 141. 6.7 The financial rate of return calculated is 161. Annex 18 also shows the detailed calculation of the project's financial rate of return. This calculation is based on the capital and operating cost estimates contained in the project cost table, including taxes and duties. Although the Gas Sales Agreement between PTT and EGAT does not provide for a firm price for the Bongkot gas, which comes on stream in 1994, PTT intends to seek a price for this gas from EGAT which would cover its costs and which would yield a reasonable (121) return on its investment. PTT is currently contemplating a price of Baht 80-82 per mmbtu, based on the present cost estimate of the project. The final price of the Bongkot gas to EGAT will be decided in 1993, when the project costs are more accurately established. B. Environmental Benefits 6.8 An added benefit of the proposed gas infrastructure investments is the major contribution natural gas will make toward mitigating the impact of energy use on the quality of the environment. Without the proposed project, the fuel used by EGAT for power generation would be - 48 - either coal or fuel oil. Compared to coal and fuel oil, natural gas is a clean and low-polluting fuel; its expanded availability particularly in the Bangkok area (and progressively in other parts of the country) will lead to a significant improvement in air quality in these areas by reducing emissions of, inter alia, S02 and particulates (para. 3.17). The new gas- fired power plants will in effect substitute for fuel oil or coal-fired stations. Based on the fuel substitution, the project is expected to reduce emissions of S02 by about 45,000 tons each year. The project would also result in a net reduction in CO2 production by 2-3 million tons annually. C. Risks 6.9 Risks for the project revolve around two areas: (a) the availability of sufficient gas reserves; and (b) the costs of producing such reserve. The gas reserves have been assessed and certified by DeGolyer and MacNaughton, which is pre-eminent in the field of reserves estimation, to exceed 1.5 tcf, the volume on which the proposed project is based. The risk of insufficient gas reserves is therefore low. The risks associated with a potential increase in production costs stem from the complex nature of the reservoirs, in that the volume of gas is distributed in numerous small reservoirs, requiring a larger number of platforms and wells than would otherwise be expected. This risk has been mitigated by taking into account appropriate contingencies in setting cost parameters, and benefitting from the experience of Unocal producing nearby since 1981. - 49 - VII. AGREEMENTS REACHED AND RECOMMENDATION A. Agreements 7.1 The following agreements were reached between the Bank and PTT during the negotiations: (a) That PTT shall, prior to entering into any amendment to the Gas Sale Agreement (between PTT and EGAT) or the Gas Purchase Agreement (between PTT and Gas Producers) -- amendments which shall be considered by the Bank and PTT as affecting PT-'s ability to perform under the Loan Agreement-- exchange views with the Bank, and shall take the Bank's views and recommendations into consideration in deciding whether or not to enter into such amendment. It was further agreed that amendments that would be considered as affecting the ability of PTT to perform under the Loan Agreement are those dealing with the: (i) quantity of gas to be purchased by or sold to PTT; (ii) price of gas sold to or purchased by PTT; and (iii) duration of the agreements (para. 3.10); (b) That PTT shall furnish to the Bank not later than December 31, 1992, for its review and comments, a report containing the results of the inspection test, evaluating the operating condition of the existing 34-inch pipeline; and that PTT take into account the Bank's comments and the pertinent recommendations of the inspection report regarding the operation of the pipeline (para. 3.13); (c) That PTT shall take all measures required on its part to ensure full implementation of the action plan and the associated monitoring activities contained in the Environmental Assessment Report (para. 3.17); (d) That PTT shall, not later than December 31, 1992, furnish to the Bank for its review and comments, an audit report of the safety of PTT's operations and take all measures required on its part to ensure implementation of the report's recommendations taking into consideration the Bank's comments (para. 3.21); (e) That PTT shall furnish to the Bank during each fiscal year until completion of the project, commencing November 1, 1992, a quarterly progress reports on the physical progress of the project (para. 3.39); (f) That PTT would be audited, in addition to the Office of the Auditor General, by a private independent external auditor acceptable to the Bank and PTT, and that it would submit - 50 - to the Bank, audited annual financial statements within six months of the close of each fiscal year (para. 4.14); (g) That except in 1993, PTT would generate funds from internal sources equivalent to not less than 25Z of the annual average of its capital expenditures incurred, or expected to be incurred, for that fiscal year, the previous fiscal year, and the next following fiscal year. For 1993, the internal cash generation would be 15X (para. 5.9); (h) That PTTIs debt-equity ratio (calculated after the revaluation of PTT's assets) would not exceed 60/40, and that it would have a debt service coverage ratio of at least 1.3 times. Debt refinancing would not be included as repayment of debt for debt service ratio calculation purposes so long as the term of the debt, including the refinanced portion, does not exceed 80X of the useful life of the assets financed by that debt (para. 5.10); (i) That PTT and the Bank, not later than December 31 of each fiscal year until the completion of the project, commencing in 1992, shall carry out a joint review of PTT's investment program for the period FY92 to FY96, PTT paying due regard in each instance to the Bank's comments and recommendations (para. 5.11); and (j) That PTT engage qualified consultants, under terms of reference, conditions and timing satisfactory to the Bank, to: (1) not later than October 31, 1992, commence carrying out an engineering study for a new project to transport additional gas from the Erawan platforms, including the feasibility of constructing a second pipeline from Erawan to an onshore location in the Central Region (para 3.14); (2) not later than March 31, 1993, commence preparing safety engineering and environmental standards for its entire operations (para. 3.22); and (3) not later than December 31, 1992, commence carrying out a study for improving PTT's Management Information System (para. 4.19). 7.2 During negotiations, .mderstandings were reached that: (a) PTT would take the necessary measures to hold regular meetings with EGAT at least every six months in order to coordinate more closely regarding the proper programming of their investment (para. 2.18); and (b) the Internal Audit Office would: (i) not later than September 30, 1992, report directly to the Governor of PTT, as proposed in the revised organizational structure; and (ii) be provided with a budget and staff allocation for recruiting three additional engineers who would be in place not later than March 31, 1993 (para. 4.13). - 51 - B. Recommendation 7.3 With the above agreements and assurance, the proposed project constitutes a suitable basis for a Bank loan of US$105 million equivalent to PTT, with the guarantee of the Kingdom of Thailand, at the Bank's standard variable interest rate for a 17-year term including a 4 year grace period. - 52- ANNEX- THAILAND BONGKOT GAS TRANSMISSION PROJECT Commerclal Energy Balance, 1989 (ooo We) Ind _P n duo 2, 240 4,36.2 479. 96.6 Iaiq,uW 247.0 10,340.8 5,6. 513. 1MB. Mwlii Bunk"ta 0.0 Stock Chanam (39.6) i D(O (0 --)- (2866) TCPmAL .RuM Y SLOY SPLYY 286.7 116.2 5*1. 435112 00 479.1 51.3 0.0 2401.0 Tranum (40 40.o (02 stwiudoONhrsi 3 .4 34 Gan wag 0.0 Pslom RunWWW (11.4156O) 10,01 (4.3) (517.1) U_n 0.0 Pui*s ( 6 (919.6) (4.057) (479) 321. (4.0694) AhloPrduchr ct Egos. 2A0) 61. (158) CHP Plw 0.0 Oleb Huadno 0.0 OUwTnrmwln 0.0 Own Lin (121.0) (121.6) DiNolbu Loss Su (25) (1974 . _ (32.) (408l8) TaTAL M&CCNUO_ 786 37.7 15,417.0 104.5 0.0 0.0 2,90. 0.0 19.248,2 R tUm Y w Im R 734 0.0 2W 10 0.0 0 1,4097 0.0 4,S15 144.3 35.6 197 369.& (of LdUa PIo Fi mn,mlu 0.0 NnjFavotwmm .1664 t1884 Nan-Malic MIn 341.6 620 6.9 1,072.5 TraroflEWIk% &Uaoh. 2L1 11LI 1462 MinaOwuwfg S6a 5a8. Food ad Toao 217 39.1 272.0 6608 Pow. Pulp aN ProInti 937 61.1 15. W aodd Wood Produrn 31.9 27.9 5.8 COmAmujaon 110.3 110.3 Taxl md Loom 411.3 303.8 715.1 Non-SpCfle Indaby 416. 2K4.8 123.7 763.6 TRANUP0RFSETOR 0.0 0. 10,99" 0. 0.0 0.0 0.0 0.0 10,398. Ar 1,776S 1.77M o2 &m.1 8,22D.1 PAN 0.0 Anto nal Navloalan 0.0 Non-Spem d T _ar^ t 4#03 400.3 OTS1 OTR 0.0 0 254 0.0 0.0 0.0 1,46.6 0.0 4,O060 AwlCuS 1,16L. 7.7 1,67n9 Coa. & PUh SWAM m.3 869.3 _1SMO" am 604.1 1.4fO0 Non-Spcfied OUhe 41.4 15.5 6.&9 nEne Uv Ve 37.7 171.6 209.5 -m6g.. I)7,7 0 1.710 19.1no 0 5.571 0 0 3a354 A7 1 4.72 19,195 ,571 37,406 Aukw 5*c 048 1948 A_~ - S el.. W - ~~~~~~g o . E I }g g R | ; | igUE~~~~~~. - CS - g aF ANNE2d Pap 2.1 THAILAND BONGKOT GAS TRANSMISSION PROJECT Commercdal Ene Demand 1990-2005 OUnb~~~~~~~~~~~~~~~~~~~~~~~~~~U an (rm* 4.14 24.66 5.140 51.41 6.51 W.M 45.79 AM042 46608 7016 7"0 hq_o1 750 40 71 705 "7 705 705 70 71 705 70 7"1z 05 - Fd.k 76 1329 19 10 1i 140 14 16 64 54 23 m - un h_6 1 A 1.7 120 170 13 198 1.9 1 0 J24 1 42 - T:0 442 Su 2SW73 s 5. 514 8t o 71 M 405 i - bi 2 7 1.661 20 1 a1 24 26 2s s1 * ow.So T '4.~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~4 -EIAT 4,@9 4F05 8,120 6.116 0.20 al,"0 6.610 S,"10 8.647 7. 7,7" ?A Dao_l 4,147 tm 5.410 5,410 6.i16 6,"5s G6M CMS 5.94 G.M 7,@ tM knpow 760 740 710 70S 705 70 705 7OS 705 S 7 a 705 -ESLAT &M6 14459 11.947 1%038 1036 1&03B 14.040 19.103 2Q078 SYUS8 M93 51.=9 LW*Dn L780 16A4# 11.947 19036 1909B 11o3 1=74 16S9 16590 W51 2L107 35.614' cod a28B 25n 4m29 li48 &140 1827n - "^hnb 1.60 i,72 I.Ms Z002 L153 2.917 2.493 2.683 im8 3.107 aou4 4.239 UV**l 1.314 1.419 1S541 1.66 1.79B 1.942 2.09 12S 2U47 Z843 2-855 &644 codS 0; I 0.303 U291 awl7 US61 Q9376 Q9951 U171 OA40 0Q4B I L489 I u5#s *a m -8h .S sam mf - 55 - Annex 3 THAILAND Page 1 of 3 BONGKOT GAS TANSMISSION Prices of Selected Energy Products (APt 1,1991) . *... ......... .. .......... .... ......................... .................. EX- TAX MAR TtX ET PRZX OtILFUM ITAIL PItCOt0W OtLAPL0 TAX RE?ISRT 3./LIT22 KacZM L/LXTE PRIM X.LLTRS m.mr N.&NT ,,,,........,,,,,,,,,,,,, I.................................................................................... PRE-CAS 3.795s 3.9390 0.6220 1.65 Z.0433 10.40 10S.6. . 21S.5 416.12 -C*CSS S I3 3.a30z 3.9390 0.5 09 7.1o01 1.99 9.70 14. 1O zn.97 563.37 tEo- 57 *M. 3:4w. 3.9390 0.60 8.0243 1.8737 9.90 0.00 0.00 0.00 EER NME 3.75 2.5280 0.396 6.7199 2.000 8.72 11.65 23.35 29.4* H-OtESEL 123 3.9"4 2.2Z0 0.4*58. 6.622 1.54?! 8.20. 3S9.63 . 555.09 796.1 x-OtESEL 0.52 AD.0fl6 2.20 Q.41 6.719' 1..0 8.20 0.00 0.00 0.00 L-OtES£L 3.9165 2.2o 0'.25 6.4= I.5775 5.m0 10.14 15.99 22.SZ FtEL600 (1) 2.2958 0.7 WO 0.1756 * 3.173 O.7t6 3.75 61.33 * 3S.06 43.36 FUE01500 CZ) 2.0511 0.7070 0.1756 ' 2.9=7 0.s63 3.40 129.15- 60.22 91.31 FUE!.2000 C) 1.9900 0.7070 0.1736 2.37Z6 0.4374 3.31 17.96 7.1S 12.70 U£LZS0O (4) 1.9259 0.7070 0.17 2.8085 0.4115 3.22 32.13 13.2 Z2.72 FUEL CS) 1.9259 0.7070 . 0.1115 S3.60 .06 37.t9 LPG-LARCE(S/) 7.DeOt 2.7000 2.3366 12.053 -1.3073 10.73 0.00 0.00 0.00 LPC- 1LL,C1/=0 7.0007 2.7000 2.356 12.0t75 -1.3075 10.7S 24..72 70.66 127.7! WG-cAXSlC=3 7.000? 2.7000 1.0n 10.733 -0.165 9.90 .7.15 -4.16 &..S3 at:ThP csiicw 291S.467 236.296 359.5218 2631051 2'3.3.749 S073.iI 15.71 39.S5 C.15 .............. . ..................-_. __......__............................... zSTOTAL 976.6 117.C 222.1 ._. . . . . . ______... . . . . . . . ........ .. . .. . . . .. ..... . . .....__..._;.. ... . .. IWT TAX MiaTKmG MET PRIM OILFUNO ETAIL l)P03t OtLFJN TAX PRIM2 5./LITRE 'PAzIX B./LITRE P5seS X.LXTU N.8"T X.SAHT =s.................................. .................................................................................. .. ....................... PRE-CUL 3.7955 3.9.90 0.6U2 1466S 2.033 10.4 38.98 79.27 153.9' 2EC-US &3 2PI 3.S302 3.9490 0.S809 7.1601 1.39 9.70 12.79 23.55 s5.52 REC-CAS 87 tCX 3.453 3.9490 0.60W0 J.034S 1.57 9.90 0.00 0.00 0.00 =Rz iENe 3.96L z.m350 0* 96' 6.9008 1.8192 8.72 0.00 0.00. 0.00 It-OtESZL t= 3.912 2.220 0.Lm5 6.690 1.5010 *1.20 240.92 361.62 . 537.7! l-OlESEL 0.S:S L.024 2.2n2 0.8. 6.7312 1.461 S.20 0.00 0.00 W '.00 !-Ot£SEL 3.9109 2.232! 0.2540 6.4.269 1.S731 1.O0 0.00 0.00 0.00 PUEL600 (1) 2.246 0.7010 0.1756 3.1242 0.658M 3.7S 0.00 0.00 0.00 ,ERIEL35O0 C21 1.9m1 0.7080 0.176 2571 7 0.S213 3.40 145.25 76.75 102.5U RIEL2000 CM) 1.9ZS0 0.70JO 0.1736 2.f 04014 3.31 0.00 0.00 0.00 lEL2300 C.) 1.8m 0.70 0.1756 2.7424 0.4776 3J2Z 0.63 030 0.L5 FUEL CS) - 0.70 . . 0.4L776 * 0.00 0.00 0.00 LPc-LARC3tr /S:) L.9W9 2.701o 2.366 t 10.0075 0.7425 ,tr75 0.00 0.00 0.00 LPG*-SwALL 5/T5) L.9'99 2.7010 2.36 10-.0 0.7425 10.75 0.00 0.00 0.00 LP_cAACS3/X) 4L.999 .2JOtO 1.062s . 8.7137 1.183 9.90 0.00 0.00 0.00 sinptLDcaCT0) 2630.3510 266.2966 59.5S21 325^6669v. 1.5106 5073.18 1.76 3.30 0.41. ssugrcTrrAL -..3 54. 86.0 ........ ................ .................................... ............... rorAL 1517.0 1732.2 - 3074.8 ... ... . ...... ............ .,,......................... ,........,,....... ,..,,,, ....................... Source:ArIl.TOTAL (TAX & CILUnD) "07.0 Source: PTTTOA lX&CLU)'800 - 56 - ANNEX 3 Pa ge 2 of 3 Bongkot Gas Transmission Project U.sb"h5W LasNM L W0DNTI&L 7. LWA MANWACr O W O A" b04D G(ai. dmin 3= kw mi Ow) FlMw s kwh too Bak Exw _aW Z N40 ~ ~ ~ ~ ~ ~~~~~~_ :O LIOa B*W Kew 10 kwh 0.70 31kk you £ tWh 0. GA /2W 'tea O&zd= of2=kWinA.~ NM to kth L. UkWh .1 4 em'. uk) pKg S kw 3L. bk/kW Pak Paau. Keg i0 VW LU 3./ * .w *. 1W Utt 110 kw .0 U.kkW Puu ahase6.0Uk/ o n00 kwh 2.02 U.kkWh OffNok7d 1. K i _ Keg 4m kwh US UaksIkW buwcb Qao2 zwk/kWh Not SW mr Z4 MOMW badmo cmq. SA0 shit L K.TRLY WIWACTURW L °"Leme " vaumw o ;W AM .D _L Ws 30 L3 Dmmi Caa* 1. 3.k/k 3mgv awsc 9. PU=IUC V NM 40 kWh u.12 mk K4 230 t L7? U.k/WJ 4a imam ls 20 kw) NSA US kWh LU UWh mma 10 kWh 12.3 5a Ibs eoUS kS 21 U./W 0- 1OkWh LU .kkW N4. ao Ma &M Sdft uwtmbLZmam ow3kW 2.3 U.k/kW &&/m o 9.2 o_9as dmilymeus D-md O.p 5.0 a.k,W LLAWON UUSUU chowe L2. U.k/Wh Csu. ~ ~ 3dlmiWS kWm.v Or 10 wh La U.k/kwh AS veluag aof ea W "W EVI W. am ~amp 1L3. 3.3/k Dow" C_ ; 231.0 adow _rC NOT 13kW1. NOtLOFODOW 4. t30U3 lw 10g kWh 1to kWh 3 10kWh : LM ./W JN v.4l1 of tla KV: *4i W_ 13.45 *.kkW _mm chep 2 0 --W 5mw ~aq. 3.U. U.k/kWh I f_-_ CbV Vt omw ILAORcx TMRL POIMO D1mm C ep 214.050 Us/W FM Ic kW ads _Wu 0u L U.kkWh 0n 100W kWh LInUkWh LS.MUALL bAAKUACrUUSIO & bMUiI ie/mMsg ./w 3DmNd 1.q. N _ .00S3.1W_ DaCag L U.k/wh 2 n up br_sm 4 SI.? ad la mdomhum Sam 305 of S Ginx. 3-mow .iff 9kw) D_=" 0"0 37.00 UbAW = ChOes LU Sini/wh Annex 3 Page 3 of 3 TI.AILANI) . . I BONCKOT CAS TRANSMISSION PROJECT Prices of TAported Coal I I~ 3990 m99 I tI 965 3966 191? 160 1969 199............... ....... .. ............. -- lut---. M i Au u c Ml SE oOC JA t11 I ............... ...............UU ..s.a.t*.......gwuauwuusmgmEa .. uau.S.aMuaaa."seaal....... s6u61 puuSSuU3UUSVUSs ., u..s.B .. u a.8SaImu6sas .S.as.3U38*3 I... 0381381r38 *ou'lis ls Ifow0 lass 3.043 0.0D 0.000 0.b0 0.043 S5.711 4.M10 0.616 0.000 9.615 3.451 S.14 0.000 6..24 O.000 0.0000 2.400 -lPCE (S1ANIJG.) 3.524 0.000 0.000 4.595 9.001 1.045 I.659 1.552 0.000 1.090 3.13. 1.119 0.000 1.101 48.93 0.0000 3.013 VAItuE (ILLION IANIS) 56.620 0.001 0.005 0.001 0.437 50.216 5.0605 0.121 0.000 10.481 S.A4 6.022 0.000 7.005 0.022 0.o000 2.501 A311N64CIll WAV*35III 43000 3I1S) 4.035 4.395 I iS L 4.922 7.921 38.9 1.0430 0.000 11.260 24.60 0.00 0.000 0.000 0.000 0.001 0.0002 0.581 PRICE ESANIIKG.) 2."6 2.633 2.156 3.436 3.082 1.222 I.S69 .D00 2.322 2.259 0.000 0.0o0 0.000 0.o00 24.550 S3.0sto 2.099 * ttuf (Kittle" "ASill 0.254 10.9I6 1.S21 16.025 24.MA5 66.S2 3.633 0.004 26.151 S5.514, 0.000 0.000 0.00 0.000 0.038 0.0102 3.2?? 9toM SOlt10 tUflS IAsW COAL .................... ...... *0QualI (3000 IONS$ 241.611 In.389 2so.228 267.311 250.356 312.293 4*2906 43.0S3 0.000 50.127 80.459 0.000 0.036 0.30011 4.00 0.0520 1.461 -PitE (SAUIIKc.3 1.205 1.129 0.98l 0.9"6 1.302 1.335 2.5sa 0.914 0.000 1.290 1.219 0.o04 10.033 0.000 1.081 9.316" 1.04 I , I v u tnIL,ION 3A*I3S 310.SS3 701.346 245.99S 266.1e0 125.9a6 416.76 109.086 40. 66 0.000 S.jS6. 99.21 0.000 0.360 0.000 59.283 0.466 1.959 PAl. .WAuIII (1000 tons) *0.00s 0.000 0.002 0.000 0.000 o.meo .ooo. 0.000 0.000 o.ooo o.m0 o.0o 0.000 0.000 0.000 0.000 0.0000 P11(6c (SIIIAKG4.1 14.5.606.000 35.566 0.00 0 .00 11.1.00 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 '-VAiL* (hiLtION SANTS 0.012 0.000 * 0I o1e.00o0 6.DO0 C.oe 0.000 0.003 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.0000 0.0000 9(0I Of COA& *0S"t11 (10 13 tOSI 42.072 37.614 SS.419 60.758 84.574 200.252 0.139 6.310 9.144 S4.S52 64.007 6.622 6.53s 30.403 7.169 1.005 S.0126 1 I SIES (GANItG 3.941 53.59 3.304 3.092 3.126 2.99 317.023 *2.54S 4.os9 2.66 2.63S S.129 4.910 3.96 3.302 3. 61 5.61j9 -VAtUE (StI IN 6111A 3 I6.060 134.616 I76.52s 212.610 IS3.301 s59.17s 12.041 16.02 31.925 14631.5 0 12.432 33.920 32.08 41.4SO 23.61? sI.aa13 d.e90 9 .................. :..... ................ ................................... ................... ............ ........................ ....... .. ,;....... ......... I 103*1.' .S*eu jl;NI (3000 IONS) 324.711 220.231 309.u59 13 .076 342.900 601.211 49.14 48.187 20.60a 147.199 14.113 12.006 6.571 16.025 S2.610 7.653 35.535 I ICE(6ANIIK/CI .) 1.66" 8 S O 1.40 1.420 1.943 1.913 2.602 1.182 3.110 1.956 1.923 1.131 4.918 2.8US 1.366 1.14 2195 *nclt SIISOION) 6.2051 M9 .199 54.40 S6.14S 75.A0 71.150 99.s5 45.5s9 119."S 75.613 75.0s 1130.901 19S.993 114.684 S4.013 132.361 103.09 .pW UIMIt, 6 I3311 541.SS9 346.A9 435.11. SIS.621 66.J39 1161.40 121.012 56.969 64.075 261.921 26.004 39.fs2 32.459 4.543 12.99 2S.504 40.25a SOURCE: P? . . . . * . . 1 siiCI JAUUAW 199. COKE Of COA*t tiS OfCOAL *CKE O IIIIIEtl EI .A '*.9Of15IIS *15101A S * IUIIIIUUS ' .. . . - 58 - Page 1 of 4 BONGKOT GAS TRANSMISSION PROJECT Geology and Petroleum Reserves General Geology 1. The Gulf of Thailand contains several present day sedimentary basins. Theme are: Chumpon (West Kra) Basin; Songkhla (East Kra) Basin; Pattanl Trough; and the northern end of the Malay Basin. These basins are similar in most respects. They were formed as extensional rift basins along highly active lateral fault systems. They are filled with Cenozoic Age clastic sediments (sands, silts, and shales) extending from the Paleocene to Pleistocene. The environment of sedimentation ranges from non-marine lacustrine and fluvial deltaic to near shore lagoonal and shallow marine with deltaic association. The basins are separated by intervening highs where thin Cenozoic sediments unconfornably overlie older sediments (Mesozoic and/or Paleozoic Age) and in some areas volcanic terrain or crystalline basement. 2. The fault movements which formed the basins in the Gulf of Thailand persisted throughout the Cenozoic and affected the concurrent deposition of sediment. As movement continued on the lateral faults, structural forces Aithln each basin alternated between compression (uplift and folding) and extension (subsidence and sag). As each of the forces occurred in turn the preceding structure was overprinted with the latest movements. At present each basin is paradoxically characterized by low relief features (both highs and lows) vhich are highly fulted. An echelon rifts are predominant suggesting that the latest activity is primarily exte_sional. 3. With respect to hydrocarbons found, the basrins are all gas prone. The only significant oll discovered thus far is in the southeastern part of the Malay BMain (offshore peninsular Malaysia) and even in this area gas remains a major component. Isolated oil discoveries have been made in the Chumpon and Songkhla basins which are as yet unevaluated. This oil was found in the underlying pro- Cenozoic sediments. Relatively minor oil reservoirs have been encountered in the Pattani Trough, notably in the shallower part of the Cenozoic section. High crustal heat flow, associated with the lateral faulting appears to have placed the bulk at the most prospective sedimenta7y interval in the over mature gas/ condensate realm. The high heat flow regise interacting with the pro-Cenozoic limestones (CaCO3) also appears to have produced significant quantities of carbon-dioxide gas (CO2) which is associated with the hydrocarbon gs. 4. The ten gas fiolds and six as yet unevaluated gas d$scoveries in the Thai portion of the Pattani and Malay Basins as well as the approximately ton gas fields and unappraised discoveries in the northwestern part of offshore peninsular Malaysia (Malay Basin) have strikingly similar characteristics. The gas is reservoired in sandstones of several types associated with river and river mouth and shallow marine systems, i e , fluvial-deltaic. In any given area scores to hundreds of reservoirs are productive. Productive reservoirs vary from just a few acres to 2,000 acres or more in areal extent but most are rslatively - 59 - Page 2 of 4 mall. Most of the Se is structurally trapped with the bulk of the reserves associated with high side fault closures and much of the remainder is associated with romnant folds within the low (graben) fault blocks. Gas is also trapped stratigraphically in lenticular sand bodies not associated with faulting or crestal portions of folds but those reserves are somewhat randomly distributed and of lesser significance. The close association between the concentration of productive reservoirs and fault closures suggest that: (L) fault planes served as paths for gas migration during at loast part of their existence; and (ii) that the gas source rocks my be pro-Conozoic (this is almost surely the case for the carbon dioxide gs). 5. The salient points are that the gas fields contain many individual reservoirs of varying size and shape and most individual reservoirs are small. When placed on production each reservoir depletes fairly quickly. Thus in order to recover most of the gas a large number of platforms and wells are required. In addition since each production well may penetrate from 2-3 up to 20 or more individual reservoirs, workovers and recompletions are rather frequent. These factors make both the cost of development and the cost of production relatively high. Reserves 6. When considering estimates of gas and liquid reserves discovered to date in the Gulf of Thailand several factors must be kept in mind. The more or less official reserves published by the Department of Mineral Resources (DMM) are primarily a compilation of the latest reserve data provided by each company operating in Thailand who have made discoveries. As such the reserves are not totally consistent or standardized in the usual manner , .e., API (American Petroleum Institute). However it should be noted that due to the distribution of the reserves In a multitude of small reservoirs without readily definable lisits, roserve calculations are based on statistical occurrence rather than measured quantities, at least prior to significant production history. This necessary approach to reserve estimation is itself at variance with API criteria which assumes a degree of measurability. In essence when statistical methods of estimation are used the distinction between proved and probable reserves is blurred, with proved reserves somewhat loss proved and probable reserves somewhat more probable than indicated by API standards. The relatively high cost associated with this gas makes reosrve estimates highly price sensitive and hence, somehat subjective. Thus the lack of standarllzed reserves in the DMR annual reports is not as serious as It may seem. 7. Using DH. data, the latest submission by Unocal, and the most recent Bongkot field reserve estimate made by DeGolyer and MacNaughton (DM), the estimated reserves of ga and condensate in Thailand are: - 60 - ANNEX4 Page 3 of 4 Offshore - Gulf of Thailand Gas Reserves (end-1990) (bef) a. Proved and Probable Gas Discovered 8,275 b. Produced 1,207 c. Remaining - Developed 3,868 Undevelopod 3,200 Subtotal Remaining 7,068 d. Posasble Additions (Discoveries not yet appraised and expected additions to proved and probable reserves) 3,738 Total Discovered and Indicated 12,013 (DMR Data) 12.318 Offshore - Gulf of Thailand Condensate Reserves (end-1990) (million bbls) a. Proved and Probable Liquid Discovered 253 b. Produced (cond. 44, oil nil) 44 c. Remaining - Developed 138 Undeveloped 71 Subtotal Remaining (cond. 194, oil 15) 209 d. Possible additions (Discoveries not yet appraised and expected additions to proved and probable reserves) (cond. 65, oil 39) 104 Total Discovered or Indicated 357 (DMR) 315 8. There is also an additional 15,000 Bcf is &:tr'buted to the non- associated gas fields located in the northern portions of the Malay Basin In Malaysian waters. - 61 - ANNEX 4 Page 4 of 4 9. Based on the above: A. reserve life at current producing rate (675 mefd) - 28 years b. reserve life at forecast producing rate ln year 2000 (1450 .efd) - 23 years co Liquid ratio to date - 36.5 bbl/wacf d. UquLd ratio ultumate (proved and probable) - 28.8 bbl/umcf *. Lquid ratio ultimate (Total indlcated) - 25.2 bbl/nmcf These indicate that: (i) production of gas from the Gulf of Thailand can comfortably be increased to about 950 - cfd based on established remaining reserves (20 year reserve life); (ii) that forecasts of production increraing to 1,450 m cfd by the end of the century are reasonable if current discoveries neet spoctations (not dependent on nev discoveries); (iLL) the proportion of liquids (condensate) declines as fields are depleted; and (iv) the possible or indicated Liquid reserves are underestimated (more likely) or these reserves contain drier gas (less liLkely). THAILAND: BONGKOT GAS TRANSMISSION PROJECT nnex 5 PRRSENT COS ?RODUCTION S CONSIPTION * _.(incffd)' PEROLEUM AUTHORITY OF THAILAND| I MONTHLY NATUnAL GAS FLOW llEPORT |. 'FATRL SUPPLY TTLt[itt 735 mmscrn (SEPTEMBER 1-30,1991) . 2L_Mmscrn ESSO I') -NPr _ _ _ _ _ _ _ M_ _ _ _ _ 7 M 9 F t Elil)li-____, r -IF SLOG CNTCIIN/OlPCU _____-_I_Ill'K__ I E:1'OIIJ ON ~~~~~~~~GAS tN...-.. ASCr-D.MMSCF GIIS IN 6SP . BUT csr *lesmrl I SOuIF 32 .F s. aCFD uiouln ueLS |sK*I . 338 254 248 233 -4; SOTUN MMSCFD MMSCr s 199. MS9CfD GiPI ASPII IIYn fteIUHBI DMII.GS USER gPn 21 -mMscroJ ItY 2 S 91 UMSCOIN r193 _""44 1---l [ ~~~~~~~~~~~~~~~fiO6 fil JHa \ CCllE / . . .~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~t..!.vmT ___ % I-- lPOPANE 1 466 6.762 TONS 644.696 00LS 3-1 .LPG , S 25.564 21,MD TINS 1311 ICC._MICIU 95 ns2 i3O Tim _..m4 INIIS3I'PLY . SIH.NGL D3, **_ 23 MMsFD 2,103 1.652 PIm CU2 3 - . 13157 - IONS 2L2 MSCFD 62 - via ETIUWE a!L._TAD *ie".co imui,uu s,w 2,285 i.1 (14 iujlu) ~~~~~~~~~~~~~~~~~PnOPANr.-..JA1..- TOP ANNEX S Page 1 Of S THAILAND BONGKOT GAS TRANSMISSION PROJECT Natural Gas Demandlsupply Profiles 1990-2005 ng or.,~~~~\'- ., Unoci S65 669 750 700 700 700 700 700 7o0 700 700 700 Smoot 0 0 0 0 ISO 200 250 250 250 250 250 250 Tl Ohhore 550 9 750 700 850 900 Ka 950 950 950 950 950 Em 0 60 6O 60 60 60 60 60 60 60 60 55 Tdal DOo_ft 550 29 760 910 960 1,010 1.010 1.010 : ,10 1,O01 1.005 Maladot- 0 0 0 0 0 0 0 0 0 0 0 0 JLA a 0 0 0 0 0 0 0 250 250 250 250 a MYW=ia 0 0 0 0 0 0 0 0 0 0 0 0 Tol Impot 0 0 0 0 0 0 0 0 250 250 250 250 uS~ ~ - A.'I7 <;0o T d Wsm w 7 4S t Fsdsock 79 132 132 132 132 147 204 204 204 204 204 204 lndslal Fud 20 59 s8 120 171 240 257 278 300 324 351 435 TOM P 10d 191 220 252 303 384 461 U2 SOS 521 655 5 % d supply SAM 276A 2 n b 40% 48§ 40% 42t 441% WIN EGAT(PotenilaI 657 792 638 956 1,174 1.290 1.397 I1.293 1.344 1,384 1.420 1.124 (CombMw-cycle) 156 394 429 550 610 610 610 610 610 610 610 662 TOrAL. ;-, 7.6 :"w 083 . .1. 747 167 16 17 1,84 1 ' 1*7 ' 170.3 . ANEX6 Page2oIS THAILAND BONGKOT GAS TRANSMISSION PROJECT Demand Profiles of Natural Gas for Feedstock and IndusrI Fuel 1990-2005 Pt.aOamudoml&P a I149 1 16 18 0 15 100 15 0 100 100 1 iOO uNh 0 S 57 55 55 57 55 aspmhom 15 15 15 is I5s Is is 1k, X 3 8@Choi & PbLuf 14 la is 20 45 so 4 sso72 79 101 Pq sy 5 C C 6 5 55 C5 CS 65 65 65 ChuuIcmlProduct 2 6 10 16 20 24 26 28 32 35 39 50 CMSUc&MCUa1CTU a 15 23 28 3 40 44 4U 53 so 64 82 -IF-ms 2 2 4 5 6 6 7 7 8 8 10 1I T _Imw 2 2 3 6 a 6 9 10 11 12 13 17 Glum 1 2 3 4 4 6 5 6 6 7 a 10 Mew - 2 9 4 5 6 7 a 8 9 10 13 Cm" a C.SSC aW lsbIS 1 5 14 28 31 32 35 36 42 47 61 es TO"s 3 4 6 9 11 12 14 15 17 18 23 album 1 1 1 23 3 3 4 4 5 5 6 TOTALINDUSTWuALviJS. A >fl ' 2 9 K a 7 t ;$taeo /7 . n ..n..rno.. S2 4 ~-Iii NO AW : ANNEXS THAILAND BONGKOT GAS TRANSMISSION PROJECT Natural Gas Allocaton 1990-2005 nwncl) Unocal 650 729 750 700 70m 700 700 700 700 700 100 700 EaksO 0 0 0 0 150 200 0 0 250 20 250 250 Tda Crbdwro 550 669 75000 850 00 950 950 250 950 250 050 Mda* O 0 0 0 0 0 0 0 0 0 0 0 Jll a O O O O O O O 250 250 250 25e0 Toalt 0nod O O O O O O O 250 250 250 250 Feedtock 79 132 132 132 132 147 204 204 204 204 204 204 kd lalFuel 29 59 es 120 171 203 196 196 300 324 951 429 ToW 106 191 220 252 303 350 400 400 504 520 555 633 % d &8"y 20A . 2n 3 39 40 40Y 40Y 4244A 50A Aval to EGAT 442 538 590 50 607 610 610 610 756 732 705 622 (Cosiiblned-cycbe) 156 394 429 550 610 610 610 610 610 610 610 622 TOT AL 5 7-9 810 7LL p910 7 960 'i.o ..M ioio s. <,, . E H X B m m X R - _W annex 7 3ON10OY GMl YRA sKIiom n3OkUC LYUUGE DSAIND PM UM!R&L 1GM 1! BUT mofd .-~ _ A i_ == a w _1 Sauth Bangkok #1-2 220OO1 66 66 0 0 0 0 0 0 0 0 0 03-5 3x30011 145 132 83 69 95 109 9B 53 34 110 81 3angpakong #1-2 255011V 190 179 179 179 179 179 179 179 179 179 179 #3-4 2x6001W 0 0 206 206 206 206 206 206 206 206 206 Worth Bangkok J1-2 75+87.51W 4S 16 16 16 16 16 16 16 16 16 16 Khanm Barge #1-2 2x75SM_ 40 40 40 40 40 40 40 40 _ 40 40 40 SUBTOAIL 'p P 486 433 524 510 536 5S0 539 494 475 5SI 522 color el= #O = 7 _ ... Marn Phong J1-2 2x300KW 40 40 80 75 75 70 70 70 70 70 70 Rayong J1-3 3x30011 96 102 105 105 105 105 105 105 lOS 105 lOS *.ngpakong J1-2 2x385.8M1 110 110 110 110 110 110 110 110 110 110 110 #3-4 2x30011 69 70 70 70 70 70 70 70 70 70 70 hanon #1-2 2x300MW 0 0 0 SO 100 100 100 100 100 100 100 Songkhla 11-3 ;3300H1 0 0 0 0 0 0 15 15 1 1 1SO SUABMtAL CCPP, 315 322 365 410 460 45 60S 605 605 605 605 D 901 -55 89 9*0 996 005 3144 @ 1099 3080 115 I1 THAILAND iONGKOT GAS TRANSMISSION PIPELINE PROJECT Annex a System Facilitles and Pipeline SCADAao S I cabm * Renovt E1s19 SteM I *New SCfDA Iu * Contl d Systm tl""Falaa a auk" Chrnbum * PI" Mdanoemn ramn System MS) I L j , ~~~~~~~~~~~~~~~~~~~~~~CUMOMfPTT' - TItdSI Sytem FWM ;1r 9~m Exludng 34- Parau P4la to n hn s Pplied Blapk FweTWinswrGSP4 AP) h CanA * 24 PVp_, 160 K . 3= sdon - j . . _ . _laPbtlms (ECP & ECPP) EM1 P1T fllsol + .^ . U~~~~~~~~~~~ INOCAL I ______.________ iT I1 Local Conitd Rloom| Now EfRP Flbcs: Now*Prr FAcIlIlle0 32@ IMM 24 Rlu * Modalion of Existing PTr * WonsvoiasPlp_ne ul Plp Tie -ha Control Panel 10106110eS (24- W VL*) P Cannol System mrEaon * Ondm Pe,le. 24 s 2 kin ReceVO 32A PigRfac_,l 24- ' Pg * 1 each 24 Branch Conneclon Ia * Sbg C K.O. Dmm TleInh ol Fui ue dopment * elIC01*0 Ukif *ad 32- Plpahe 175 Km, GaS PtpPoe t * 2701 R.ax Walef'epF * UWN HMO" Sisluu * PIs Launct ,Ie 24- *CoNdB & g *Corrosion ton 4 P1T * CorS01r;;losIon bad MidloRkifu * Caliojo Ploluclan System S *Odoantg FadE, S=ply TOMd * Fk Proteuiw Opered by PTr . nsted by Tot *SCjWA aiwacoun COfoslon MwntoAV P acIn Pltono S1*D A'reco - S SCADA & Tuluionmincallons TI Opated by TOTAL: * Cusody Tnsfe Measuremen * Gas tmy Control *I=wB Proidubiom It Thmerha Control hlu P9 * Comodoni o born 4DN aysla * SCA,A kbce *Pigin Fmcee -68 - A=N 9 Page 1 of 4 BONGQOT GAS TRANSMISSION PROJECT BONGKOT FIELD 1. The Bongkot gas field (formerly called 'B3 structure) will be the prinmry source of gas for the proposed Thailand Gas Transmission System ExpazLsion Project. This field is located ln the northwest extremity of the Malay Basin (all offshore) about 180 km southeast of the Erawan gas field (terminal of present gas pipeline). The 13 Unocal discoveries are located in the south central portion of the Pattani Trough. The Pattani Trough and the Malay Basin are simalar in most respects but are physically separated by an intervening high (horst block). About 6 Tcf has been found to date in the Pattani Trough. 2. The first exploration licenses in the Bongkot field area were granted in 1972 to Tenneco and British Petroleum. During the next several years Tenneco drilled three exploratory wells and BP drilled one. All four encountered gas and three of these in quantities indicating potential com _rciality. However, in May 1976 the remaining rights and obligations were transferred to Texas Pacific Thailand, at. al. (TP) by means of farm-in from Tenneco and BP. The first TP exploratory well was completed in November 1976 and was considered a commercial discovery (officially the discovery well). TP conducted an appraisal program over the next *ix years (1977-82) in which 18 additional exploratory wells were drilled and 3-D seismic survey covering 110 kIm was made over what was considered the heart of the field. Based on the results of the 23 wells, TP appliod for and received a Production Liconse (up to 30 years) from the DMM TP's development plan was never accepted by the DK& due to inability to reach agreemnt on a sales price formula with Texas Pacific. After protracted negotiations an agreement to buy-back the TIP Production License was reached and consumated in July 1988. The repurchase price was $100 mm. 3. The Bongkot fiold, as currently defined, is comprlsed of some 20 structured highs (14 high saLs fault closures and six renmant fold closures) and intervening saddles over an area of approximately 225 kmI (60 km along NW/SE axis and up to 10 km wide, averaging nearly 4 km). While gas reservoirs are concentrated on the hLghs, which cover about 40 percent of the total area, they are not limited to them. This is due to the stratigraphy of the sandstone reservoirs. These are large in number and consist of relatively small disconnected bodies deposited in a fluvial to shallow marine, or perhaps 1acustrine, environment, l.e. irregularly shaped channel, bar, lagoonal, or coastal deposits. The 23 wells drilled to date encountered from as little as one to as many as 26 reservoirs with as little as 6 feet to as much as 300 feet of net gas pay. A purely arithmetic average for all 23 wells results in 143 net fact of gas pay in 8.5 reservoirs per well. A total of 22 production tests were conducted (the remaining reservoirs confirmed by wire line sample tests) and nearly half of these indicated a reservoir boundary withln 500 feet of the well bore. ThLs data when coupled with the lack of electric log correlation of reservoir between wells makes it difficult to determine whether any of the 196 gas reservolrs penetrated occurred in more than one well. Therefore it can be concluded that the reservoirs are numerous, each contalns a relatively small reserve, and are lrregularly distributed and uimappable at present. - 69 - ANNEX 9 Page 2 of 4 4. In order to proceed with development, DeGolyer and MacNaughton were cousissioned to provide a reserve determination for the Bongkot field. D&M has a long established reputation as an industry leader in the area of reserve determination. They also know the rather unique situation in Gulf of Thailand fiolds as well, having made four prior reserve estimates for Bongkot and several for Unocal. Early difficulties with the original Unocal reserve estimates have honed D&W's sensitivity to the critical factors in estimating Bongkot reserves. These are: (a) in the absence of any mappable reservoir limits and the irregular distribution of a large number of reservoirs any calculation of in-place reserves must be based on statistical occurrence; (b) it was deemed that the number and placement of available well data when combined with seismic derived structure maps provided a usable and generally reliable statisti ~al sample; and (c) that the recoverable fraction of in-place reserves is cost and price sensitive, since reservoir distribution limits the reserve quantity per well, requiring a large number of platforms and wells in a diminishing returns regime for maximum recovery. After comprehonsive analysis DWH certifies 2,168.6 Bcf of recoverable gas (1,494.2 Bcf proved and 674.4 Bcf probable additional) in the Bongkot development area. DUM has excluded those reservoirs where CO2 is excessive. They anticipate that up to 18 platforms and 160 woRlls may be required to achiove the certified reserves and are estimating 55 percent recovery from 3,973 Bcf proved and probable reserves in-place. This relatively low recovery estimate (60 percent to 70 percent is normal) reflects the intensive development -equired and the economic sensitivity of reserve estimates to both cost and price. D6I has attempted to be prudently cautious in this respect. 5. The DMR awarded a Production License to the Joint Venture Group assabled to develop and produce Bongkot gas on the March 15, 1990. The Joint Venture (JV) consLsts of Petroleum Authority of Thailand Exploration and Production (PTTEP) 40 percent, Total Exploration and Production Thailand (total) 30 percent, BritLsh Gas Thailand (BG) 20 percent and Statoil Thailand (Statoil) 10 percent. The Bongkot liconse is divided into Production Areas (those areas surrounding the previously drilled gas productive wells; consistlng of 720 km1, and Reserved Exploration Areas (covering the reminder of the TP License) consisting of 2,523 kmc. Each of these areas carries its own obligations for activity and expenditure. A Development Plan must be submitted for the Production Areas within eight months (November 1990), which has been met, and a seismic program must be commenced on Reserved Exploration Areas within 24 months (March 1992), contract already signed. It is further required that three exploratory wells will be drilled prior to the end of the third year of gas production (mid-1996). 6. Immedietely following the award of the License, the JV partners entered into a participation and operating agreement. In this agreement PTT EP accepts each of the other parties as co-concessionaire in return for a proportional payment of the acquisition cost borne by the DHR in the rep%rchase of Texas Pacific rights. Total was elected Operator. The Operator undertakes the responsibility of preparing the Initial Program (Development Plan and Definitive Cost Estimate) which must be adopted unanimously after which they will be financially bound and liable. The Operator will handle all normal operations, i.e. preparation of budgets, procurement and eapenditures, and management of day- to-day operations including supervision of employees a..Gonded b other parties. The Operators activities will be authorized and monitored by a Management Committee representing all parties with a proportional vote. The development and - 70 - ANhE 9 Page 3 of 4 operating costs will be met by monthly cash calls initiated by the Operator and approved by the Kan-gement Cou.ittee. Any party(ies) may conduct sole risk operations. Sole risk operations permltted are restricted to: (a) the drilling, deepening, side-tracking or testing of an exploration or developmental well, (b) the appraisal and developmont of a previously drilled dLicovery area and the production therefrom; and (c) the installation of additional production facilities including platforms, well, etc. Parties may withdraw from the venture agrooemnt only after completion of the Initial Program. The withdrawal may be accomplished by party deeding its share proportionally to remaining parties, by placing interest in trust with the Government of Thailand as trustees, or by selling or otherwise assigning its shares to a new party providing this party is acceptable to the Government of Thailand and is willing to abide by the terms of Participation and the Operating Agreement. Except for gross negligence tho Oporator is not solely liable for any damages awarded as a consequence of the Joint venture. The Operator is obliged to carry adequate insurance and any award amounts above insurance limts will be shared by all parties proportionally. The Operator may be changed any time 95 percent of non-operating parties deem Operator to be negligent. The Operator may resign after giving six months notice providing the Initial Program has been completed. Another party to the JV may bo elected Operator should PTTEP decline to act as Operator. Ax.ter the third anniversary of gas delivery PTTEP shall have the option to become Operator after giving 24 months notice to the other parties (earliest five years after start of gas sales). It is contemplated the 24 month period would be used to provide a smooth transition from the current Operator (Total) to the new Operator (PTTEP). 7. The Develcpment Program for the Bongkot fiold is designed to produce a minimum 1500 Bcf over the life of the Gas Sales contract between the JV and PTT. Further the sales contract provides that a minimum production level of 150 - cfd shall be maintained for the first five years of production wlth subsequent minimum levels to be determined on the basis of reserves to be re- evaluated after three years of gas production. It is also stipulated that the CO2 fraction will not exceed 23 percent of pipeline gas. The actual production targets of the JV are significantly higher than the minimum required. 8. The Initial Program, as unanimously agreed, includes the following (') New 3-D seismic survey covering 573 km2 (3-D area) at a cost of $20 -; (b) Central Production and Process Platform (includes living quarters, compressors, condw'sate separation, etc.) at a cost of $219 am; (c) Three 12-slot well platforms plus plpelines to CP&P platform at a cost of $85 m; and (d) Drilling and compleing 20 producing wells (out of 36 slots available) deviated to selected target reservoirs at a cost of $59 m. The total cost estimate for the first phase of developmert is $383 -. Procurement is essentially complete and construction is underway with production start-up planned in October 1993. - 71 - A= 9 Page 4 of 4 9. The Initial Program will not be sufficient to develop the 1, 500 Bef of recoverable gas reserve called for in the Gas Sales Agreement. The Operator, is already planning a second phase of development but implementation will be somewhat dependent on first phase results. The most recent plans include three additionAl well platforms and 27 additional platform wells completed by year ond 1996. Some six appraisal wells (non-platform) will abe required -for proper platform locations. The 47 producing wells are expected to raise productive capaclty to more than 250 - cfd, the current target for 1995-96, 100 m cfd above the contract minimum. The Operator (Total) has not made any plans beyond the second phase on the assumption that PTTEP will be the Operator for any additional phases at development. 10. PTTEP with the assistance of Statoil has prepared a total development scenario for the purpose of determining economLes of the Pipeline Project. PTTEP's scenario envisions a total of 109 wells to be drilled following the Initial Program, 103 development wells and 6 appraisal wells (most likely expendable wells) on 10 adLitional platforms. This additional drilllng program is expected to cost $514 on ln 1991 constant dollars. Thus the total development is expected to require; (a) Central Productlon and Process facilities; (b) 13 well platforms; and (c) 123 development wells, at an estimated investment cost of $897 -. Related exploration activities are $55 - bringing the total JV investment to $952 -. This investment is expected to recover 1,700 Bcf as and 24 - bbl of condensate. Gas delivery at plateau production will fall between 250 - cfd (min. DCQ) and 350 - cfd (max DCQ, i.e. Daily Contract Quantity). Gas quality is expected to average 912 btu/cf. 11. The cost and volume assumptions used by PTTEP are comparable with past experLence in similar fiolds in the Gulf of Thailand (Unocal average experience in 6 fields). These include average reserve/well at 13.8 Bcf (Unocal 8 - 15 Bcf); initial producing rate of 12.5 mm cfd (Unocal 10 - 12 mmefd); rate of production decline average/well predicted is 20 percent (Unocal 20 percent), etc. Expected costs of platforms and wells are also comparable to current Unocal experience. The initial results of the new 3-D seismic survey give promise that better than expected development efficiencies can be achieved. The clarity of structure and faulting is much improved over the initial 3-D survey. Many of the gas reservoirs, both proved and prognosticated, can be identified and delineated by means of seismic amplitude anomalies. While substantiation of the seisaic data will require drilling, the seismic results support JV enthusiasm that a production plateau of 350 -m cfd can be achieved by 1999 for a duration of seven or more years. The seismic data also indicates that the earlier wells at Bongkot were located on the basis of the deeper structure (where CO2 concentrations are higher) consequently missing the better part of the shallower structure (where C0 concentrations are lower) since the structures are offset with depth, particularly the fault closures. Thus, the statistical methods used to determine reserves serves to overestimate the quantities of gas (including C02) in the deeper reservoirs and underestimate the quantities of gas (including COZ) in the shallower reservoirs. Thus the CO2 fraction way be overstated and the estimate of condensate (shallow reservoirs also richer in liquids) reserves may also be low. In view of this PTTEP has used an estimate of 912 btu/cu ft for their development scenario rather than 875-900 btu/cu t: as determined from produced samples. - 72 - Page 1 of 10 Bangkok-Erawan-Khanom Gas Transmission Pipeline-Environment Assessment Summary L _Backgroun The Petroleum Authority of Thailand (PTT) completed the construction of a natural gas pipeline and associate onshore dew point control unit from the Erawan field of UNOCAL Thailand Ltd. in the Gulf of Thailand to consumption centers on shore in 1981. In 1985, PTT completed another pipeline connection PTT's Platong platform to PTT's main system and also installed an onshore compression stati.'n near the existing gas separation plant at Rayong. Recently, PTT concluded a natural gas supply agreement with PTT Exploration and Production Co. for the supply of gas from the "B (Bongkot) structure gas field 160 kilometers south of the Erawan platform in the Gulf of Thailand. A study was conducted by Fluor Daniel in order to determine the best way in which the "Bo structure field gas can be transported to various consumption centers via existing facilities or by the addition of new facilities. The study concluded that the best way to perform this task would be the construction of a new 170 kilometer pipeline form the "Bw structure field to the Erawan platform, joining the existing system, and in addition the const.uction of a new 160 kilometer pipeline from the Erawan platform to Khanom onshore. II. The Prglect The proposed project consists a 32" diameter pipeline form the "B" field to the UNOCAL Erawan field and a second 24" pipeline from the Erawan platform to Khanom onshore. There are no structures at present in the B field, with construction of initial platforms and intra field platforms set to commence in March 1992. The "Bo field structures will be sufficiently complete to allow construction of the pipeline from the field to the Erawan platform after May 1992. The major system components of the project are summarized below: A 175 kilometer long 32" diameter submarine gas pipeline in depths varying from 270 to 210 feet connecting the Bongkot production platform with the existing Erawan compression platform (ECP). This pipeline will be able to transport up to 750 NMSCFD of gas from the *Bo field and a potential future gas field to be developed jointly by Thailand and Malaysia. - 73 - ANNEX 10 Page 2 of 10 A 165 kilometer long 24" diameter submarine gas pipeline in depths varying from 210 to 100 feet to sea level connecting the ECP with Khanom onshore. This pipeline will be able to transport up to 330 MSCFD of gas without recompression and ultimately 500 MMSCFD of gas with recompression at Erawan. A new gas/liquids handling and tie in facility at the Erawan complex, located on the existing UNOCAL platform. A new gas/liquids handling facility at Khanom near the Electricity Generating Authority of Thailand's existing Khanom powerplant. A new SCADA information system, including renovation of PTTIs existing gas pipeline control system. A new control building at the Khanom pipeline terminal for both the Bongkot to Erawan and Erawan to Khanom pipeliaes. The target date for the completion of the pipeline and associated facilities from the "B" field to the Erawan platform is June 1993, while that of the Erawan platform to Khanom and associated facilities is December 1993. III. Base line conditions The study area is focused on the offshore environmental areas where the pipelines will be laid, and the onshore area where the EGAT thermal power plant is located. A. Meteorology The project area lies between latitudes 8 and 10 N, 1,100 km north of the equator. Its climate is characterized by high temperature and humidity, with rainfall varying according to the monsoon season. Meteorological parameters summarized below were measured in stations located close to the project area: (1) Temperature: The mean maximum and minimum temperature range from 29.0 to 32.5 C and 23.5 to 26.2 C respectively. (2) Rainfall: Annual rainfall in the Khanom area is in the range of 1,600-2,000 mm. Precipitation peaks to 428 m per month in November and declines to 38 mm in February. - 74 ANNEX 10 Page 3 of 10 (3) Winds: Easterly winds are normal from May to October, with mean speeds ranging from 4.0 to 7.1 knots, and extreme gusts of 40 to 50 knots. (4) Fog: This is seldom recorded in the area but may occasionally occur in March. (5) Thunder storms: Activity peaks in May with an average of 18 days. (6) Storms: Intensity and occurrence of storm in the Gulf of Thailand range from 10 m/sec during 3 hours once a year to instantaneous gusts of 58 m/sec once in 100 years. B. OceanorraPhy (1) Waves: Height and occurrence of waves range from maximum 4 m high once a year and 11.6 m once in 100 years. Wave direction ranges from 220-270 degrees. (2) Currents: Maximum currents of both flood and ebb tides is 0.3 m/sec with flood tide setting north, and ebb tide south. C. SeismoloFg Thailand lies on a southern extension of the Eurasian seismic activity zone. The closest boundary is just offshore of the islands of Sumatra and Java, some 1,000 im from the Gulf of Thailand. The main belt of shocks is seen to run offshore from the coast of Myanmar, then approximately along the Thai border. No earthquakes of magnitude greater than 2.0 were observe in the Gulf during 1984-1987 period. It can therefore be concluded that the seismic risk along the pipeline is negligible. D. Marise water quality The distribution of water temperature and salinity in the lower western part of the Gulf of Thailand are quite similar throughout the water depth resulting from the vertical mixing of the water mass. The dissolved oxygen (DO) concentration at the surface water is greater than the bottom except for some deep areas. Observed DO concentrations were greater than 4.0 ug/l. Transparency at nearshore area are usually lower than 10 meter - 75 - ANNEX 10 Page 4 of 10 but reach 30 meter at far offshore areas. PH values are lower than 8. E. Aquatic Biology (1) Plankton: Low relative abundance of plankton was measured along the proposed pipeline route and vicinity area. About 6 species of plankton were observed. (2) Benthos: Benthos occupy the mud and muddy sand habitats. Low abundance of up to 28 species were observed. (3) Sea grass: 9 species of sea grass were found in the Gulf of Thailand. The sensitive productive area is 25 km north of the coastal pipeline route to Khanom. F. FishvXX The western coast of the Gulf from Surat Thani province to Nakhom Si Thamarat province is an important fishery resource. The distribution of juveniles have mostly densed along the nearshore coast more than for the offshore areas, due to the high fertility along the shallow coast. The planktons which some species use as food have mostly been found in the shallow area. Thai fisheries developed very rapidly after 1960, with total production increasing slx-fold between 1960 and 1970 and by a further 501 in the period 1970-77. Recently, production has fluctuated - the catch from otter trawling (of particular relevance to the pipeline) jumped about 25X from 1985 to 1986 then remained fairly static at about 1 million tons through 1988. Fishing resources are now over-exploited and associated industries such as cold storage, canning and fishmeal production are under utilized. 86X of the marine catch is from the Gulf of Thailand. Trawling accounted for 5i4 of the catch. The percentage of otter board trawling to other trawling was 821. Hence, 44X of the total catch was derived from otter board trawling. Hundreds of trawlers will operate in the vicinity sf the pipeline route at all times of the year, with only the immediate areas of the oil platforms providing some deterrent. A typical - 76 - ANNEX 10 Page 5 of 10 trawler will be 16 m long, with a 90 HP engine and operate with otter boards weighing less than 100 kg. These will therefore pose little direct risk to a surface-laid pipeline. Fish traps, comprising floating bamboo rafts moored by wire to concrete mocrings, presently extend to offshore areas as far as the "B3 field (220 km). Bottom trawling for demersal fish is illegal within 3 km of the coastline but is doubtless carried out by rogue vessels lured by the rich fishing grounds off Khanom. Smaller local vessels, including long-tailed motor boats also carry out line and rod fishing off Khanom, catching fish, shrimps and crabs. Some 200- 300 of trawler vessels may be present along the cable route, normally running at least 8-10 km from the coast. G. The mangrove forests The mangrove forests in the vicinity area of the coastal pipeline route cover 12,400 rai. The common tree species are Kong-Kang-bi-led (RhizoRhara agiculate), Kong-Kang-bi-yai (RhizoRhora mucronata), Prasak (Brumuiera gvmnorrhiza), Tualkhas (Bruguiera cylindrica), and Prong (CerioRs tagal). H. Navigation International shipping to &nd from the north part of the gulf to Singapore, Nalaysia, Australia, Persian Gulf and westwords, will cross the pipeline route at about 100 km from the shore. Domestic coastal traffic, consisting of cargo vessels, tankers, LPG carriers, passenger vessels and tugs. The average cargo vessel size is 750 DWT and the mean tanker size 1,500 DWT. Traffic in and out of the coastal ports, down the southern coast of the Gulf of Thailand, involves crossing of the pipeline route. Typical commodities traded are rubber, copra, general goods, minerals, rics and fish. I. Socio Economic Data Amphoe Khanom is located at the north of Nakhon Si Thanmarat and covers an area of 434 km2. The population counts about - 77 - Page 6 of 10 25,000 people. Most of the income in the region comes from fisheries and agriculture. J. Archaeologv The region is regarded as one of the centers of ancient art and culture in the southern regions. An archaeological site is located about 8 km from Khanom and 2 km south of the onshore pipe crossing. IV. Potential Significant Environmental Impacts and Mitigation Measures Potential significant environmental impacts of the Bongkot-Erawan- Khanom pipeline would be caused by the following: = Sea bottom disturbance - Solid and liquid wastes - Obstruction of navigation during construction - Gas composition and pollution due to potential leakage during operation - Changes in the existing socio-economic situation during construction and operation - Safety issues A. Sea Bottom Disturbance Construction of the offshore pipeline will have short term effects on marine water quality. Disturbance of the sea bottom will result in increased turbidity and suspended solids contents. This will result in a decrease in water transparency, affecting the growth of phytoplankton by reducing the light available at the seabed. Further, direct habitat destruction over the area disturbed would affect benthic organism. Indirect destruction of habitat by the increase in concentration of chemicals such as sulphides, greases and oils and phenolic compounds in the sea water in the immediate vicinity of the pipeline due to the dissolving of chemicals naturally present in the disturbed seabed sediment could also occur. However, in the former case, since phytoplankton are dominant only in the first ten meters from the surface it is expected that no significant effects will be observed in the long term. In the case of direct and indirect habitat destruction, only about 0 37 square kilometers of seabed would be subject to short term habitat destruction. Little impact on the long term quantity and characteristics of benthic life is anticipated. - 78 - ANNEX 10 Page 7 of 10 Indeed during the operation phase of the pipeline, it is expected that the pipeline surface will provide attachment points for plant species and benthic life and will provide cover for fish. B. Solid and Liguid Wastes No process related solid wastes will be generated during the operation of the pipeline. Spoil generated during the construction of the onshore facilities associated with the pipeline will be initially deposited in suitable areas at the construction sites and then eventually used foi landscaping around the construction site. Onshore spoil will be disposed of in suitable areas so as to minimize siltation effects. The spoil from the onshore pipeline excavation will be stored along the sides of the ditch and used for backfilling upon completion of pipelaying. Solid refuse from both the onshore construction sites as well as from the pipeline lay barge and the platform will be collected and disposed of onshore. Process waste water will be generated during the operation of the facilities. The primary pollutant in this water will be waste oil. The waste oils generated during platform and pipeline operations will be separated and the water treated to prevailing Thai standards (15 ppm of oil). Domestic waste water and sanitary wastes will be pretreated and discharged to the sea at B.O.D. load conforming to Thai standards. Solid wastes will be transferred to approved disposal sites onshore. C. Obstruction of Navigatio During construction, the use of a pipelaying barge which will have the pipeline suspended behind the barge, touching down on the seabed at a distance of 200 to 400 meters behind the barge will pose a iazard to navigation. Further, during construction, the suspended pipeline can potentially interfere with trawl fishing since fishing nets could get fouled on the pipeline. Both of these hazards will be mitigated by the use of appropriate warning devices and the prohibition of trawling in the area around the pipelaying barge. PTT and the government of Thailand agencies will develop a plan to implement the prohibition of trawling. Since the nearshore pipeline will be buried in a four meter deep trench, no obstruction of navigation will be caused by the pipeline. Furtler, the platforms will be equipped with appropriate navigational aids and warnings to prevent their being a hazard to navigation during pipeline operation. - 79 - ANNEX lO Page 8 of 10 D. Gas Characteristics and Potential Leakage Mercury in gas can pose an environmental hazard. The reported content of mercury from the Erawan structure is 10 ppb. The gas from the "B" structure field is expected to contain similar amounts of mercury. A mercury removal unit will be installed in the future to remove mercury from the gas if it reaches unacceptable levels. The removal unit will be an absorber which can reduce mercury levels to 0.1 microgram/m3. The used absorber will be sent back to the manufacturer for mercury reclamation. Mercury is also condensed on the production platform and accumulated until a proper way of disposal will be agreed with DMR. The mercury content and accumu_ated amounts on the platform do not coincide and shcAld be resolved by the EA consultant. Non catastrophic, short term, gas leakage will have no significant effect on marine water quality, since the gas will bubble to the surface and disperse. Catastrophic gas leakage is addressed under safety issues. E. Socio-Economic Effects The temporary increase in the population around Khanom by about 800 workers, of which 80 will be local residents, will have an impact on the quality of life in the Khanom area. Problems such as overcrowding of construction camps, life and property security problems, gambling, etcetera could result. In addition, the workers will stress the water supply, health services, and other community facilities capabilities. Transportation and navigation activities during thb construction period will probably result in an increase of transport related accidents. The impact of the additional workers will be mitigated by requiring the contractors to provide and maintain good living conditions in the construction camps as well as requiring them to seek the assistance of local authorities and police forces as necessary. The economic condition of the Khanom area will be improved by the influx of workers as well as by the employment of local labor. The influx of the workforce will lead to increased development of the commercial and service sectors such as food services and general stores for the supply of the workers needs. During operation, only a small number of PTT employees will be working at the Khanom terminal and thus are expected to have a negligible socio-economic impact. Indeed local people have been surveyed as to their attitude toward the project and in general had positive opinions about the impact of the pipeline. The effect of the pipeline on fishing productivity and livelihood of the fishermen, has still to be checked by the EA consultant. - 80 - ANNEX 10 Page 9 of 10 F. Safety Issues During construction, the occurrence of storms will have a significant impact on pipelaying activities. Tropical cyclones and typhoons normally occur in the period from September to December. Pipeline construction wil' have to be suspended during these storms. During operation, the effect of the storms on the pipeline will be comparatively minor, but production activities at related production platforms may have to be suspended. In order to minimize occupational hazards and enhance worker safety during the construetion phase, construction equipment will be kept in good repair and good working conditions will be established at the sites. Adequate safety measures will be taken and safety related equipment as well as fire fighting equipment provided in order to reduce the potential for accidents. Further, stringent safety regulations will be set and safety awareness increased by training and education of construction workers. A record will also be kept of accidents and their causes and the damage that results in order to ensure learning from past experience. Although the pipeline and associated facilities are properly designed, there is a small potential for hazardous conditions during operation such as overpressure. leaks and fire that can result in catastrophic rupture of the pipeline of damage to the platforms or onshore facilities. The potential for these events will be minimized by the adoption and implementation of proper operating and maintenance procedures as well as personnel training. Overpressure protection of the pipeline is also provided by the use of design principles for the pipeline and associated facilities that requires a design allowable operating pressure that is significantly higher than the normal operating pressure. In addition, over pressuring of the platform facilities at Bongkot and ECP as well as the onshore facility at Khanom is prevented by a design code requiring features such as active monitor/pressure regulators, high pressure alarms and shut down valves, emergency shutdown valvcs, blowdown connections and pressure safety valves. Leak detection devices will be provided and the pipelines continuously monitored in order to ensure prompt detection of unsafe conditions. Risk assessment and evaluation of the hazards associated with a catastrophic gas and condensate leakage, are still pending and should be shortly completed by the EA consultant. - 81 - ANNEX 10 Page 10 of 10 C. Other Issau No significant environmental impact is expected due to the sGismology of the site or due to the ocean currents and tides at the offshore sites. Noise pollution will occur during pipeline construction resulting from the operation of heavy equipment. Since the noise level is not anticipated to be excessive and since only the construction workforce will be exposed, noise pollution during construction is not expected to have a significant impact. V. Environmental Management and Training PTT proposes an environmental monitoring plan that will sample water quality and aquatic biology during both construction and operation. The plan will also monitor fish landing at Khanom, solid waste generation, water supply requirements and socio economic impacts. The results will be used to adjust the environmental management plan to reflect experience. The ITT Safety and Environment Subdivision of the Gas Pipeline Operation Department is directly responsible for the implementation of the pipeline environmental management plan which has been drafted by the PTT Safety and Environment Standard Division. Pipeline system personnel are trained in loss control, safety, fire control and hazardous chemical management on a regular basis. PTT realizes its responsibility for the improvement and maintenance of good working conditions, working environments and working approaches with respect to internal and international standards. Safety is paramount at PTT and will be monitored as part of the environmental management plan. Dated Dec 13, 1991 Apnex 1,1 THAILAND BONGKOT GAS TRANSMISSION PIPEUNE PROJECT Project Implementatlon Organization |. MwId Dl Ngeo Mard Ealpnmne MiftetownwcmProcfumNo r Sp lmIuinui. Cwntjow andOfhre constrxtIo 9*09_ *o d onsobConsuco cm | ,9 THAILAND Annex 1.2 BONGKOT GAS TRANSMISSION PIPEUNE PROJECT Project Schedule 1991 I 1992 1993 AcvItpDascrIpUon | ; i. 3 e~> e28 .. i. 1J M M J S N J F M A MJJ S N D MJJISIOINID AJIJ IAISIOI Ati 2. 1991 so- LIM Doc ~17, 1991 ConWrac Award Padiag b Ppelne wan1d SCADA Apr 30.1991 BIdd loCoracts bO Wdders Enrominenlal Survey-EIA Repot TOR - i I _ Data Coiecion - MadneSv i ii " System Englneebg & Pipelho Design " fr..t Ecn4edrmg & Design-SCADA, Contols - 4 D.20,191 t '99' . . Line Pipe Pucdiase Otder Bid Package - _ Un.Fh Award SCADA Land SCADA & Communcalons Contract . .as o .nta" Pipoene and FacUes Conwract Bld Packags ___.__ F C L* Pq Supply ~~~~~ ,~~~~~~~~~~~s ~~~~3# 24lPIps - Mianulackn te !o !rO P24OP ' Dlvr Plpe kr Coalti ng 32 E24 F @ Cor oslanlciele C____ C by UNOCAL Conoslon £ bIg V Plehbe a Facith sCansLucio J - a 17S Km 3210 Pkm*e. wr p * Lay 160 Kln 24* Poin by24|P>1 Stbsea Tb-kV hr naalon - ,av oimHo, e-up,ins Twan Unoca Onhore Faclsttes-Khanom . - SCADA and Control Systems kskaon flADi SI'a s£un - TbUg & Commnlsulon - _-_ _ _ _ _ - 84 - ANNEX 13 THAILA6ND BONGKOT CAS TRANSMISSION PROJECT Annual Capital Expenditures (US$ million) PY-1993 _ T-1994 Py-1995 Totol Local Foreign Total Local Foreign Total Local Fore4gn Total Local Foreign Total Civil Works 0.78 - 0.78 1.50 1.50 0.72 - 0.72 3.00 - 3.00 Lino Pipe - 20.07 20.07 - 38.60 38.60 - 18.53 18.53 - 77.20 77.20 ipe Coatinsg Jackt4ng - 6.61 6.01 - .3.10 13.10 - 6.29 6.29 - 26.20 26.20 Pipeline ConatauntAa 3.90 24.70 28.60 7.50 47.50 55.00 3.60 22.80 26.40 .15.00 95.00 110.00 TOTAL - 5.20 5.20 - 10.00 10.00 - 6.80 4.80 - 20.00 20.00 SCADA/T.loam 0.96 1.72 2.68 1.65 3.30 5.15 0.69 1.58 1.58 3.70 6.60 10.30 Rigor llat5oin - 9.86 9.68 - 19.00 19.00 - 9.12 9.12 - 38.00 38.00 ginao*arng Coaultats 0.91 2.99 3.90 1.75 5.75 7.50 0.64 2.76 3.60 3.50 11.50 15.00 HIS L.. Training 0.03 0.23 0.26 0.50 0.65 0.50 0.02 0.22 0.24 0.10 0.90 1.00 InVLroAMeatal StudV - 0.05 0.05 - 0.10 0.10 - 0.05 0.05 - 0.20 0.20 ipali- Rtudy 0.05 0.67 0.52 0.1 0.90 1.00 0.05 0.43 0.48 0.20 1.80 2.00 axeo and Duties 3.36 5 3.38 6.5 - 6.50 0.1 2 3.12 13.00 - 13.00 Bass Cost 72.12 j, UJ 1 3 JJ7 1fts7-95 9.2 ft Ij M30 277.40 A315.S lh7xical Cantinsgnc 0.81 5.77 6.56 1.55 11.10 12.65 0.74 5.33 6.07 3.1n 22.20 25.30 Price Coantagemcy 0.21 1.56 1.77 0.40 3.00 3.40 0.39 1.66 1.63 0.80 6.00 6.60 f U L IRD5MCT:COS 110l3 Z9LU 90.482 ZL2I 152.S0 174.00 ILU ZLJA &;-U 2.A4 30LS-60 34LMaO - 85 - Annex IULND Bong&ot Gas Transmission Project Estimated Disbursement Schedule (US Million) IBRD Fiscal year Estimated Dsbunrsement Pipeline Subsector and Semester Semester Curnmulative Profile 1993 December31, 1992 52.0 S50 3.0 June30, 1993 22.0 75.0 10.0 1994 December31, 1993 16.0 91.0 27.0 June30, 1994 'r.u 96.0 40.0 December31, 1994 9.0 105.0 48.0 June 30, 1995 67.0 December31, 1995 82.0 June30, 1996 95.0 1997 December31, 1996 103.0 June30, 1997 105.0 - 86 - ann 16 ,UARND PSOTMRAS PROEC ISCAL YEAR 1966 1967 16 i9o 1910 a" 37873 3754 40559 44U78 562 Ow rRevue 705 1013 M M 1205 Tatmi ft=mmm m m ii az Coo 3230 33M 34725 39570 4427 Sak Ewwe 4O 405 452 480 634 M.M p_FhI 1396 1066 1269 1250 2264 ODwSpe_ 43 40 34 35 386 WprealaUu_ 1124 1003 1173 1271 136o RSAIBSUIGStote Go_vemnt ON m 675 6 1161 MOLO_hrti kwo P_~~~~ M___li h130 1264 1200 1382 1266 Lome kron Forwign EOi_e 406 362 674 415 400 TIW Non Opwadn2 _ UX Zg 2074 Not Income Z m Za 1411 Avrage Aimal Rm"ud NP Fked AMe 20=57 2123 224 236 261 FOReof rumn) 11 11 14 11 13 Operng RaOO) 94 94 93 e5 6 - 87 - TIULND Armex 15 QOKOA GAS ANSMISSION PROJWr Pa2 od 3 Poes Fnandal Pwfr rms ,funda Flow 81tmnwt (mm uuon) FISCALYEAR l96 1987 1988 l 1990 SOURtCES Of FUNDS Intemp] CahGwt opwadnobvmw 2224 2394 3039 250 3106 Non-Cash tes 31 266 2827 2520 2744 Total internal CerArshm l_n 1 AM la C4PiW Cntr oaw 1 7 23 0a 935 Long-Turm Loas Rced lb 0 0 2847 4522 0 Depost 0 6 0 563 0 Da dpoaslof Pbged Ammi 3 2 1- 1 1 Other Lan RepAYMent 31 0 0 2 0 TOTAL SOURCES OF FUNDS 1 08 S APPLICATION OF FUNOS CatW _endRure 2012 1539 3392 2775 5719 Long Trnm Loan P4p3a"nalb 194 1049 3545 4061 126 Interm 1290 1284 120 1382 loop l tal Debtn8 14U 4748 1412 RefundableDepo it 0 39 734 0 112 Other LbIbUIt 0 0 0 109 4 Total US" of Fud 724Z Ince In Non-cai WodnAg Capi 906 1499 2W5 064 -511 Increa In Cash es moainei In 8ic Omrdrafts 1726 -342 -3120 561 48 Iner_w In ToUM WXdMno Ct_ 1t5T , TOrAL APPUCAIION OF FUNDS j Mn Capit Egpndle (3 Years aveae) 2B34 2314 2569 3869 3869 Det SeNic Coverag - tiOme 4.1 2.2 1.2 0 4.1 Sel-Financing Raio(%) ha lb NA WA -73 -3S 128 Ia - Internal Cah gewaton l non-cash wordng capWim deb 5k Wed a a pucntae of _de yeas averae Caa pclditure lb - Company records do not brak out lngourm nbuo rceived and repaid In 1966 Bnd 1987, but rathe rel a nat amount AccdnSgly. a sel-fn to tor tl° yrn s cannot be prperly calulated - 88 - TDMIAND ANNEX 15 ,Pgs 3Fas FISCAL YEAR 1986 1967 Im 1989 1990 MIM Cam am2 2S6 137 29 152 Shart-Tom Invegronts 50 0 0 0 0 Auounts RuAble - Trade (Nu 48 482 7m 6541 8336 NWue|R@culi w796 905 1032 1200 2020 bwdodei 106I 1532 1610 1777 2067 _Mi aid Su 250 S2 64 775 m7 Obtr CuOrut AsaW 2205 231M 3130 309 4404 LWn-Twm Im _uIO 1?97 2211 27 3118 49 Rope". PMI ad oEu Ne) 21001 21536 234 21109 23728 Constuedo Vork I Progrih s 533 915 513 964 3384 Toatl FbPed atM Zi MS4M 2m2t Ower AU 220 197 917 311 394 TOTAL AgS M 4 LIADUTIES AND EOtUY Bank Owvdrail 10 0 69 250 95 Accfunt Paabe Trade 2361 2446 2233 3135 47e9 Ottw Accownt a ylW 963 1197 620 1270 3149 Accrued r heI- 1567 1339 2047 1427 514 S&or-Tem LoNs 624 1239 658 464 246 fur Coumnt" Ubile 1471 1624 1344 1S22 3329 Long-TerM ULwow Long-ToM LcWN 10404 l1616 16263 16320 16302 Other Long-TomnLbOW"to 565 313 1n2 11 7 Totid ama im amu am am mounry G _oem Conbuio 2411 2418 2441 2506 343 Retand Emlng 7764 648'; 947 10152 11563 Revaaton Surpks 4438 6045 )16 8801 9903 Foreign E_mn Lsme (3250 (3582 (31C7) (3193 (28) Total E:ulht 1 tm3 1m aims 22 0m TOTAL 6LWM ND-EQUITY flE 2I _4M M Long Term Dow t dofamt INWUtY 59 55 50 47 43 CurrWRaoo0m)n . 1.7 1.6 1.6 1.8 1.5 - 89 - Ann 16 Pace I of 7 Prr. RkuW PMGon (Bh Mllbn) FISCAL YEAR 191 192 193 1994 1S99 1996 Ra-u Sa"es 76279 78860 SE104 103858 124733 136938 Ote Renue 1078 1N85 ag 898 96 387 Total Rmuo MU 5 MS MM 104-I' 12569 139925 Opwtlna Ex_ Cd of sale 66775 6M076 77446 91347 110000 122406 Se"lng Epmes 843 92 976 1056 1144 1231 Adiliralve _inpenee 2194 2367 2859 3330 3795 4262 other Bpeneu 26 11 14 14 14 14 Deselsi*on 1566 1496 1568 2284 2557 2803 ,emittance toth Omovernmet 2085 1801 1560 1476 1896 2463 ToW Cker Ona-Emnses nn n 7A28 MU 119-4r 133178 Nzl CbH"afina Incom2 - 5f 429 7 A2 67f4 No-:wafna E _one MfZtwe ExpwN 1206 1245 2207 3063 3508 3151 Losse F.wm Foren Exchng 407 364 237 269 175 133 Total lion Oo"lna LU =_4 M 0 X 3 J Ne Incme 21 297 34 Average Annual RPvalued Fbod Aut 2544 223 28171 34682 40693 50870 Rast o Ratum f) 13 16 16 1S 15 13 Opwating Raio(%) 94 96 96 96 96 96 - 90 - Anne 16 Pags2of 7 ll4AIUANQ KONKO OAS M1MISSON PROJECr PrrTs Flnandal Prdreons Funds Flow rnomrn FISCAL YEAR 1991 1992 1993 1994 199 16 8011RCES OF RJN08 ,*rnal Cash 020non qwae ho h m 468 4282 4571 S24 62S0 6748 D _rcaon 1566 1496 1568 2284 2597 2803 Dehfered C 26 11 14 14 14 14 Othelt"m notlnvomn cash 1831 467 67 1116 2607 1594 ToW ltwna go Gn2Mml ml m~ m "'so15 Long-Term Lam 0 5321 10073 14390 10346 4233 OteW UabuU 1 0 0 0 0 0 Surplus From Contrlbutors '18 0 0 0 0 0 OhwAsets 121 -50 0 0 0 gv L8CiOF tJNOS 11S27 JM 235 22014 aim APPCATION OF FtUNO8 Inca_elnFkedAsdt 2824 91 9190 13823 10897 6014 _nvstmel In SubIda and Afl_lat 269 3030 2807 3902 2380 316 TotalCaoftm nvowesmn t31 21 197 t75 12r 5 Fepaymwfent Long Tem Loans 770 699 426 1627 3325 2635 Loanto PrEc 52 52 52 52 52 0 Intrest Expens 1206 1245 2207 3063 3508 3151 ToI tt9bri o Own 199 im 4742 flft Total Ues" OFunds 5141 tl977 L4M W 12M 121 InnceInnNL.CasIh VWoedng Capital -1341 2169 1387 338 1716 1661 Icreasse In Cash les Inre in Oak Ovedraft 4801 -2619 224 248 136 1616 Inc In Total Worldno a oak_ i iSol M m go52 TOTAL APPLJCATON OF FUNOS 2 305 11W 1M &M m I=2 Captale Exedre (3 yea average) 627 8364 13234 14333 12444 9804 Debt Service Cove (Umes 4.1 3.1 2.3 1.8 1.7 1.9 SeI-fncinq RtUo(%)Ja 121 25 16 25 25 38 la - Intena cash generton lss non-cash wridnog capl Im d btsvicespessed as a perentage of thrse ye avrage capita spenditure ANNEX 16 - 91 - PageSof7 TAIWLAD Q" 318w0 PROJEt:r B a ShM fl8ALYEMR 199a m ) 1993 1994 19 19-6 ASETS Cuh 49 2239 2463 2709 284S 4461 Accounts Receivable (Trde) 6612 9413 9692 11306 13424 14739 Accounts Rable (PTEP.) 1813 1484 741 690 1275 1275 luwdm1m 3977 3292 5063 5991 66 8150 OtheCuuWCAse 3334 434 4697 599 502 6147 Totl CMnAono m 2iM am amn maz am wlobvwft In Su_skladn and Afll 527 6306 li1S 15017 17396 17713 Pperty. Piant NW Equipmet 27201 26644 2969 39 41720 MM020 ConasuWourkIn Progm 777 61 10544 11703 17418 1735 OtherAss 273 311 298 284 270 256 TOTAL ASS9EM un Z.4S01 82US IMZ2f 114496 LSARILMN1PAD EOUITY Current U&bMWin Bank Overdraft s 0 0 0 0 0 Accout Payable. Trade Local 3589 4472 5060 6180 62 7631 : Foren 594 1472 1000 1509 1954 1907 Accrued Interee 575 249 564 1C59 1419 1154 Accuud ReenutoTresusy 2157 1601 1S50 1476 1696 246 Oter Current ULbl_ 4390 3S0 4212 4536 4662 5253 TO UNUONSM 1M 1M0 14M 760 Long-Tm UsbIl_es Longi-Term Loans (Net) 15273 19895 29542 42304 493 50923 LonTerm Loans W PTIEP(N 207 155 103 52 0 0 Total LooTor Lon 0Nf im a A M A Ote Liabilities 8 8 6 a a 6 TOrAL LRLBLMES 21B* 1#1f 4204 li=4 I=8 J=5S Eoi Government ContrIbuto 3291 3291 3291 3291 3291 3291 surplus from C*ontRb 336 336 336 336 336 336 RPtad Eamkg Approprleted 7466 7486 7486 7466 7466 7466 _napproprIated 7352 10034 1216 14078 16646 2110 Patok1 Surplus 11493 11541 11202 11906 14181 15182 Foregn Exo g Losses f08 m- 2 im IM Iobl Elty - -2 M _40 449S7 TOALUADLIAMESAM EOUlffY MEM 74501 MOI 1104 Debt as% ofdeandequlty 38 40 48 55 55 u3 Current raUo (OM) 1.8 1.7 1.8 1.7 1.e 1.9 - 92 - AM 16 Page 4 of 7 BONOKOT GAS TRANSMIBSSION PROJECT pT?'. Financial Proleetions Revenus 1. Revenues from Oil nd Oil Products were projectod as follows: (a) Petroleum products uales volume was projected product by product (e.g. , for premium gasoline, regular gasoline, kerosene, high spoed di-sol, low speed diosel, fuel oil etc.). These projections are included in the project file. Essentially petroleum product iL projected to increase on average approxinately 14X per annum over the next five years. Annual totals in million liters are shown below. ya r 1992 1993 1994 | 1995 1996 H I Petroleum Product Sales VolUm (UK liters) 8208 10470 11651 13153 13637 (b) Price projections were also made on an individual product basis, and are lncluded in the project file. However, generally fluctuations from 1991 prLec levels relate to the projected prices of crude oil per barrel, which are as follows (ln 1991 dollars). Year Prelo p cr $1 $. $1 1 18 - barrel of crude $17.30 $16.00 $16.31 $16.60 $17.30 $18.00 - 93 - AM1 Page 5 of 7 2. Revenues of Natural Gas and By-products are projected as follows: (a) Gas flow in Milion Cubic Feet per Day (MMCFD) is estimated as shown below. m ~~~~~ m Year 1992 1993 199' 1995 1996 GALS FLW(MMCFDI UNOCAL I 230 230 230 230 230 UNOCAL II 368 368 305 258 240 UNOCAL III. & IV 139 152 165 212 230 BONGKOT 150 200 210 JDA ESSO 60 60 60 60 60 TOTAL i 797 | 810 j 910 j 960 970 (b) The selling price of gas to EGAT in Baht per million BTU (MHBTU) is expected to be 69 Baht per MOBTU for existLng gas flows, and 80 Baht per MHBTU for the Bongkot Pipeline gas, begimning in 1994. 3. The price of natural gas is given below. Year 1992 1993 1994 1995 1996 NATURAL GAS PRICE UNOCAL I 54 46 47 49 51 UNOCAL II 50 50 52 54 56 T. III & IV 59 61 63 54 56 BONGKOT 55 57 60 JD ESSO 34 37 45 48 54 4. In the cascs of imported oil, the cost of sales includes various import expenses such as custom duties, import duties, surveyors" fees, and contributions to Oil Stabilization Fund. - 94 - ANNEX 6 Page 6 of 7 5. Inflation factons are proj cted throughout the five year period at the rate of 7X per armum for selling and administrative expenses. 6. Depreciation is calculated by using the straight line method over the ostimated useful life f the asset, at the following rates: ASSETS RATE Products Extractlon Plant Group 6.67X Transmission Plant Group 4.OOZ Gas Plant Group 6.67Z Genoral Plant and Other Property Buildings and Improveant 3s33X Tools, Equipments and Other Proporty 10.001 Railroad Transportation Equipment 6.67X Transportation Equipment 20.00X Computer System & Peripherals 15.001 to 20.001 7. Remittance to the Government is expected to remain at 35s of net income throughout th proj-ction period (calculated on net income based on book value -- not revalued asset -- depreciation). 8. Foreign Exchange Losses are an amortization of the balance of tbh deferred losses from devaluation of the Baht against foreign currencies. The balance of deferred losses on exchange from conversion of outatanding foreign loans as of September 30, 1991 mounted to Baht 2,605.9 million. The projections assume that the current exchange rates of the baht into all currencies (including both the dollar and the yen) will remain constant. Accordingly, if the baht in fact weakens against the yen (it is less likely to move dramatically agalnst the dollar since it is tied to the dollar), then the foreign exchange loss could be understated (ard net income correspondingly overstated). Conversely, a strengthening of the baht against the yen would provide an increase to PTT's net income. C_nital Tvewstmen 9. Detail regarding PTT's proposed capital investment ±.s given b-low. - 95 - gX 16 Page 7 of 7 tfaht Million) FISCAL MmS 1992 19*3 1994 1995 1996 A. PRO= IDVZSSNHJ 1. Ga Plat Project tUMt III (Rayem) 50 500 1475 1475 2. Gas Plnct Pojeot UnRit IV ohnam) 175 412 924 489 3. lafrigszatd Senk Co.ssumtima 200 4. Pows Plant - Co. Gezsation 200 250 5. 2id Otffhoe Pipeline 52 1300 7600 5200 1408 6. JnA Pzoject 78 312 7 DUomkot Gba lranainison Pipalin 3020 4333 2546 212 741 8. 3 1227 tp.lina 100 315 258 193 10. Jthmsvaksm Oil Depntt s0 190 360 ?O?AL ~f TrW ~ U nIr Mm nu ian S. INYUDT IX UUSZDA*5 AND A111L1A 3030 2807 3902 2381 315 C. OGin LOW =1 1 ZUYUUIU 3424 2645 1546 2824 1886 TOIAL CAPITAL flWfl? fl32 11997 17725 13277 I=3 Accounts Receivable 10. Trade Accounts Receivable are projected to range between 39 and 43 days of sales throughout the projected period. Acputs Payabl 1I. Trade Accounts Payable are projected to range between 29 and 31 days of Cost of Goods Sold. orr1ncs 12. PTT's sources of foreign borrowings are expected to be the Bank (with its 17 year term, 5 year grace period, and, interest rate of approxiuately 72), the Overseas Economic Cooperation Fund of Japan (with a 30 year term, 10 years of grace, and 2.51 interest rate), the Japan Export- Import Bank (with a 15 year term, 5 years of grace and approximately 7S interest rate), and forolgn coercial banks (typically with 10 year terms, 2 years of grace, and pricing at approximately LIBOR). 13. PTT expects to raise funds locally by issuing bonds and by borrowing from local comuerciLal banks, both of which sources typically give loans of 5 to 10 years with an interest rate of approximately 11. - 96 - Annuul7 THALAND aONTM GAS TRNSMISSION PfOEM Pw ra CIDISI mmS m (Sam Mi an) FISCALYEAR 1992 1993 1994 1996 1996 A. PROJECT INVEfrMENr 1. GaM PaPJectUritUHiao ) s0 Soo00 1476 1475 2. G Plant rt Unt IVQhmm) 175 412 924 489 3* ReMgae Tank C _anuln 200 4. Powe Pln - Co. Geneadon 200 250 5. 2ndOlft eline 52 1300 7800 5200 1408 8. JDA ct i7 312 7. Bonokot Ga Tranmhnion PeIn 3020 4333 2048 212 741 a B212J27 Pie 100 315 258 193 10. IOilD 80 190 360 TOTAL PROJECT IN 6U6 IZ2m 4129 B. NVESTMENT IN SUBSDARES AND AFFIAUTES 3030 2807 3902 2381 315 C OTHER LONGI-TER NVESTMENTS 3424 2 1546 2824 1886 TOTALWCAIYTAL leM1ENT I J a 'Numbers Include conUngencies, due Nad toces -97 - Annex 18 Page I of 4 BONGKOT GAS TRANSMISSION PROJECT Economic and Financial Analysis- Assumotions Economic Analvsis 1. The capital cost for development and production of the Bongkot field is based on the estimated costc for drilling 123 wells, installing 13 well-platforms and a central production and process.ing platform, and the cost for related exploration activities. The total capital cost is the estimated investment needed to produce 1,500 bcf of gas and 24 million barrel of condensate. The operating costs associated with the estimated investment cost is based on the required fixed and variable costs, including the work-over and re-completion of the wells. 2. The pipeline capital cost includes the Project base cost (except taxes and duties) and the physical contingency. The pipeline operating cost is assumed to be 3 percent of the capital cos:. 3. The annual quantity of gas supply is basid on minimum daily contractual quantity delivered by the joint-venture ga- producers to PTT. The average calorific value of the gas is assumed to I-- 000 btu per cubic feet. The annual prodtction of condensate is proportio.. _o minimum daily contractual quantity of gas supply. 4. The price of crude oil is based on Bank projection. The price of condensate is assumed to be US$1.00 less than the price of Bank-projected crude, due to possible penalty imposed by some refiners on the condensate. The FOB price of fuel oil is assumed to be 80 percent of the price of B&nk- projected crude oil. The CIF price of the fuel oil is assumed to be US$2 more than the FOB price of the fuel oil, to cover the cost of ocean freight, insurance and losses. 5. The gas net-back value is based on the economic value of gas used in a combined-cycle power plant. This takes into account not only the energy cost of the alternative fuel (i.e., the fuel oil used in a thermal power plant), but also differential in equipment efficiency (i.e., differential in efficiency of a gas-based combined-cycle and fuel-oil-based power plant). 6. The combined-cycle power plant considered for. the purpose of these analyses is the proposed plant at Khanom, 600 MW capacity, estimated to cost US$815 per Kwh ( based on actual bids received by EGAT). It is assumed to have operating costs of US cents 0.6 per kwh, a plant factor of 751, efficiency of 46X, a construction time of 3 years, and a life of 20 years. 7. The fuel oil-based power plant is assumed to have a plant factor of 65X, efficiency of 39Z, capital cost of US$1,100 per Kwh, operating cost - 98 - Page 2 of 4 of US ceonts 0.5 per Kwh, a construction tin, of 4 years, and a life of 25 years. Financial AnalAsIXS 8. The capital cost of the plpcllne for the purpose of finLneial analysLs L. ssumed to be the Projoct base cost ineludlng taxes and duties and the physieal contingency. The operating cost is assumed to be 3X of the capital cost. 9. The purchase price of gas is calculated using the gas price formula provided in the Gas Sale Agreement singed between PTT and the joLnt-venture gas producers. The gS solling price is calculated using the price formula provided ln the Gas Sale Agreement singed betweon PTT and the EGAT. ANNEX 18 Page 3 of 4 bm ql Read R _a. __ _ ___ _ _ P_d. PmWod. TOMl PJndd. PL be Gland T71 aI Cr;a G" Un VuO GuBee 1 Gan Not es I To. Nu caPa oP.. cap. o . wPILEm PaL.e cp.&oplef. codw - ..... d N*ack COW. 8ia Bons own. ¢am Boha Ye cn o God cop co o!Lcad Cad___ .!2Lr!6, 4r owl Ie ow ...."? Omnii~i .! .i- I-%&C4Ind. 5mm. 1660 14.10 L0 17A _ _ 0.00 UA.O0 - _ _ _ _ -17.01 0SAO .0o0 -17.0 1961 114Jo 1OAO 135.6S _ _ 0.00 13.o - _ _ _ _ -125.'.. U._2 CAo -125.60 196 1.0 A1.60 370 6806 8_ 81.78 - - _ _ _ 410 , 000 0no 410. 160 111A0 81.10 16.70 185 - 138 32 - - -4 7 0.0 0.G 4-6w7 t164 4A.4 4.70 64.1o0 78.2 9.90 U.48 1728 64.00 1.00 4.14 15.6 364. 626 1A3 230A6 1062 196 U620 .80 138.70 - .96 O0. 148.6 62.60 125 4.14 16.36 141.66 1S91. 20.46 02.00 23.4 1o6 47.60 626 160.10 - 9.90 6.S 110.06 66.10 126 4.14 17*3 A7. 2817.7 21.64 419*6 JO332 1t97 12.8 66.8 6 0.30 - 9.66 0 .90 76* 1OU.0 1.o 4.14 -16.10 GM 374.07 27.16 430.48 40122 m 94.60 66.50 161.10 - 6.G 0.96 1t1.0 0915 1.60 4.14 19.03 7.7n 216.72 25. 400.32 246. lw 630 UJ0 111J0 - 0. Om ' 121.76 e1.6 1.75 4.14 20.02 877.78 26.2 360 412.1 201*s 200 1t.Jo U.00 e.60 - 0.6 S.6 70.76 61.26 1.76 4.14 21.6 #77.7 266.02 368-4 414.61 33465 2001 2.60 U.00 120.30 - 0.06 06 130.76 01.25 1.76 4.14 20.70 377.78 2472 3O. 414.16 28340 2002 40.10 6.00 6.10 - 0am 108G0L 916 1.76 4.14 20.61 Sml.78 2072 3W7 413J64 s07n 2003 8.30 680 6O - P." 9.6 7.2 01.26 1.75 4.14 20.S 377.78 3042 6s. 413M 340.09 2004 00.70 67.60 88.20 - 0.06 0.0 9618 61.s6 1.76 4.14 20.10 17r.7 279.61 3S6.U 412.6 314.76 2005 58.10 67.60 06.60 - 0.96 0m 106.66 01S. 1.7 4.14 18 37.78 722 34SI 412.66 W7S 200m - 87J0 0.60 - 0m 9.9 67.40 021.6 1.76 4.14 19.01 m77.7n 310.32 34J4 412.62 1416 2007 - 51J0 61J0 - 9.C0 O.o 61.40 61.26 1.50 4.14 19.#2 m7.7n 310.32 27J4 407WAS S320 I0U - 0 10 4.10 - 90.6 96 8348 01.J 1.00 4.14 19.91 m.7n 324.S2 60A 07. 344.23 me6 - =80 32.60 - 0691t O0. 42.4 61* 0.80 4.14 1902 377.78 336.32 0BA6 37. 74 46.2 201t _ 2020.0 00.00 _ .06 0.90 2.06 *1.25 0.60 4.14 t 1U.l 277.7 472 .66 337.72 867.7t TOTAL 062.50 0780 1627.80 7.14 160J2 406.48 24t 1830.6 24.00 636.77 044. 46.F.. 6370 4412.83 NlV 40694 3062 66L.1 d6 46.07 204.11 1t0l 402J4 1 729 THAIND ANNEX 18 BONGKOTTRANSMISSION an PRO Page 4 ot FINANCAL ANALYSIS.1991 aeonst4 olbr FInancIl Rate of Retun Purchase Price Vdume of Gas Purchase Pipeline Cap. Operating Total Gas Gas Selling olGas GasSold Cost Cost Fin.) Cost(Fln.) Cost(Fin.) Price NetBeneit ($IMCF) (BCF) (S million) (S milnon) (S millbn) (S million) ($ miion) (S milNon) 1991 - - 1992 - - - 68.71 - 88.71 - -8871 1993 - - - 170.60 - 170.60 - -170.60 1994 1.87 64.00 119.82 81.89 9.96 211.67 171.02 -40.65 1995 1.93 8260 159.18 - 9.96 169.14 225.18 56.04 1996 2.03 96.10 194.65 - 9.96 204.61 271.53 66.92 1997 2.12 109.50 232.39 - 9.96 242.35 319.99 77.64 1998 2.23 91.25 203.13 - 9.96 213.09 276.13 63.04 1999 2.34 91.25 213.14 - 9.6 223.10 286.14 63.04 2000 2.45 9-.25 223.55 - 9.96 233.51 296.55 63.04 2001 2.15 91.25 196.41 - 9.96 206.37 269.41 63.04 2002 2.16 91.25 196.91 - 9.6 206.87 269.91 63.04 2003 2.16 91.25 196.95 - 9.96 206.91 269.95 63.04 2004 2.16 91.25 197.30 - 9.96 207.26 270.30 63S04 2005 2.17 91.25 197.95 - 9.96 207.91 270.95 63.04 2006 2.18 91.25 199.34 - 9.96 209.30 272.34 63.04 0 2007 2.20 91.25 200.91 - 9.96 210.87 273.91 63.04 2008 2.22 91.25 202.45 - 9.96 212.41 275.45 63.04 2009 2.24 91.25 204.13 - 9.96 214.C9 277.13 63.04 2010 2.25 91.25 205.71 - 9.96 215.67 278.71 63.04 Total 153835 3343.92 341.20 169.32 3854.44 4574.60 720.16 -101- BONGKOT GAS TRARSSTrON PIOJXCT Selected Documnts and Data Available in the Project File 1.. Gasis Agreeamnt between PTT and jont-venture Ss producers 2 Can Sals Agreemnt between PTT and WAT 3. PartLcipation and Operating Agreemnt 4. Concession Agrement 5. Enviromental Assessment Report 6. GAT Seven-year Power Development klan 7. Engineering Conultancy ServLce Contract S. lid Documents - supply of 1lie plpe 9. Draft Contract - supply of line pipe 10. Gas Naster Plan Study THAILAND GAS TRANSMISSION EXPANSION PRWECT PETROLEUM AUTHORITY OF THAILAND Organizalon Chart mm OIR OfEFI WW OFF OFT _-- MM" P&WYNO I4En$O HFSUIL E8E FUCEPX PLN&Nm I~~~~~~ , WUNRESOURCE8~BUDO bo N^HCE& _f rOSWM L w _K PETLROEPJL9 rn~~~u m . . ea .. -ms I *13 rPROCUUT LIZL] U- MAP SECTION IBRD 2341 1 CHINA,, ,- ' . . ~~100° 102° 104 MYANMAR *'L_ ; THAILAND BONGKOT GAS TRANSMISSION PROJECT ' it ,REP._ >.s 14' PROPOSED PIPELINE ROUTES AND OFFSHORE PLATFORMS ~/ \ ,iTHAIIAND *, >BANGKOK FUTURE PROPOSED EXISTING /\. **-;' 6s * - - GAS PIPELINES A IUD . A TERMINALS ARFABD 9 . * PLATFORMS OF Z f Gusf _1 _,< \ Chonburi ) / POWER PLANTS MAP/ aF "I GAS FILDS )^> LZ j 9 \DISPUTED AREA MAiA1Saft i Rayon - - INTERNATIONAl BOUNDARIE 98°A IA . Saf // i1 Gulf a Thailand 12 /ip 'j°/"KhThahpn CAMBODIA &S *-ci C'~~~~~J -100 gf SuratThani0 EGAT 0) 160 KI( E R A W iI Phangngo ump/on \ Krabi NkoSOj If !~~~~~~D & 1\ a PLANT M LASI 10 SurcFtThanio EGAT 160 KAA EPA A ~ ~ ~ ~ ~ ~ ~ ~ MRCH199 Nakho SiNrdiaC s w^^n i & i ~~~raI I TI t,'mor\ t i S y (* r \'sPotth l IATFOR 98e 100s i MA~~00 Noathiwat 12 = 4~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~h ,o I YI Is . 0 40 80 120 160 MO yho &n.,q~~~~~~~~~~~~~~~~..d 60CH199 IBRD 23519 :,CHINAw. I. oooe14 MYANMAR;-t-B THAILAND ,¢sV ' 'fsEt.S BONGKOT GAS TRANSMISSION PROJECT , -XI@Es,_ '> _14' GULF OF THAIllAND - GAS FIELDS 1 - \ THAILAND '.f BlV AGKK, ASIN OUTLINES . \; " . . _t * 4 P , ~~~~~~~~~~~~~~~~GAS DISCOVERIES I td BD GAS FIELDS AR& ,X 'f/' Of r Go.lf <._ MAP S f ond |/ ? ; , . _ ~~~~~~~~~~~~INTERNATIONAL SOUNIARIES o + **^)\ \ i O ~~~~~~ ~ ~~~~~~Rayong ° AO B0 120 160 200 1 9 _ ___ ) SaX p - . N~~~~~~~~~~~~~~~~lLCMETERS b,ftefX 0 7 > ~~~~~~~~(,;,L)f of ThailondC .21 t~ 7 MYANMAR l 'i - #7hw*^,,. 1 vrw WJ /4~Kirl Khan CAMBODIA 1 ,0 j { O / 50 GKHIA! TROUGHw .Zt j43 X J 1050m ),SurutThoniO 10 2 N ~ ~~~~~ ~ \0 6 \ ; ~~~~Pagn9 Noko Si 13. 0\ Nuliyds > Trn Part uSg 2 ' 0 AMA OFfSiORPAlT E A \ 2-la* 11T *\A 54*"x@n MALAY BASIN 7-J&wn 0y W'/ \,v ' 8 a3 > ~~~~~~~~~~~~~~~~~NorathiwatO \ / s 0 O OFFSHORE MAIY Q ,v~^\ 4-J12Sotw "Wv\0 S-U 9-Dt ' " e ' 012 07 i43k 9Dawt r ' \ S440r 12-Tuh 100 hAALYSIA 12\< _ . g ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~FEBPUARY I9v