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Document of

The World Bank

FOR OFFICIAL USE ONLY

MICROF'ICHE COPYMICROFICHE 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 DivisionCountry Department IEast Asia and Pacific Region

This document has a restricted distribution and may be used by recipients only in the performance oftheir official duties. Its contents may not otherwise be disclosed without World Bank authorization.

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CURRENCY EOUIVALENTS(As of December 15, 1991)

Currency Unit - Baht (B)US$1.0 - B 25.52B 100 US$3.92

UNITS AND EOUIVALENTS

bbl barrelbcEf billion cubic feetbpd barrels per daybtu British thermal unitCWh gigawatt hourskcal kilocalorieKWh kilowatt-hourkoe kilogram oil equivalentkm kilometerlb poundmcf thousand cubic feetmmbtu million British thermal unitmmcfd million standard cubic feet per dayMW megawattppm parts per milliontcf trillion cubic feettoe tons of oil equivalenttonne metric ton (- 2,205 lb)

ABBREVIATIONS AND ACRONYMS

ADB Asian Development BankCNG Compressed Natural GascO Carbon monoxide

CO2 Carbon dioxideDMR Department of Mineral ResourcesEA Environmental AssessmentECCT Energy Conservation Center of ThailandEGAT Electricity Generating Authority of ThailandJDA Joint Development AreaJEXIM Japan Exim BankLNG Liquified Natural GasLPG Liquified Petroleum GasMIS Management Information SystemMOF Ministry of FinanceNEA National Energy AdministrationNEB National Environmental BoardNEPC National Energy Policy CommitteeNEPO National Energy Policy OfficeNESDB National Economic and Social Development BoardPTT Petroleum Authority of ThailandPTTEP PTT Exploration and Production Co. Ltd.SCADA Supervisory Control and Data Acquisition

PTT's FISCAL YEAROctober 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 theBank's standard variable interest rate.

Project Objectives: The objective of the project is to increase the gassupply capabilities of Tha4.land by: a) expanding thegas transmission system; b) strengthening theinstitutional functioning of PTT; and c) making moreefficient use of capital resources in the gas sectorthrough 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 theBongkot gas field to the existing Erawan productioncomplex; (b) a 24-inch, 160 km long submarine pipelinefrom Erawan to a terminal at Khanom; (c) a newSupervisory Control and Data Acquisition (SCADA) andtelecom system and renovation of the existing system;(d) a riser platform; (e) equipment includingadditional compression capacity; (f) upgrading ofPTT's Management Information System (MIS) and trainingof staff; and (g) a study for preparation of safetyand environmental standards, and a study for a secondpipeline.

Benefits: The proposed project would have significant economicand environmental benefits. The gas will be used forpower generation, in a combined-cycle plant, which hasbeen shown to be part of Thailand's least-costsolution to power generation. The economic benefitsof the project are derived from the value of fuel(mainly fuel oil) displaced by gas, corrected for thedifferential in thermal efficiency. In addition, theproject produces a significant volume of condensatesaleable in international markets. Environmentally,natural gas is a clean and low-polluting fuel comparedto 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 reserveshave 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 performanceof their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

The risk of insufficient gas reserves is consequentlylow. The risks associated with potential increase inproduction costs stem from the complex nature of thereservoirs. This risk has been mitigated by takinginto account appropriate contingencies in setting costparameters, and benefitting from the experience ofanother gas producer, which has operated nearby since1981.

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f&stimatpd Cost:Local Foreign Total

Pipe material (Line pipe) - 77.2 77.2Pipeline coating & construction 15.0 121.2 136.2TOTAL equipment - 20.0 20.0SCADA/telecom/civil work 6.7 6.6 13.3Riser pl tform - 38.0 38.0Engineering consultancy 3.5 11.5 15.0Studies and training 0.3 2.9 3.2Taxes and duties 13.0 - 13.0

Base Cost 38.5 277.4 315.9

Physical contingency 3.1 22.2 25.3Price contingency 0.8 6.0 6.8

Total project cost 42.4 305.6 348.0

-^ther cogts:

Interest during constructionand 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 52.0Asian Development Bank 8.0 50.0 58.0U.S. Exim Bank 0.7 6.6 7.3Conr-ercial Borrowing 10.0 46.0 56.0PTT Internal Cash 15.1 76.6 91.7IBRD 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 9Cumulative 75 96 105

Economic Rate of Return: 26X

sM : IBRD No. 23485 and IBRD No. 23519

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THAILAND

BONGKOT GAS TRANSMISSION PROJECTStaff Appraisal Repore

TAbl2 of ContentsPage No.

I. THE ENERGY SECTOR

A. The Role of Energy in the Thai Economy . . . . . . . . . . . 1B. Energy Resources and Production . . . . . . . . . . . . . . 1C. Energy Consumption and Demand . . . . . . . . . . . . . . . 2D. Future Prospects for Energy . . . . . . . . . . . . . . . . 5E. The Institutional Framework . . . . . . . . . . . . . . . . 5F. Sectoral Issues and Strategy . . . . . . . . . . . . . . . . 6

II. TIE GAS SECTOR

A. Background . . . . . . . . . . . . . . . . . . . . . . . . 9B. Gas Reserves ............. 9C. Production of Gas . . . . . . . . . . . . . . . . . . . . 10D. Gas Availability . . . . . . . . . . . . . . . . . . . . . 10E. Gas Demand . . . . . . . . . . . . . . . . I . . . . . . 12F. Gas Pricing . . . . . . . . . . . . . . . . . . . . . . 15G. Experience with Previous Bank Loans . . . . . . . . . . . 15H. Rationale for the Bank Involvement . . . . . . . . . . . 16

III. PROJECT

A. Project Background . . . . . . . . . . . . . . . . . . . . 18B. Project Objectives . . . . . . . . . . . . . . . . . . . . 18C. Project Description . . . . . . . . . . . . . . . . . . . 18D. Status of Project Preparation . . . . . . . . . . . . . 23E. Environmental and Safety Aspects . . . . . . . . . . . . . 23F. Project Implementation and Schedule . . . . . . . . . . . 25G. Project Costs . . . . . . . . . . . . . . . . . . . . . . 26H. Project Financing Plan . . . . . . . . . . . . . . . . . . 27I. Procurement and Disbursement . . . . . . . . . . . . . . . 28J. Monitoring, Reporting and Supervision . . . . . . . . . . 31

This report is based on the findings of an appraisal mission to Thailand inDecember 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 PeerReviewers were: Messrs./Mme. A. Hashayekhi (FODG4), A. Malbotra (ASTEG) andD. Mehta (EA1IE). The project was cleared by Messrs. C. Madavo, DirectorEAl and V. Nayyar, Chief EAlIE.

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IV. BORkOWER

A. Ba^kground . . . . . . . . . . . . . . . . . . . . . . . . 33B. Organization . . . . . . . . . . . . . . . . . . . . . . . 33C. Staffing and Training ... . . . . . . ..... . . . . 34D. Operations and Management ... . . . ... . . . . . . . 36

V. FINANCIAL ANALYSIS

A. Past Performance .... . . . ...... . . . . . . . . 39B. Present Financial Position ... . . . . . . . . . . . . . 41C. Financial Outlook .... . . . . . . . . . . . . . . . . 42D. Investment Program and Financing Plan . . . . . . . . . . 44

VI. PROJECT JUSTIFICATION AND. RISKS

A. Economic Benefics ........... .... .... . 46B. Environmental Benefits ........ ... .. .. .. . 47C. Project Risks . . . . . . . . . . . . . . . . . . . . . . 48

VII. AGREEMENTS REACHED AND RECOMMENDATION

A. Agreements .49B. Recommendation .51

1. Commercial Energy Balance .522. Commercial Energy Demand .533. Prices of Selected Energy Products . . . . . . . . . . . . . . 554. Geology and Petroleum Reserves .... . . . . . . . . . . . . 585. Present Gas Production and Consumption . . . . . . . . . . . . 626. Forecast of Natural Gas Supply/Demand . . . . . . . . . . . . 637. Projected Gas Demand by EGAT ..... . . . . . . . . . . . . 66S. Project Diagrammatic Description . . . . . . . . . . . . . . . 679. Bongkot Field ....... .. .. .. .. .. .. . .. . . 6810. Summary of Environmental Assessment . . . . . . . . . . . . . 7211. Project Implementation Organization . . . . . . . . . . . . . 8212. Project Implementation Schedules . . . . . . . . . . . . . . 8313. Annual Capital Expenditures . . . . . . . . . . . . . . . . . 8414. Schedule of Disbursement . . . . . . . . . . . . . . . . . . . 8515. PTT's Past Financial Performance . . . . . . . . . . . . . . . 8616. PTT's Financial Projections . . . . . . . . . . . . . . . . . 8917. PTT's Capital Investment Program . . . . . . . . . . . . . . . 9618. Economic and Financial Analysis . . . . . . . . . . . . . . . 9719. 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, makingThailard the fastest growing economy in the world. Commercial energy,particularly oil and gas, plays a critical role in Thailand's economybecause (a) Thailand '.. a relatively modest endowment of commercial energyresources and (b) the country's dramatic industrialization in ree~ent yearshas 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 andrapid economic growth expecteu in Thailand and the uncertair. prospects ofdiscovering further major oil and gas reserves.

'.2 Like other middle-income, oil-importing countries, Thailand'snomy is greatly affected by the price of oil. In the earlv 1980s, whencountry faced sharp increases in oil import prices and then the oil

I absorbed over one third of the country's export earnings, Thailand wasab_ ro maintain growth, but only at the expense of high inflation, largefiscal md ex-rnal deficits, and heavy international borrowings. Whilethe Government implemented fiscal policy measures to revive the economy,the dec'.ne in the price of oil in 1986 was the single most importantfactor 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 nationalsavings, resulting in increased investments.

1.3 Despite the country's impressive economic growth, per capitaenergy consumption in Thailand and the type of energy consumed is that of amiddle-income developing country: a modest 320 kilogram oil equivalent(koe) consumption of energy per capita (compared with the average 420 koefor all Asia) and a relatively high share (35X) of traditional fuels in thefinal energy consumption. This is explained by the size of the ruralpopulation and the relatively high price of commercial energy compared withrural income levels, which places commercial energy beyond the reach ofthe lower-income group.

B. Energy Resources and Production

1.4 As of end-1990, the remaining recoverable reserves of oil inThailand totalled about 260 million barrels, including about 195 millionbarrels of condensate, which would have to be produced in association withoffshore gas, and about 65 million barrels of crude oil. Possibleadditional oil reserves are estimated at about 125 million barrels,consisting of about 65 million barrels of condensate in off-shore gasfields and 60 million barrels of oil (see para. 2.2). Oil production inThailand is currently limited to Phet crude from the Sirikit oil field in

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Kamphaeng Phet Province, which amounted to 22,000 barrel per day (bpd) in1990. In addition, about 19,000 bpd of condensate were produced inassociation with gas from offshore fields in the Gulf of Thailand. To meetthe country's oil demand, Thailand imported 145,000 bpd of finishedpetroleum products, and 208,000 bpd of crude for processing in its localrefineries.

Natural Gas

1.5 Natural gas has been discovered mostly by companies exploring foroil. As of end-1990, the remaining proved and probable reserves of naturalgas in inailand totalled about 7 tcf. Possible additional gas reserves areestimated at about 3.7 tcf. Gas production in 1991 was about 770 mmcfd, ofwhnich 670 mmcfd were produced from the offshore fields.

Hydro Power

1.6 Thailand's hydropower potential, excluding that of its two maininternational 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 LaoPDR and Malaysia. Higher iulvestment costs and environmental concerns arethe 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 resourcesamount to 2.2 billion tons (about 450 million toe), of which an estimated800 million tons are economically exploitable reserves. Almost 70X ofthese resources are located in the Mae Moh Basin in northern Thailand whichis exploited solely by EGAT, the largest user of coal. The production oflocal coal in 1990 was about 9.8 million tons. In addition. Thailandimported 0.3 million tons of coal in 1990, for use in the industrialsector.

C. Energy Consumption and Demand

1.8 In 1990, total supply of commercial energy in Thailand was about28 million tons of oil equivalent (toe). This was a two and a half foldincrease over 1980. Petroleum represented 701 of the total supply; naturalgas 16X, lignite 91, hydro power 4Z, and coal 1Z. Since Thailand exportsvery little commercial energy, the entire supply was consumed in thecountry. Table 1.1 summarizes the past consumption and the prospects forcommercial energy demand in Thailand. A detailed energy balance is givenin Annex 1.

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Table 1.: PRIMARY CONMERCIAL ENERGY-CONSUMPTION AND PROJECTED DEMAND(1985-2005)(million toe)

Primary Commercial 1985 1990 1995 2000 2005Energy _ _ _ _ _ _ _ _ _ _

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 Ta/ Dry gas-suppty conutraint.

1.9 Final commercial energy consumption in the economy continues tobe dominated by the transport sector, which in 1990 accounted for 40X,followed by the industrial and commercial sectors, accounting for 30% and24X respectively. Traditional fuel (fuelwoods, charcoal, and agriculturalresidues) continues to represent a significant albeit rapidly decliningshare of energy consumption in the rural residential sector.

Petroleum

1.10 Demand for petroleum products ir 1990 was about 201 higher thanin 1989. Since 1985, LPG consumption has grown at an annual average rateof 111. largely because of its increasing use in the residential sector,but also in petrochemical industries. Gasoline consumption has grown at anaverage 12X p.a. since 1985, reflecting increased consumption in thetransport 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 itscontinum.ng use in electricity generation. Diesel oil consumption grew at

121 p-a. and had the highest Powth between 1987 and 1990, averaging about14.61 p.a. These rates of 6?owth were realized despite an increase ofabout 1.9 Baht per lite' ..L the retail prices of petroleum products.Table 1.2 summarizes tlO -Ast consumption and the projected demand forpetroleum products in Thailand.

_J Automobil sale In 1990 grow at 45%. Transport sector consumpUon also grew because of Increasedtransport of agrIculural products and of construction raw materials as well as the expansion of fisheries (and relatedboaUng).

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TI1able.a: PETROLEUM PRODUCTS CONSUMPTION AND PROJECTED DEMAND(1985-2005)

(thousand bpd)

1985 1990 1995 2000 2005 Avg. GrcwthI ~~~~~~~~~~~~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: PTTa/ 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 processedin the country's three refineries: the Bangchak Petroleum Co., Ltd. (BPC)refinery --in which PTT has a 30% interest-- with a current capacity of65,000 bpd; the Thai Oil Co., Ltd. (TOC) refinery -- in which PTT owns a49% interest -- with a current capacity of 107,000 bpd; and the EssoStandard Thailand Ltd. refinery --wholly owned by Esso Eastern Inc.-- witha 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 ofApril 1990, there were about 3,250 retail stations in Thailand.

Power

1.13 Thailand's total installed generating capacity as of September1990 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 atKhanom, 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 combustionturbines (3%).

1.14 Per capita electricity consumption in Thailand has grown from 19KWh in 1961 to 606 KWh in 1989. Demand for electricity, particularly inthe past two to three years, has surged, with about a 15% average increasea year, fueled mainly by rapid GDP growth in the industrial rector, butalso by the recent substantial expansion in the residential sector, both inurban and rural areas. The industrial sector consumed about 48% of the

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electricity, the residential and commercial sector each about 22X, and thegovernment and other public facilities about 81.

1.15 De-and for coal in Thailand surged during the period of high oilprices. The total share of coal consumption in commercial energy, whichwas 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 GDPgrowth. Domestic coal supplies about 901 of demand. The power sectoraccounts for 801 of total coal consumption. Based on current consumption,and co;.sidering proeluction constraints due to environmental reasons, EGATneeds to start importing coal in 1996, to supplement the local supply inorder to meet its power generation requirements.

D. Future ProsRects for Energv

1.16 While the energy elasticity of GDP growth in Thailand between1985 and l993 was 1.2, reflecting the continuous expansion of energyconsumption in the industrial sector, the past trend is not expected tocontinue because of increased efficiency in energy use and, to a lesserdegree, the structural shift away from heavy industry to lightmanufacturing and services. The Government accordingly projects that totalenergy consumption wi?l grow at an average rate of 8.71 a year between 1990and the year 2000, hence an implied energy/GDP elasticity of 1. This is arealistic forecast considering projected growth of the various sectors.Oil consumption is expected to increase at the rate of 81 a year between1990 and 2000, and natural gas consumption at 71 a year, primarily becauseof a supply constraint. In the power sector, the latest forecast by EGATenvisages a 14.51 base-case growth for 1992, followed by an 3.41 growth for1993-97 and 6.9Z for 1998-2000. Demand for domestic coal is expected toincrease at about 141 a year throughout this decade. Annex 2 providesPTT's detailed forecast of commercial energy demand in nailand.

E. The Institutional Framework

1.17 Institutional arrangements for the regulation of Thailand'senergy sector are rather complex, cutting across several ministries andagencies. The principle actors are: (a) the National Economic and SocialDevelopment Board (NESDB), the government agency responsible for theformulation of overall economic and social policy, reporting to the Officeof the Prime Minister; (b) the National Energy Policy Committee (NEPC),which acts on behalf of the Cabinet on all matters related to energy policyand planning; (c) the National Energy Policy Office (NEPO), a senioipolicy formulation, coordination and advisory body focused on energymatters, which serves as a secretariat to NEPC; (d) the Department ofMineral Resources (DMR), which is responsible for resource assessment,granting of licenses for exploration and production, setting and enforcing

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of environmental and safety standards governing production activities, androyalty collection; (e) the National Energy Administration (NEA), underthe Ministry of Science, Technology and Energy, which is responsible fordevelopment of non-conventional energy sources, energy conservation, andidentification and promotion of new uses for domestic energy sources; and(f) the National Environment Board (NEB), chaired by a Deputy PrimeMinister and responsible for advising the Cabinet on all aspects ofenvironmental protection in Thailand.

1.18 While the public enterprises in the energy sector enjoy a largedegree of autonomy in the conduct of day-to-day operation, the Governmentcontinues to control matters related to investment planning and financing.Recently, however, the Government is increasingly introducing measures topave the way for commercialization of revenue-generating publicenterprises. PTT is among the first state enterprise to be selected by theMinistry of Finance (MOF) for de-regulation so long as it meets a set ofprofitability and pruductivity performance criteria.

F. Sectoral Issues and Strategy

1.19 During the past decade, the Government and the Bank havecoopezated to identify and address the following issues in the energysector:

(a) Insufficiency of domestic energy resources to meet the growingdemand is the most critical issue in the sector. Since the late1970's, the Government has made serious efforts to reduce thecountry's dependence on imported energy. As a result, the shareof imports in commercial energy declined from 94X in 1980 to 63Xin 1990, primarily through increased production of domestic coaland natural gas. However, it is now recognized that furtherexpansion of domestic energy supply is limited and the country islikely to rely more neavily on energy imports in the future. TheGovernment is therefore attempting to devise an energy importpolicy which would minimize both the risk and the expectedeconomic cost of energy imports to the country. The Governmentand the Bank are cooperating in exploring possibilities ofimporting gas and liquified natural gas (LNG) from the countriesin the region (para. 2.13).

(b) Heavy burden of energy investments on public resources has beenrecognized as an impediment to economic growth. As a result, theGovernment and the Bank have cooperated in investigating variousavenues to promote private sector participation in the energysector. In the power sub-sector, which is the country's mostcapital-intensive industry, the Government has adopted a policytowards potential commercialization of EGAT, encouragement ofprivate independent power generation and private cogeneration.In the petroleum sector, private oil companies have taken themajor share in refining and distributing petroleum products. In

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the gas sub-sector, private companies dominate upstreamactivities. In addition, the recent reorganization of PTT intoprofit centered business units is an initial step towardscommercialization of PTT and eventual privatization of itsindividual business units.

(c) Subsidies and cross-subsidies in energy prices have beenrecognized as an important contributor to inefficient use ofenergy. During the 1980's, the Government introduced successiveincreases in power tariffs to align the rates with the cost ofsupply. In 1987, the Government took a major step towards.floating retail oil prices by tying local ex-refinery prices tothe world market through weekly price adjustments based onSingapore-posted prices. There are some remaining distortions inthe relative price structure of petroleum products. TheGovernment is taking steps to align the relative price structureof petroleum products with the structure of international pricesand domestic refining costs. The prices of selected energyproducts are given in Annex 3.

(d) Judicious use of energy has been recognized as a necessity forcoping with the economic, financial and environmental costs ofenergy supply. Energy conservation has become, since theintroduction of the Sixth Development Plan (1988-92), a formalobjective of the energy sector policy. Accordingly, the Planprovides for: (i) the establishment of the Energy ConservationCenter of Thailand (ECCT) charged with promoting energyconservation through public awareness, consulting assistance,training, inspection, research and development; (ii) theestablishment of the Industrial Finance Corporation of Thailandand other financing agencies to provide low-interest loans toindustrial factories which adopt energy saving processes andsystems; (iii) the reduction of taxes and duties on energy-efficient equipment and appliances; (iv) the establishment ofeducational institutes to promulgate energy knowledge to studentsand the public; (v) consideration for enacting an EnergyConservation Promotion Law mandating energy efficient designs fornew industrial and commercial buildings and systems, andimproving features of existing ones; and (vi) promoting transferof technology including between the Government agencies and theprivat_ sector. These directives are currently being put intopractice by the NEA and its implementing arm, the ECCT.

(e) Environmental impacts of energy nroduction and consunmtion havebecome a topic of public debate. The Government has recognizedthe significance of the issue and is fully committed to thedevelopment of the energy sector in an environmentally soundmanner. Environmental concerns in the next few years will befocused on: (i) the impacts of rapid expansion of power andmining facilities; (ii) the ecological acceptability ofhydropower projects involving dams; and (iii) the adequacy of theexisting environmental regulatory framework for formulating

policy and standards, enforcing compliance and monitoring thequality of the environment. Measures to strengthen theenvironmental safety of gas production, transmission anddistribution are incor?orated in the proposed project (paras 3.16- 3.22).

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II. THE GAS SECTOR

A. Background

2.1 The natural gas indutstry in Thailand started in August 1981, withtransmission 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 offshorefields, under a production-sharing agreement. After extraction of gasliquids in a gas separation plant at Rayong (finarnsd by the Bank underLoan 2184-TH), the dry gas is transported to the Bangkok area through a160-km onshore pipeline, primarily for use in EGAT's power planta but alsofor use in the industrial sector. The gas liquids are used to produceLiquified Petroleum Gas (LPG) for domestic consumption and to providefeedstock 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 easilydefinable limits. Hence, the reserve calculations --at least prior tosignificant production history-- are based on statistical occurrence ratherthan measured quantities. The relatively high cost associated withproduction of Thailand's offshore gas makes reserve estimates highly pricesensitive and rather subjective. A more detailed discussion of the generalgeology of Thailand's sedimentary basins and its hydrocarbon reserves isgiven 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: 7068Gas Developed 3868(bef) Undeveloped : 3200

Possible Reserves

Remaining Proved and Probable: 209Condensate Developed : 138(million bbl) Undeveloped : 71

Possible Reserves :104

Soure: Mouic. Eatlmtc

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2.3 Based on the above, the gas reserve life at the currentproduction rate is about 28 years, and at the production rate forecastedfor 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 theErawan field averaged about 200 mmcfd. Subsequent drilling by Unocal inthe vicinity of the Erawan field resulted in discovery of several fields,together currently producing about 670 mmcfd. The production facilitiesinclude 34 platforms and 422 development wells, 309 of which are nowproducing. The current production comes from fields under Unocal'sContract I and II. The fields developed under Unocal Contract III will bebrought on stream in early 1992. On February 6, 1990, a total of 1 tcf gashad been purchased by PTT from Unocal, less than nine years after the startof the operation, rather than 20 years, as indicated in the originalcontract.

2.5 In addition to offshore gas production, which represents about90X 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 salesagreement signed between PTT and Esso for the Namphong gas, a reserve ofnot less than 1 tcf must be confirmed before a gas utilization project canbe implemented. In the interim, however, natural gas at the rate of 66mmcfd was delivered until the end of 1991, and is projected to graduallyincrease to 250 mmcfd by 1993. Annex 5 provides present gas consumption inThailand.

2.6 Gas production in the Gulf of Thailand is determined by twostriking features of the gas reserves: the gas fields contain manyindividual reservoirs of varying size and shape; and most individualreservoirs are small. Because each small reservoir depletes fairly quicklywhen placed in production, a large number of platforms and wells arerequired to recover the gas. In addition, since each production well maypenetrate from 2 to 20 or more individual reservoirs, workovers and re-completions are rather frequent. These factors make both the cost ofdevelopment and production relatively hig&.

D. Gas Availability

2.7 The forecast of gas availability from offshore fields in the Gulfof Thailand is given in Table 2.2.

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Table 2.2: Gas Availability in Gulf of Thailand(mmcfd)

Production Fields Total EZwn/ zxisting 34-inchYear Unocal I & II Unocal III Doncot Unocal 12/27 Prod'n 1h0m Pipl. Space Capacity LI

an

Mazxi= Allowable Flow750 850

1991 670 - - - 670 - + 80 +1801992 590 160 - - 750 - 000 +1001993 550 ISO 75 - 775 - - 25 + 751994 535 165 150 - 8S0 e0 - 20 + 601995 530 170 250 - 950 s0 -120* - 201996 470 230 250 - 950 120 - 60 + 201997 470 230 250 - 950 120 - s0 + 201998 470 230 250 150 1,100 120 -230 -130*1999 400 300 250 250 1,200 150 -300 -2002000 400 300 250 250 1.200 150 -300 -200

Source: PTT and Hjasiona 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 ofThailand- - which may impact the Thai gas market include both onshore Thaigas and imports. At present, onshore gas production is limited to the non-associated gas from the Namphong field and associated gas from the Sirikitfield (para. 2.5). Namphong was originally estimated to contain 1,500 becof producible reserves and therefore a nipeline from the Namphong field tothe Bangkok area was contemplated. However, the additional drillingresulted in reducing the estimated level of original reserve. Therefore,no major additional onshore gas supplies are predicted prior to the year2000.

2.9 Faced with a limited supply of domestic gas and its rapideconomic expansion, Thailand is looking to its neighboring countries forgas. This includes Martaban offshore gas in Myanmar, offshore Malaysiagas, and any new gas discoveries in the Cambodian and Vietnamese portionsof the Gulf of Thailand. The offshore Martaban field with 2,500-4,000 befof producible reserve is a suitable candidate because of its lowdevelopment and operating costs and high-caliber reservoir. Discussionsbetween Thailand and Hyanmar have been ongoing for several years withoutproducing any discernible result due to economic and political difficultiesin Myanmar. Gas imports from Myanmar are therefore not likely tomaterialize before the year 2000.

2.10 Due to the limited market in southern Thailand and the distancesinvolved from the Malaysian gas fields to major Thai markets, it is notexpected that significant gas imports from Malaysia will materialize in theforeseeable future. A more likely scenario for imports from Malaysiainvolves the extension of a Gulf of Thailand trunkline, to join the JointDevelopment Area (JDA), a gas field shared between Thailand and Malaysia.The development of JDA, however, requires additional exploratory workbefore an appraisal program can be contemplated.

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2.11 The eastern portions of the gas-rich Pattani Trough and MalayBasin extend into Cambodia and Vietnam territory, making Thai importspotentially viable. However, exploration is only in the initial stages.Furthermore, any pipeline would need to traverse the disputed areas forThailand to utilize existing infrastructure to import gas from Cambodia orViet Nam. At present, import potential seems remote, making the import ofgas from Vietnam and Cambodia unlikely before the year 2000.

2.12 Therefore, no additional gas supplies of consequence, either fromonshore domestic sources or imports, are likely to impact the Thai gasmarket before the year 2000. Domestic offshore gas supplies will be themost likely source to provide increased gas production. Unless newdiscoveries are made in the Gulf of Thailand, the 1,400 - 1,500 mmcfdplateau production expected in the late 1990s should become the targetlevel. Identified reserves should be sufficient to maintain production atthis level for eight to ten years, with expected new discoveries producedto prolong this plateau further.

2.13 Thailand has recently been considering importing LNG fromIndonesia or Malaysia. Given the high net-back value of gas in Thailand'seconomy (particularly in the power sector) and its environmentaladvantages, the option of importing LNG deserves further assessment. Onekey consideration in importing LNG is that unlike other imported fuels(e.g., oil and coal), LNG requires commitments to be made well ahead oftime because of the magnitude and long lead time of the investmentrequired. Another consideration is that imports have to be of a sufficientscale to justify the necessary infrastructure. This requires a concertedeffort on the part of the Government, in part motivated by environmentalconsiderations, to promote the use of LNG as a major fuel source and adoptappropriate pricing policy and other policies to bring about an adequatelevel of usage. The Government is initiating a "fuel option" study, whichincludes 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 theforeseeable future. Table 2.3 gives the supply/demand forecast fornatural gas in Thailand and Annex 6 provides a detailed breakdown. Thesupply/demand forecast indicates that Thailand will face a deficit in gassupply for the foreseeable future. The Government's projection indicatesthat the country's demand for natural gas will reach 1,975 mmcfd by theyear 2000, with about 1,400 mmcfd going to the power sector (including 610umcfd for combined-cycle power plants). These relatively conservativeestimates are based on the needs of currently identified end-users, withouttaking into account rapid GDP growth in the future and the environmentalbenefits associated with the utilization of natural gas. It is estimatedthat if the gas supply is not constrained, the country's gas consumptioncould reach 2,500 mmcfd by the year 2000.

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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 presentallocation of gas is based on the ranking of the economic value of gas indifferent applications. The present policy is to extract the propane andbutane (C3/C4) fractions for LPG use, and the ethane and propane (C2/C3)fractions for petrochemical feedstock. The methane (Cl) fraction, whichrepresents about 80X of the total, is used in the industrial and powersectors. The gas in Thailand presently yields its highest economic valuewhen used in a combined-cycle power plant. However, since the total gasdemand in the industrial sector represents less than 5X of the country'spotential gas demand, the Government has made a decision to meet the fulldemand of gas in the industrial sector, while adjusting the supply to thepower sector according to gas availability.

Gas Utilization for Power Generation

2.16 Due to rapid growth in electricity demand in Thailand, EGAT needsto increase its generation capacity from 7,970 MW in 1990 to 24,794 MW inthe year 2000. EGAT has established that, subject to gas availability, gasoffers the least-cost scheme for the country's power generation

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requirementsV. The economic benefits of gas use in combined-cycle powerplants and its value-added environmental benefits resulted in the share ofcombined-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. Theshare of coal-fired (lignite) power plants increased from 61 to 221. Inaddition to economic benefits, the underlying policy for this structuralshift stemmed from two objectives: reducing Thailand's dependence onimported nil and improving environmental conditions in the country.

2.17 Choices of fuel for EGAT however, are becoming increasinglylimited. The remaining hydro potential is not easy to develop, because ofhigh costs ard environmental and forestry problems. The reserves of thecountry's li[aite are not sufficient to meet the increased power generatingrequirements, and, in addition, the use of lignite creates environmentalproblems. Although the gas is the least-cost solution for EGAT's powergeneration, because of constraints in gas supply, EGAT cannot develop areliable, 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 supplementgas with fuel oil in its master plan in case of gas inavailability. EGAT'spresent planning calls for the share of combined-cycle plants to stay inthe present range of 15-16% between now and 2006, assuming that no furthergas would be available in addition to the existing reserves. The plan alsocalls for the share of oil-powered plants to decline from 221 to 41 by2006, the share of local-coal-powered plants to increase marginally, from181 to 221, but the share of imported-coal-based power plants to increasefrom 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 byEGAT until 2001, for both thermal power plants and combined-cycle powerplants. The projected demand represents EGAT's minimum gas requirements.If sufficient gas were available, EGAT's potential demand would be 1,420mmcfd 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$1.2billion. Furthermore, the Seven-Year Plan envisages additional investmentin rehabilitation and new construction of oil-fueled power plants. Forboth oil and gas, EGAT needs to deal with PTT. Given this size ofinvestment, EGAT and PTT need to coordinate more closely regarding theproper programming of investments. While such coordination at the policylevel is currently through NEPO and at the corporate level between EGAT andPTT, it is believed that a more formal exchange of information between PTTand EGAT through regular, working-level meetings would produce substantialbenefits. During negotiations, assurances were given by PTT that it wouldtake the necessary measures to hold such a meeting at least every sixmonths (para. 7.2).

2/ The methodology used by EGAT to deternine the leastoost scheme h quilb adequate. Altemative goneratlonoxpansion sequences are analyzed using computer model WGOPLAN). The timing of the plant Is dotermined by analysisof monthly load demand and avallable generating capacity.

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F. Gas Pricing

2.19 Although Thailand has not yet established a comprehensive gaspricing system for produicers and consumers, the Government's underlyingpolicy for gas pricing in sound, in that it is guided by the principle offull cost-recovery.

Producer Prices

2.20 The cost of producing natural gas in Thailand is relativelyexpensive compared with that in Indonesia or Malaysia. This is due to thecomplex geological structure of the fields (para.2.6), which results in thewell-head transfer price bearing the high cost of field development andproduction. The average well-head price for Unocal's gas ranges fromUS$1.77 to US$2.08 per mmbtu, while gas frov he Namphong field is aboutUS$1.00 per mmbtu. Except for Namphong gas, : r which the price is 100llinked to the price of fuel oil, Unocal's priceb are partly indexed to fueloil (15X - 202), and partly to Thailand's wholesale prices (25X - 30X) andto U.S. oil field machinery prices (40X - 60X),

Consumer Prices

2.21 The principle applied by the Government in setting consumerprices is to link gas prices to alternative fuel prices in each activity.Currently, PTT charges two prices: one for industry and one for the powersector. The present prices of gas to industry are intended to encour-.,eLPG consumers to shift to gas, but no such incentive is provided to fueloil users. This is because the gas has a lower net-back value whensubstituting for fuel oil. In 1990, the average price of gas to industrywas Baht 100-120 per mmbtu. In the power sector, which uses over 902 ofgas in the country, the gas yields its highest economic value. The priceof gas for the power sector, i.e., EGAT, is about Baht 70 per mmbtu. Theprice of gas to EGAT is low because of the size of EGAT's consumption andbecause EGAT, as a swing customer, bears the weight of uncertainties of gassupply 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 andgas sector over the past ten years. The first loan (1773-TH) was forconstruction of Thailand's first gas transmission pipeline. The secondloan (2184-TH) was for the construction of a gas separation plant. Thethird loan (2184-TH) supported oil field developmer.t. These projects werecompleted on schedule and within the budget, and they realized their mainobjectives. The Bank provided substantial institutional and technicalsupport to PTT, especially during its early stages when PTT had very littleoperational experience. While several important lessons were learned from

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the Bank's previous involvement, two in particular are relevant indesigning 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 fromPTT than it had originally estimated, because EGAT saw nofinancial incentives in using gas while the price of fuel oil wasdeclining. Since there was no formal agreement between PTT andEGAT, EGAT simply switched its dual-fuel installations to fueloil. PTT was not in a position to pass on to its major clientthe benefits of declining oil prices, because in its agreementwith the gas producers, the gas price was insensitiv& tointernational oil prices. In the proposed project, a long termagreement has been signed between PTT and EGAT, under which PTTpasses the full cost of its gas purchases from the producers toEGAT, 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 Banklearned that the hydrocarbon basins in the Gulf of Thailand arecharacterized by a complex geology, therefore requiring acomprehensive appraisal of the discovered gas fields beforeproceeding to the full development and production phase. Aninadequate appraisal program could lead to substantial costoverruns. In the proposed project, the designs have taken intoaccount 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 industrysince its inception. In the course of the dialogue that has beenstimulated by this involvement, the Government and the energy-affiliatedagencies have continuously sought the Bank's advice in the areas ofinstitution building, pricing, investment programming, and least-costscheme 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 thatthey will be concluded succe- fully: (a) the Bank has worked extensivelywith PTT to develop techniques and processes for a more rational investmentprogramming and analysis. Continued Bank involvement will encouragefurther 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 developinginternal systems and procedures and managerial approaches that areappropriate to PTT's eventual privatization in which t*e individualbusiness units might be sold separately to the public; and (c) in theproposed project, Bank support to date has enabled PTT to take a broad viewat its objectives, including adopting a common-carrier approach to pipeline

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development. The proposed common-carrier pipeline will encourage smallindependent producers to exploit marginal fields close to the pipeline, andwould also promote the regional trade in gas slnce the construction of thepipeline facilitates the future importation of gas into Thailand from theneighboring countries of Vietnam and Malaysia. Furthermore, the Bark'sinvolvement in the project has helped to resolve the gas pricing issuebetween PTT and EGAT which has been in dispute for ten years, and hashelped attract co-financing for the project.

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III. THE PROJECT

A. Background

3.1 Since the commercial discovery of gas in the Bongkot field in1976 (para. 3.5), the Government has sought ways to implement a project foreconomic utilization of this gas. Immediately following the award of theProduction License by DMR, PTT commissioned Fluor Daniel to carry out a gasma-ter plan study, taking into account the potential gas availability,forecasted demand, and the existing infrastructure. A conclusion of thestudy was that the implementation of the proposed project should be givenhigh priority. In February 1990, PTT requested Bank financing the project.The Bank has reviewed the consultant's report and agrees that the BongkotGas Transmission Project constitutes a high priority investment in themaster plan proposed for the country's gas transmission network.

B. Project ObjectivUes

3.2 The objective of the project is to increase the gas supplycapabilities of Thailand by: a) expanding the gas transmission system; b)strengthening the institutional functioning of PTT; and c) making moreefficient use of capital resources in the gas sector, through annual reviewof PTT's investment program (para. 5.11).

C rr_!lect Description

3.3 The project consists of two submarine pipelines and theassociated facilities to transport the natural gas production of theBongkot field to onshore locations in the southern and central parts of thecountry. Map IBRD 23485 shows the location of the offshore facilities andthe routing of the pipeline. Annex 8 gives a diagrammatic description ofthe project's content.

3.4 The major project components are:

(a) A 32-inch diameter natural gas pipeline installed in water depthsranging from 270 ft to 200 ft. The pipeline would runapproximately 175 km from the production platform being installedin the Bongkot gas field to a new riser platform to be installedapproximately one km from the existing Erawan production complex.The pipeline is designed to transport up to 700 mmcfd of naturalgas; V'

/ PTT antlcpates a plateau production of 350 mmcfd from the 8ongkot field, and expects an additonal 350 mmcldIn future from the JDA flold.

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(b) A 24-inch diameter natural gas pipeline installed in water depthsof 200 ft to landfall. The pipeline would run approximately 160km from the new riser platform at Erawan to the terminal atKhanom. The pipeline is designed to transport up to 350 mmcfd ofnatural gas;

(c) A new Supervisory Control and Data Acquisition (SCADA) andpipeline telecommuw cations system, including renovation of theexisting SCADA system, and construction of new control buildingsat Khanom and at Chonburi;

(d) A riser platform to support a piping mainfold to connect theincoming gas flow from the Bongkot field to the existing 34-inchpipeline to Rayong, as well as the pipeline to Khanom;

(e) Equipment including additional compression capacity for PTT'soff-shore operation at Bongkot and Erawan;

(f) Consultancy and management services for engineering, procurementand construction of the project facilities;

(g) Upgrading of PTT's Management Information System (MIS) and thetraining of PTT's staff;

(h) A study for preparing engineering safety and environmentalstandards for PTT's operations; and

(i) An engineering study for a new project to transport additionalgas from the Erawan platforms.

The Bongkot Gas Field

3.5 The Bongkot gas field (formerly called "B" structure) will be theprimary source of gas for the proposed project (IBRD Map No. 23519). Thefield will be developed, produced and operated by a joint-venture of threeprivate producers and PTT Exploration and Production Co., Ltd. (PTTEP).The produced gas will be sold by the joint-venture producers to PTT, inaccordance 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 agreementsigned in December 1991 (para. 3.10).

3.6 The Bongkot field is located about 180 km southeast of the Erawangas field. Annex 9 provides more detailed information on the Bongkotfield. On March 15, 1990, DMR transferred the concession rights in theBongkot field to a joint-venture group. The Joint Venture (JV) assembledto develop and produce the Bongkot gas field comprises PTTEP (40X) which isa 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 (areassurrounding the previously drilled gas production wells) was submitted toDMR, and a seismic program cont.act has been signed for the ReservedExploration Areas (the remainder of the concession area). To proceed with

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development, DeGolyer and MacNaughton (D&M), an industry leader in reservedetermination and experienced in working in the Gulf of Thailand, werecommissioned 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 BongkotProduction Area. D&M estimates that up to 18 platforms and 160 wells willbe required to achieve producing the certified reserves. They are alsoestimating 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 operatingagreement among themselves. TOTAL was elected Operator. The Operatorwill 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 Operatorwill also prepare the Initial Program (the first phase of the DevelopmentPlan and Definitive Cost Estimate) which must be adopted unanimously. Amore detailed description of the Operator's role is given in Annex 9.

3.8 The Development Plan for the Bongkot field is designed to producea minimum of 1,500 bcf of gas and 24 million barrels of condensate over thelife of the Gas Sales Agreement signed by JV and PTT. The cost for thefirst phase of the Development Plan (Definitive Cost Estimate) is estimatedat US$383 million. Procurement is essentially completed and constructionis under way, with production start-up planned in October 1993. The firstphase (Initial Program), however, will not be sufficient to develop the1,500 bcf of recoverable gas reserves and the associated cordensate calledfor in the Gas Sales Agreement. The Operator is already planning a secondphase of development, but no Definitive Cost Estimate has been preparedbecause implementation will depend on first phase results. PTTEP (with theassistance of Statoil) has prepared a complete development plan todetermine the economics of the proposed pipeline project. PTTEP's totaldevelopment plan requires central production and process facilities, 13well-platforms and 123 development wells. The total Development Plan isestimated to cost US$897 million. Considering related exploration costs ofUS$55 million, the total investment for producing at least 1,500 bef of gasand 24 million barrels of condensate is US$952 million. The Bank hasreviewed 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 producersand PTT for the proposed project follows the same principle outlined abovefor the producer price (para. 2.20). Specifically, the transfer price isbased on the economic cost of supply: it is linked to the price of fueloil, and the price adjustment is based on a set of indices reflectingdomestic and international inflation. The formula also includes stablefloor and ceiling prices to avoid the impact of short-term fluctuations ininternational markets. The initial base price is set at Baht 56.14 permmbtu, and the Agreement includes a take-or-pay covenant. The formula

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appropriately ensures economic efficiency by charging the full economiccosts (including a depletion premium) of gas supply, while allowingproducers to cover the cost of exploration, development and production, andthe Government to absorb the economic rent in the form of royalties andtaxes. The discounted (at 12%) transfer price of the gas over the life ofthe field contractual reserve (1.5 tef) is calculated to range from US$1.98to US$2.25 per mcf depending on the range assumed for the future prices offuel oil (i.e., fuel oil price varying from 73% to 85X of the price ofcrude). While the price is relatively high, reflecting high developmentand production costs, the economic value of this gas for power generationis significantly higher than its cost.

Gas Sales Agreement Between PTT and EGAT

3.10 Consistent with its role of purchasing and transmitting the gasto consumers, PTT seeks agreement with the major users for a price whichwould cover PTT's cost of purchasing gas from upstream producers, as wellas its cost of gas transmission. Although PTT has supplied natural gas toits major customer, EGAT, for about a decade, no formal gas sales/purchaseagreement was signed between the two entities until December 1991. Duringpre-app.-aisal of the proposed project, the Bank raised with PTT, EGAT andthe Government the lack of a gas sales agreement as an outstanding issuewhich needed resolution prior to project appraisal. Subsequently, PTT andEGAT undertook extensive negotiations which resulted in the signing inDecember 1991 of a ten-year sales agreement between the two entities. Thepricing structure stipulated under this contract -- as the price of gas tobe paid by EGAT to PTT -- is composed of three components: (a) the pricepaid by PTT to the upstream producers (well-head price); (b) the averagecost of gas transmission by PTT (throughput fee); and (c) the value-addedtax (VAT), if any. A throughput fee will be assessed annuall) to ensurethat it reflects PTT's transmission costs and gives it a reasonable returnon its investment. The agreement provides that if PTT must invest in newtransmission facilities, the throughput fee will be readjusted to take intoaccount the new investment and will be in effect retroactively on the datewhen the new investment was used. The current average price of gas s'old byPTT to EGAT is Baht per 70 per mmbtu. During negotiations, agreement wasreached that prior to entering into any material amendment to the existinggas sale/purchase agreements (between PTT and EGAT, and between PTT and thejoint-venture gas producers), PTT shall exchange views with the Bank andshall take the Bank's views and recommendations into consideration. It wasfurther agreed th&t amendments that would be considered as affecting theability of PTT to perform are those dealing with the: (i) quantity of gasto be purchased by or sold to PTT; (ii) price of gas sold to or purchasedby 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,lt.e Gulf of Thailand; all of that gas is currently being transportedthrough a single 34-inch submarine pipeline from Erawan to Rayong. Thepipeline has been in operation for almost nine years, and its present flowrate is about 670 mmcfd. Its maximum design capacity is 850 mmcfd.

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However, the pipeline has never operated at its design capacity due toinavailability of gas supply. Periodic pipeline inspection -- the latestIn 1990 -- has indicated some corrosion. PTT plans to run a moresophisticated inspection test in early 1992, which should provide moreaccurate information on the condition of the pipeline including its maximumallowable capacity.

3.12 The need for and the viability of the second pipeline totransport additional gas from Erawan to Rayong is a function of: (a) thepresent and projected production of gas from the Unocal and, to a lesserdegree, from the Bongkot fields; (b) maximum allowable capacity of theexisting 34-inch pipeline, depending on the result of the inspection test;and (c) concern over the security of supply, since the existing 34-inchpipeline is the only means of transporting gas to the critical consumingcenters of Rayong and Bongkot for power, petrochemical, and otherindustrial users.

3.13 If the inspection test determines that the pipeline can be safelyoperated at its design capacity of 850 mmcfd, then no major dislocation ofgas supply would occur until about 1998, because the existing pipelinewould have sufficient capacity to transport the additional volume of gas(Table 2.2). Under this scenario, the second pipeline, which is scheduledfor completion in PTT1s Master Plan in late 1995 or early 1996 -- primarilyfor transporting gas from Unocal's future production under Contract III --could be delayed by two years, depending on the pace of Unocal's fielddevelopment 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 throughinstallation of a booster compressor on the existing pipeline rather thanconstructing a new one. However, if the inspection test indicates thatlimitation should be imposed on the capacity of the existing pipeline, thenthe need for additional capacity, in the form of a second trunkline,becomes more immediate, possibly in 1995, as scheduled in the PTT MasterPlan. During negotiations, agreement was reached that the results of thisInspection 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 testand the pertinent recommer.dations of the inspection report would be takeninto account (para. 7.lb).

3.14 To determine the urgency of the second pipeline and the project'sviability, the Bank is providing US$2 million for the required consultant'sstudy as part of the proposed loan. The study, which will be carried outnot later than October 31, 1992 (para. 7.1j), will confirm the availabilityand timing of the gas supply, and the optimal means of evacuating theadditional gas from Erawan to the onshore consuming centers. It wouldestablish whether the additional gas in the region justifies theconstruction of a second pipeline, and whether the proposed second pipelineshould be constructed offshore, closer to the shore or onshore.

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D. Status of Proiect Pregaration

3.15 The project is at an advanced stage of preparation. A contractfor the pipeline materials (to be financed by the proposed Bank loan) hasbeen awarded to a Japanese Consortium in accordance with the Bankprocurement guidelines. A letter of intent has been issued to a firm forcoating and jacketing the pipe in Malaysia. Bids for the pipelayingcontract have been evaluated by PTT and its consultants, and the award isexpected to be announced in April 1992. Other engineering, procurement,and related project activities are progressing at a corresponding pace. Noland acquisition problem is anticipated for pipeline landfall and onshorereceiving facilities since the land is owned by EGAT. The overall statusof project implementation suggests no impediment to the current rate ofprogress, other than the possible lack of timely project financingarrangements.

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 environmentalconsultants, the Team Co., which was responsible for carrying out the EIAand for preparing the Environmental Assessment (EA) report. The final EAreport has fully taken into account the Bank's comments, including themeasures to be taken to ensure that the project complies with the Bank'senvironmental guidelines. Annex 10 provides the summary of the EA.

3.17 The project's negative impact on the environment is minimalbecause use of natural gas would be significantly less harmful to theenvironment than either fuel oil or coal. While natural gas consumption isnot pollution free, .it is inherently cleaner than other fuels. Natural gasis free of most pollutants present in liquid and solid fuels and generatesless carbon dioxide (CO2). The reduction in CO2 emission offers a highlycost-effective response to the greenhouse effect. The gas used incombined-cycle power plants emits only 40X as much CO2 as a coal-fired powerplant. Treated natural gas has no sulfur content. Furthermore, the gas tobe transported by the project pipeline is non-associated gas, which hasmuch less environmental risk than the transport of oil or associated gas.Nonetheless, a few potential but more manageable environmental issuesexist, including the disruption of marine life which may be caused bychanges in seabed conditions in the vicinity of the pipeline duringconstruction; the discharge of liquids such as process water, deck drainageand sewage from production and living quarters platforms; the disposal ofmercury present in the gas; and the noise and vibration caused by equipmenton the production platforms. The EA report fully addresses these potentialissues and provides for appropriate mitigation actions such as pre-treatment of liquid effluents before discharge to the sea, safe disposal ofsolid wastes to approved sites on land and safe disposal of elementalmercury. The disruption of marine life is not severe because only about0.37 square kilometer of seabed would be subject to short-term habitatdestruction. Indeed, during the operation phase of the pipeline lt is

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expected that the pipeline surface would provide attachment points forplant species and will provide cover for fish. The design of equipmentwill be in accordance with international standards for maximum safety andallowable levels of noise and vibration. Furthermore, the EA reportprovides analysis of alternatives, including the effect of various pipelineroutings on natural biological resources such as coral reefs. Proposedmeasures will ensure that the environment impact, if any, will be keptwithin limits prescribed by Bank guidelines. During negotiations,agreement was reached that PTT will take all measures required on its partto ensure full implementation of the action plan contained in theEnvizonmental Assessment Report (para. 7.1c).

3.18 The entire project design will be in accordance with applicableinternational safety codes and standards. Natural gas condensates areseparated from the gas on the production platforms before the gas isintroduced into the pipeline. However, small quantities of liquids will bepresent in the gas as the result of condensation of hydrocarbon gases. Thecondensed gases will be periodically removed from the pipeline by a "pig."The pipeline route will be adequately demarcated, especially in shippinglanes and fishing areas, to avoid potential damage to the pipeline (e.g.,by a ship's anchor). The construction of the offshore facilities is beingcarried out by the Operator of the Bongkot gas field (for upstreamfacilities), and by PTT's construction contractor (for downstreamfacilities). The Operator, TOTAL, has extensive experience in similaroperations elsewhere in the world. The construction of the downstreamfacilities will be carried out under the supervision of BechtelInternational, which also has vast experience in this area. Thesecompanies use high standards of safety and environmental protection, andthey would require the same from their sub-contractors. Furthermore, astudy for developing environmental regulations for all offshore operationsin 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 completionof project construction.

3.19 PTT's operational safety record has been excellent, and it isexpected that operation of the new facilities will meet this high standard.The gas plant group experienced only one lost-time (14 days) accidentduring 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 highwayfatalities, one in 1988 and the other in 1990.

3.20 Notwithstanding PTT's excellent operational safety records andPTT's commitment to the environmental aspects of its operation, therelatively young age of the oil and gas industry in Thailand has not yetproduced the necessary standards and regulations for safety engineering andenvironmental protection. PTT currently has no well-defined safetyengineering standards and environmental regulation, nor does it have anadequate institutional framework to properly administer this aspect of itsoperation.

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3.21 PTT has commissioned the DKV Company of Sweden to carry out aone-time comprehensive safety audit of PTT's entire operation. Duringnegotiations, agreement was reached that the results of this safety auditwould be made available to the Bank not later than December 31, 1992, andthe 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 forconsultancy services to help PTT prepare adequate safety engineering andenvironmental standards for its entire operation. It was agreed with PTTthat the study for preparation of safety engineering and environmentalstandards would be carried out not later than March 31, 1993 (para. 7.1j).Regarding the institutional framework, PTTIS new organization, effectiveJanuary 1, 1992, includes a safety and environmental committee chaired byPTT's Governor as well as safety and environmental standards divisions ineach business unit. The heads of the environmental standards divisionsreport directly to the presidents of the respective business units.Furthermore, each division has one or more sub-divisions (e.g., forpipeline and gas plants within the natural gas business unit) to enforcethe standards and regulations at the operational level.

F. Prolect ImRlementation and Schedule

3.23 Overall responsibility and control over project implementationwill rest with PTT. PTT has in the past implemented several similarprojects including the construction of the existing 34-inch offshorepipeline financed by the Bank. PTT has appointed Lavalin/Bechtel, aconsortium comprising Lavalin and Bechtel International, both of Canada, toassist in carrying out all stages of the project implementation cycle. Theconsortium members are reputable international engineering firms which havethe experience and expertise for successful execution of the project.Annex 11 shows PTT's organization for project implementation. PTTpersonnel will also be assigned to the project for on-the-job training andother selected tasks.

3.24 PTT's internal schedule cal.ls for completion of the project'sphysical works by December 31, 1993 (Annex 12). This is a challengingtarget which can be achieved with the cooperation and best effort of allconcerned. PTT with assistance from its consultants has instituted acritical path master plan to monitor implementation progress and to reactquickly to actual and potential delays. However, to allow for thepossibility of delays during testing and commissioning, the projectcompletion date is assumed to be June 30, 1994.

3.25 EGAT has already issued the invitation to bid for procurement andinstallation of a 600 MW combined-cycle power plant at Khanom. The 200 MWgas turbine for the first unit will be completed in December 1993, followedwith completion of the second 200 MW unit in April 1994. The 100 MW steamturbine units will be completed one year after the respective gas turbineunits, i.e., December 1994 and April 1995. Annex 12 provides thecompletion schedule for the Khanom combined-cycle power plant.

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G. Project Costs

3.26 The project is estimated to cost tha equivalent of US$348million, including taxes and duties which amount to US$13 million. Foreignexchange costs total US$305.6 million or 88Z of total costs. Table 3.1gives a breakdown of the project cost by major components. Annex 13 givesthe breakdown of annual expenditures. The estimate is expressed in end-1991 prices and is based on actual prices of approximately 68Z of the totalproject cost and on informal but firm quotation for the balance. An 8Xphysical contingency and a 2X price contingency have been added to the basecost estimate. The physical contingency is adequate considering theadvanced stage of project design and the fact that pipeline engineering andconstruction involve few uncertainties. The low price contingency reflectsthe fact that all major procurement is on a fixed price basis, that twomajor contracts have already been awarded, and that most procurement willbe completed by late 1992. Taxes and duties were estimated based on anaverage rate of 40X on all goods subject to such charges. The Governmentrequires PTT to pay taxes and duties only for those project goods whichenter Thailand's 12 mile territorial water zone.

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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 3.0Pipe material (Una pip.) 1970.1 1970.1 - 77.2 77.2 100Pipe coating & Jacketing 668.8 668.6 26.2 26.2 100Pipeline construction 382.8 2424.4 2807.2 15.0 95.0 110.0 88TOTAL equipment 510.4 510.4 - 20.0 20.0 100SCADA/telecom 94.5 168.4 262.9 3.7 6.6 10.3 84Riser platform - 969.8 969.8 38.0 38.0 100Engineerng consultancy 89.3 293.5 382.8 3.5 11.5 15.0 77MIS and training 2.5 23.0 25.5 0.1 0.9 1.0 90Environmental study - 5.1 5.1 - 0.2 0.2 100Second pipeline study 5.1 45.9 51.0 0.2 1.8 2.0 S0Taxes 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 88Price 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 constructionand 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 14Asian Development Bank 8.0 50.0 58.0 16U.S Exim Bank 0.70 6.6 7.3 2Commercial Borrowing \i 10.0 46.0 56.0 15PTT intemal Cash 15.1 76.6 01.7 25IBRD 4.2 t.O 8 .10

Total Financing Required 45.0 325.0 370.0 100

\1 including PTT Bond Issuanco.

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3.28 Total financing required, including interest during construction(estimated at US$22 million based on 8X interest), would amount to US$370million. The proposed Bank loan of US$105 million would be made directlyto PTT at the Bank's standard terms for Thailand. PTT would bear theforeign exchange and variable interest rate risks of its loan, which wouldbe 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 loanwould finance 28Z of the total project financing required and 33% of itsforeign expenditures.

3.29 The financing plan has been developed on the basis of extensivediscussions with PTT, Japan Exim Bank (JEXIM) and the Asian DevelopmentBank (ADB); the JEXIM and ADB representatives participated in both projectpre-appraisal and appraisal. The procurement packages were designed totake into account the various co-lenders' internal requirements, theproject implementation schedule, and PTT's concern regarding its largeexposure to non-dollar hard currency, particularly Japanese yen. The Bankwould finance the engineering consultancy and the line pipe contracts andseveral studies (US$105 million), while ADB and JEXIM would jointlyfinance the pipeline construction contract, and the U.S. Exim Bank wouldfinance part of the the SCADA system. ADB and JEXIM jointly appraised theproject 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 byADB/JEXIM will materialize (both institutions have shown strong interest inlending for the proposed project and both have actively participated in theproject preparation), it was determined at negotiations that cross-defaultand cross-effectiveness of the various loans were unnecessary. In theunlikely event that co-financing will be delayed, PTT is in a healthyfinancial position to fund the project financing gap from its ownresources.

I. Procurement and Disbursement

Procurement

3.31 Procurement arrangements are summarized in Table 3.3 below. Thecost of each procurement item includes its pro-rata share of the project'sphysical and price contingencies.

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Table3 Summary of Procurement Arrangements(US$ Million)

Procuroment MetodsPmlobo Element Jo ,OFr of T01;4

CNI Wods/BuIdIng 33 3.3PIpoline Materals Qing pipe) 85.0 85.0

(85.0) (85.0)Pipe Coaing & Jacketing 28 28.3PipeUno Contuoton 121.2 \a 121.2TOTAL Equipment 22.0 22.0SC4DA/Teleoomm 11.4 \ 11.4Nier platform 41.9 41*Englnooeing Consultanoy 106. 16.6

(16.5) (16MIS 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) 29 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 BankNBF- Not Bank-Fnanced

3.32 The following five single responsibility contracts comprise thebulk 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 underinternational competitive bidding (ICB) in accordance with theBank's procurement guidellnes. Owing to its critical nature, theBank had agreed to advance procurement for this contract;

(b) Engineering consultgncy and project management contract (US$16.5million), a Bank-financed component, the contract for which hasalready been awarded by PTT in accordance with the Bank'sprocurement guidelines for use of consultants by the World BankBorrower;

(c) Coating and jacketing the line pipe (US$28.9 million), thecontract for which is to be awarded to a .1alaysian firm and to befinanced by PTTVs own resources;

(d) Construction of the pipeline (US$121.2 million), the contract forwhich will be awarded in accordance with ADB and JEXIMprocurement procedures; and

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(e) Supply and installation of SCADA and telecommunication facilities(US$11.4 million), the contract for which will be awarded inaccordance with U.S. Exim Bank procurement procedures.

3.33 Equipment, including additional compression capacity (US$22.0million), is needed for PTT's offshore gas pipeline operation. These itemswould be supplied and installed on the Bongkot production platform byTOTAL, the operator of the Bongkot gas field, in accordance with anagreement between PTT and TOTAL. Due to a lack of space on Unocal's Erawanproduction platform, PTT requires a riser platform to support a pipingmanifold to connect the incoming gas flow from the Bongkot field to theexisting 34-inch pipeline to Rayong, as well as the pipeline to Khanom andthe future second pipeline. The riser platform (US$41.9 million) would bedesigned, supplied and installed by Unocal in accordance with arrangementsagreed with PTT. PTT would procure civil works and buildings (US$3.3million) in accordance with its own procurement procedures which aresatisfactory to the Bank. The remaining consultancies included in theproject would be selected and appointed in accordance with the Bank'sguidelines for use of consultants by the World Bank Borrowers.

Disbursement

3.34 The estimated disbursement of the Bank loan is shown in detail inAnnex 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 willbecome effective in the first quarter of the Bank's fiscal year 1993. Itis 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, theclosing date for the loan is set for December 31, 1994. The scheduleddisbursements are faster than the standard profiles for the region and thesubsector, reflecting the advanced stage of project preparation. Phasingof the estimated disbursements of the proposed Bank loan and the Bank'sstandard disbursement profile for the subsector are shown in Annex 14.

3.36 Due to a tight project implementation schedule and the criticalnature of the pipe material in the completion schedule, PTT had to advanceits contract for pipe material. Therefore, retroactive financingequivalent to US$22 million is recommended for expenses incurred afterSeptember 1, 1991, for partial payments for line pipe materials and

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consultancy contracts, for amounts which already have been paid by PTTthrough advanced contracting approved by the Bank. Increasing the level ofretroactive financing from the Bank's normal limit of 10 to about 21X ofthe loan amount is considered acceptable because: (a) the increasedretroactive financing is required for progress payments on the pipelineoontract which has been approved in advance by the Bank; and (b) theretroactive financing will be for expenditures incurred within theallowable 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 outlinedin Table 3.5 below:

Table 3.5: Allocation of the Proposed Bank Loan(US$ million)

Percentage ofUS$ Million expenditures financed

Pipeline Materials 85.0 100l of foreign expendituresConsultancy services 16.5 1002 of expendituresTraining, studies, 3.5 10OZ of expendituresMIS

Total 105.0

3.38 Reimbursement for goods, services and training valued at lessthan 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 availablefor review by Bank supervision missions. All other disbursements would bemade against full documentation. To the extent possible, withradawalapplications should be consolidated into amount of US$1.0 millionequivalent 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 interms of physical execution and financial reporting to ensure that allconditions of the proposed loan are satisfied. For this purpose the Bankwould, on average, field two supervision missions per year, during theactive project phase to review project implementation, inspect job-siteactivities and discuss, as required, any related matters with Governmentand PTT officials. In addition, PTT would be required to forward periodicprogress reports. During negotiations, agreement was reached with PTTregarding the format, content and frequency of these reports (para. 7.1e).The basic requirement would be quarterly progress reports for each

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applicable project component and PTTVs semi-annual and annual financial andauditors reports as defined in para. 4.14.

3.40 Project supervision by the Bank would be coordinated through asupervision plan to be confirmed during loan negotiations. Bank fieldsupervision would require a total of about 24 staff-weeks during the lifeof the project, of which about 14 staff-weeks would be required during thefirst two years of project implementation. Supervision would be carriedout mainly by Bank technical and financial staff, including anenvironmental specialist.

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IV. THE BRROWE

A. hackground

4.1 The Borrower of the proposed loan would be the PetroleumAuthority of Thailand (PTT), which was established in December 1978 by thePetroleum Authority of Thailand Act and became operational in July 1979.mT's objective is to engage in and promote petroleum and petrochemicalactivities. It was formed by the transfer of operations from twopreviously existing state ent6prprises: the Natural Gas Organization ofThailand and the Oil Fuel Organization. It is wholly owned by the Kingdomof Thailand and comes under the direct jurisdiction of the Ministry ofIndustry.

4.2 While PTT focuses primarily on gas transmission and petroleumproducts refining and marketing, it also is involved in upstream operationsthrough PTT Exploration and Production Co., Ltd. (PTTEP), a wholly-ownedsubsidiary company which was established to handle petroleum explorationand production activities. PTT is a statutory body which, because of atechnicality in the Thai petroleum law, cannot co-venture with privateproduction companies. It does, however, participate in joint venturesthrough PTTEP which, as a limited company, can legally be the co-venturer.PrTEP's accounts are kept separate from those of PTT to ensure properidentification of exploration and production expenditures.

4.3 PTT has entered into joint venture agreements for downstreamoperations and holds shares in two refineries --the Thai Oil CompanyRefinery (491) and t'ne Bangchak Petroleum Co. Ltd. (301)-- and in theNational Petrochemical Corporation (49X), the National FertilizerCorporation (21X), Thai LNG Co. (101), Bangkok Aviation Fuel Services(101), Intoplane Services Compnny (171), Thai Olefins Company (401) and theAromatics (Thailand) Company (251). In 1991, PTT invested in two new jointventures, buying a 25.5Z share in the Thai Petroleum Pipeline Co. Ltd. anda 10 share in the Fuel Pipeline Transportation Co., Ltd.

B. Organization

4.4 PTT is a well-run state enterprise, capable of managing thesubstantial growth in investment, exploration and production, and salesexpected over the project period. It functions as a modern organizationand enjoys a considerable degree of autonomy in its day-to-day operations.Although decisions concerning the investment plan and financing remainsubject to government approval, PTT has essentially been deregulated andmanagement makes the key operating decisions (para. 4.5). PTT'soperational and policy decisions are made by a Board of Directors, whichconsists of a Chairman and 11 other members, including the Governor. Withthe exception of the Governor, the Board members, who are appointed by theCouncil of Ministers, act in a part-time capacity. The Directors include

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representatives from the Ministries of Defense, Finance, Commerce,Industry, Transport and Communications and the Juridical Council. PTT alsohas an executive committee, comprising the Chairman of the Board and fiveDirectors. The executive committee meets frequently and is empowered tomake decisions on certain investments, contracts, staffing and otheroperational matters.

4.5 While PTT has in the past operated under the constraints typicalof government enterprises in Thailand, it has recently been designated forderegulation under a Ministry of Finance directive which allows greaterautonomy for those government-owned enterprises which meet certainefficiency criteria. As of fiscal year 1992, PTT's procurement,organizational structure, and administrative controls are no longerregulated, and salaries and benefits are no longer limited by schedulesapplicable to state enterprise. The major areas remaining under governmentsupervision are the capital investment plan, which is subject to NESDBapproval, and the financing of investments, which is reviewed by theMinistry of Finance.

4.6 As of January 1, 1992, PTT was reorganized on a profit centerbasis, with four separate buliness units reporting to the PTT Governor (theattached chart shows the company's organizational structure). The businessunits are as follows: (a) the downstream oil companies (includinglogistics and transportation, refining and marketing); (b) the natural gasactivities; (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 thesefunctions relevant to individual operating units are decentralized intoeach of the five business units. It is intended that the individualbusiness units will function autonomously, and that the reorganization willprepare PTT for an eventual privatization in which the individual businessunits 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-end1991, has remained relatively constant over the past five years, with verylittle growth ln that period. The management and staff are competent andwell qualifict. About 62Z of the staff have received some form of higheroducation. About 371 are temporary staff, largely in unskilled positions.Since most construction ls contracted out on a turnkey basis, the PTT staffdoes not include construction workers.

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Tabl S.1: PST STAllING EVCLUSIO

Increase1986-91

FY86 FY87 FY88 FY89 FY90 FY91 X p.a.

UniversLty graduates 1,023 1.161 1,239 1.398 1,361 1,364 5.92Dlploa *ad higher

professanalt educatton 435 447 434 438 497 498 2.74BHgher 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, PTThas suffered a "brain drain" of experienced technical personnel leaving thecompany to take mora lucrative private sector jobs. Under the system inplace through FY91, PTT had been obliged to use the government salary scalepublished by the Ministry of Finance for all public enterprises. FortechnLcal employees, that scale was considerably lower than the privatesector compensation levels for comparatle jobs. PTT s pay scale wastherefore not sufficient to retain trained engineers, computer specialists,accountants and financial experts, chemists, geophysicists, and otherscientists. With the recent deregulation, PTT has been freed from theconstraints of that salary structure, and it anticipates that, with its newautonomy on salary and other personnel matters, it will be able to competemore effectively with private sector companies. As of October 1, 1991, PTTincreased its salaries by an average 25X, with the increases allocatedlargely to technical and financial personnel. PTT plans to adjust thecompensation of these employees so that after a three year period, mostsalaries would be within 801 of commercial levels.

4.9 Training falls under the overall responsibility of the PersonnelAdministration Department, and focuses on both the management and technicalactivities of PTT. In addition to significant in-house training programs,PTT sends employees to outside training courses, both in Thailand andabroad. In 1991, nearly 200 PTT employees attended training programsoverseas.

4.10 PTT has a good record in project cost control, implementation andmanagement. It has been borrowing from the Bank since its inception and isvery familiar with the Bank's procurement guidelines. Processing oftenders and award of contracts are undertaken equitably and expeditiously.

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D. Operation and ManagementAccounting

4.11 PTT's accounting system conforms to modern oil anu gas industrypractices. PTT maintains separate accounts for each of its majoractivities. The natural gas financial accounts are modelled on U.S. gasindustry principles, and accounts have been satisfactorily prepared for allaspects of PTT's operations. Accounting applications such as generalledgers, payroll, inventory transactions, accounts payable, and accountsreceivable have been fully computerized. PTT prepares annual budgets forits capital and operating expenditures; it also prepares five-yearforecasts for financial planning purposes. Periodically, reports areprepared enabling management to compare actual results against budgetedamounts. The budget process has been operating satisfactorily.

4.12 PTT's billing and collection system is adequate. Accountsreceivable are an average of 45 days of sales, which is consistent with agovernment regulation requiring all state enterprises to collectreceivables within 60 days.

Audit

4.13 PTT has an Office of Internal Audit with a staff of approximately40 auditors. The Office of Internal Audit is an effective management toolfor PTT. Its responsibilities cover audits of PTT's accounting andfinancial functions, computer systems and programs, and operation systems.The tasks outlined to be performed by the Internal Audit Office seemappropriate. However, the Office could be strengthened by an increase instaff. Although the scope of work for audit of PTT operations isappropriate, because of the shortage of engineers on the staff of the AuditOffice, it has not been possible for all of the operations to be auditedeach year. Rather, some sites have been audited only every few years. Inaddition, it is important Xhat, as shown in the new PTT organization+,structure effective January 1, 1992, the Office report directly to tf.,UGovernor (it previously reported to the Deputy Governor for SpecialAffairs). This will empower the Internal Audit Office and help itsrecommendations to be taken more seriously. Accordingly, assurances weregiven at negotiations that not later than September 30, 1992, the InternalAudit Office will report directly to the Governor, and that the budget andstaff allocation of the Office will be changed to provide for three moreengineers, to be in-place not later than March 31, 1993, bringing the totalnumber of engineers on the Office's staff to six (para. 7.2). This willenable the work to be completed as recommended.

4.14 PTT's external audit has in the past been performed solely by theOffice of the Auditor General, the government organization responsible forauditing all state enterprises. While the performance of the Office of theAuditor General has been satisfactory, it is desirable that as PTT takessteps towards corporatization and potential privatization, it should alsobe audited by a private sector auditing firm. Accordingly, agreement wasreached during negotiations that PTT in the future will be audited inaccordance with the generally accepted accounting principles by a private

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independent auditor acceptable to the Bank and PTT, and that PTT willsubmit to the Bank its audited annual financial statements within sixmonths of the close of each fiscal year (para. 7.lf).

Insurance

4.15 PTT carries insurance against loss or damage which could causeserious financial harm, and otherwise tries to limit its risks through aninternal risk management system. It protects itself through all riskinsurance, which provides coverage against property damage on majorproperties and any subsequent business interruption, protection againstthird party legal liabilities, protection of cargoes and against delays ordamage in transportation, and protection against any catastrophic loss.The insurance is provided through the Dhipaya Insurance Co. Ltd., a stateenterprise which reports to the Ministry of Finance. Most of the risksagainst which PTT is insured are in turn transferred to the reinsurancemarket through the Sedgwick Energy Group, London. PTT would continue tomake these provisions, which are satisfactory to the Bank, to provideinsurance against risks and in amounts consistent with appropriatepractice.

Taxes

4.16 PTT is required to remit a portion of its net income to theGovernment 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 isexpected 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 andmaterials for PTT projects have in the past been covered by the Governmentin the form of equity contributions. Ho-7ever, the Government has notagreed to PTT's requests for assuring similar concessions for projects inthe future. Duties and taxes are therefore expected to be met from PTT'sown resources.

Management Information System

4.18 The Management Information System (MIS) of PTT consists of sixseparate systems, some of which were inherited from PTT's parentorganizations. These systems include the SCADA system which monitors theoperation of the gas separation plant and pipeline systems, a finance andaccounting system, a management information system, a marketing system, andtwo data systems -- one for oil and one for gas. These systems will needto be adapted to PTT's new organization and they also should be integrated.Integration of the systems would facilitate the transfer of informationfrom one function to another, both making access to information moreimmediate and establishing the communication links which would encouragecloser integration of PTT's various departments.

4.19 Integration of the systems and adaptation of the MIS for theproposed organizational structure would most appropriately be done by

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outside consultants since the MIS Department of PTT has neither sufficientstaff nor the specific expertise to accomplish the scope of work required.A consultancy contract, the first phase of which would cost approximatelyUS$1 million, would te required to complete the assignment, and has beenincluded in the proposed project. The study will be carried out not laterthan December 31, 1992 (para. 7.1j). EssenLially, the first phase of theconsultancy service would involve identifying how PTT's existing computersystems and those currently under development should operate under the neworganizational structure implemented January 1, 1992. It would includeupdating the MIS master plan, which would be implemented over the next fiveyears. This would involve developing a high level data model as a basisfor identifying the total integration needs relating to PTT's data andsystems; it would also involve an assessment of PTT's hardware needs. Inaddition, the consultant would propose the optimal structure and staffingplan for PTT's MIS department.

Research and Development

4.20 PTT's Research and Development Unit is a part of the GeneralService Unit under the Vice-President for Technical Services. Although todate PTT's research and development efforts have centered on the marketingof petroleum products and on pollution reduction, an important future goalis to develop new applications and uses for natural gas. This wouldinclude developing residential/commercial uses for natural gas, natural gasuse in the transport sector, and the cogeneration of electric power.

4.21 In the residential/commercial sector, PTT plans to investigatethe use of natural gas for such purposes as air conditioning, and it hopesto improve the efficiency of gas appliances. Technological assistance willbe sought from major gas utilities such as British Gas, Osaka Gas and TokyoGas. With regard to the transport sector, an active program is in placefor developing compressed natural gas (CNG) as a motor fuel, especially asa substitute for diesel oil. The government has approved the purchase, bythe Bangkok Mass Transportation Authority (BMTA), of 200 buses especiallydesigned to operate on CNG. The buses are expected to be operational in1993. If results are encouraging, the BMTA may eventually replace itsentire 2,000 bus fleet by CNG-powered units. PTT is currentlyexperimenting with two diesel engine buses running on CNG, and it isdeveloping CNG fueling stations. Research and development activities withregard to co-generation will initially focus on evaluating the technical,financial and economic feasibility of using cogeneration to produceelectricity for use in the gas separation plants.

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V. FINANCIAL ANALYSIS

A. Past Performance

5.1 PTT's performance for the period FY86-90 is summarized in Table5.1. Detailed statements are given in Annex 15.

Table 5.1: SUMMARY OF PTT's FINANCIAL OPERATING STATISTICS, FY86-90(Debt million)

Fiscal year endingSeptember 30 1986 1987 1988 1989 1990

Revenues 38,578 38,561 41,357 45,744 58,047Cost of Sales 32,368 33,009 34,725 39,570 49,427Adininstrative Expenses 1,396 1,068 1,259 1,250 2,284Depreclation 1,124 1,003 1,173 1,271 1,380Total Operating Ezpenses 36,354 36,167 38.318 43,243 54,942Interest Expens* 1290 1,294 1,200 1,382 1,286Operating Incoam 2,224 2,394 3,039 2,501 3,106Not Income 528 717 966 705 1,411

Accounts Receivable 4,668 4,882 5.705 6,541 8.336Total Current Assets 11,957 12,748 12,259 14.362 17,954Fixed Assets 21,534 22,521 23,940 24,873 27,111Average Hot Fixed Assets 20,557 21,269 22,482 23.668 23,818Total Assets 35,608 37,677 39,890 42,663 50,449

Current Liabilities 7,185 7,845 7,491 8,068 12,123Long-Term Loans (Not) 16,494 16,156 16,292 16,320 16,302Total Long-Tern Liabilities 17,059 16,469 16,414 16,331 16,309Total Equity 11,363 13,363 15,986 18,264 22,017

Primary Ratios:Rate of Return (M) 11 11 14 11 13Debt service coverage

(times) 4.1 2.2 1.2 0.9 4.1Operating ratio CZ) 94 94 93 95 95Current ratio 1.7 1.6 1.6 1.8 1,5Long term debt as S of totalCapitalization 59 55 50 47 43SeLf-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 cannotbe properly calculated.

5.2 During the period FY86-90, PTT's revenue increased from B 38,578million to B 58,047 million--at an average annual growth rate of nearly11. The revenue growth was particularly dramatic in FY90, when salesincreased by 26X over the FY89 level. This was the result of a substantialincrease in PTT's revenues from oil operations. Sales volume of petroleumproducts increased from 4,770 million liters in 1989 to 6,827 millionliters in 1990, for a gain of 43Z. This resulted in PTT's increasing itsshare of the total market from 261 in 1989 to 301 in 1990. To a largeextent, PTT's operating income and net income rose with sales through theFY86-90 period. The one exception to this trend was FY89, when bothoperating income and net income declined. This reduction in income in 1989

- 40 -

occurred primarily because PTTs gas separation plant was forced to shutdown for 124 days (as opposed to 33 days in 1988) when mercury was found inthe cold box. The plant outage resulted in a 44X increase in PTT's refinedproduct imports.

5.3 During the past five years, PTT has been a strong financialperformer. This is primarily indicated in its rate of return (ROR) on netrevalued assets in operation, which has remained at or above 11 during theperiod. <(Assets were revalued using government-published inflation indicesfor fixed assets.) Due largely to the unevenness of debt repaymentobligations, PTT's self-financing ratio (SFR) has been volatile. Indeed,in FY88 and FY89 PTT's total debt service was larger than its internal cashgeneration reduced by the increase in non-cash working capital. Afterbeing negative for two years, PTT's self-financing ratio (which was 731 inFY88 and 35X in FY89) then jumped to 1281 in FY90. This dramatic swing inthe SFR was primarily caused by a 971 drop in PTT's long-term loanrepayment obligation, from B 4,081 million in FY89 to B 126 million inFY90. PTT financed its debt service obligations primarily through areduction in cash. While it will be important for PTT to smooth out itsfuture long-term loan repayment schedule (para. 5.4), it is notable thatduring the FY86-90 period, PTT financed 421 of its total capital investmentprogram with internally-generated funds (Table 5.2). Also, it willcontinue to be advisable for PTT to re-finance some of its debt to lengthenmaturities 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 solong as the term of the debt, including the refinanced portion, does notexceed 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 180Less: 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 46Lose 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-tezloans 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 hasbeen expanded substantially by the appreciation of the Japanese yen, thecurrency in which about 30X of PTT's debt is denominated (para. 5.6). Anuneven debt repayment schedule (para. 5.3), exacerbated by mushroomingforeign exchange losses (at year end FY90, the total unrealized exchangeloss on the revaluation of loans for completed projects was B 2,888million), caused PTT's debt service coverage ratio to drop to 0.9 times inFY89. However, PTT is a financially sound organization. Its debt servicecoverage ratio averaged 2.3 times during the FY86-90 period and was 4.1times in FY90. PTT's capital structure remains satisfactory (long-termdebt was less than 601 of total capital throughout the five years, fallingfrom 591 in FY86 to 431 in FY90). To avoid erratic financial performance,PTT should in the future consider arranging a more level debt repaymentschedule or plan debt refinancing to lengthen loan terms so that theycorrespond 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, witha self-financing ratio of 1211, an ROR of 131, and a debt service coverageof 4.1 times. These robust ratios were caused in part by a substantialsales increase of 341 in FY91 (this on top of the ample 261 increase ofFY90): operating income increased by 571 over FY90's level; net income wentup by 1311. They are also reflections of the uneven capital investmentprogram and debt service obligations of PTT. Capital investment in FY91amounted to only B 3,113 million, which was a decline of 461 from the FY90level, and the debt service requirement, at B 2,028 million, was 341 lowerthan the average of the previous five years. The ratios have, however,given PTT a strong balance sheet which positions it well for its futureoperations. As of September 30, 1991, PTT's debt to total capitalizationratio was 341 and its current ratio was 1.8 times; accordingly, PTT is in astrong position to take on the expanded capital investment program which isanticipated for the next few years.

5.6 Although PTT's FY91 debt to total capitalization ratio is low enoughto give PTT ample flexibility (para. 5.5), PTT nevertheless has significantforeign exchange losses: its debt has been expanded by about 201 due tocurrency fluctuations. As of September 30, 1991, PTT had long-term debt(net of current maturities) of B 15,480 million, of which about 301 wasdenominated in Japanese yen. Since the Baht has weakened substantiallyagainst the yen, PTT had incurred foreign exchange losses of B 2,606million. A 1986 Ministry of Finance directive required all. stateenterprises to revalue foreign currency loans as of September 30 of eachyear, and spread the loss over the remaining term of the loans. PTT treatsits foreign exchange loss in accordance with this policy. The policy isnot in compliance with Generally Accepted Accounting Principles, whichprovide that except in the case of devaluation, the foreign exchange lossshould be written off each vear as it occurs. However, because the yentends to both appreciate and depreciate against the dollar (the currency towhich the Baht is essentially tied), the Thai Government policy provides a

- 42 -

smoothing effect which the Bank mission determined to be acceptable. Whilethe Thai foreign exchange accounting policy would not be appropriate in anenvironment in which the local currency always depreciated against theforeign currencies, it is acceptable in the Thai context and in factprecludes the wide swings in earnings which would result if foreignexchange losses were written off year by year as they occurred.

C. Financial Outlook

5.7 PTT's healthy financial performance is projected to continuethroughout the next five years. The challenge for PTT in the near-termwill be to assimilate and finance the expected sizeable expansions in itscapital investment. Its current financial strength should allow it to dothis without excessive difficulty. Key indicators of PTT's financialperformance for the period FY91-96 are presented in Table 5.3, and detailedprojections 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 1996Revenuas 77,357 79,945 88,994 104,756 125,697 139,925Coat of Sales 65,775 69,076 77,446 91,347 110,000 122,405Administrative Expenses 2,194 2,367 2,859 3,330 3,795 4,262Depreciation 1,566 1,496 1,568 2,284 2,597 2,803Total Operating Expenses/a 72,489 75,653 84,423 99,507 119.448 133,178Interest Exponse 1,206 1,245 2,207 3,063 3,508 3,151Operating 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 14,739Total Current Assets 20,676 20,744 22,846 25,795 29,932 34,772Investments in Subs. and Affiliates 5,276 8,308 11,115 15,017 17,398 17,713Property, Plant end Equip. (Net) 27,201 26,644 29,698 39,666 41,720 60,020Averago Not Fixed Assets 25,464 26,923 28,171 34,682 40,693 50,870Total 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 18,608Long-Term Loens (Net) 15,480 20,050 29,645 42,356 49,325 50,923Total 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 15Debt service

coverage (times) 4.1 3.1 2.3 1.8 1.7 1.9Operating ratio (Z),/ 94 96 96 96 96 96Current ratio (times) 1.8 1.7 1.8 1.7 1.8 1.9Debt as Xof 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 foreignexchenge losses

/k On average not revalued fixsd assets 1n operation

- 43 -

5.8 Although PTT's sales revenues are expected to increase only 3.41in FY92, sales growth for the FY92-96 period is projected to be 151 peryear. Most of this increase is in the sales volume of petroleum products,which are expected to grow on average 14X per annum. Petroleum prices areforecast to remain fairly steady through the five-year period. Total gasflow is expected to increase at a slower rate, averaging 4X per year: theincrease would come from gas flowing through the proposed pipeline. Gasprices for existing gas are forecast to remain fairly constant; prices forgas flowing through the proposed Bongkot Pipeline, beginning in 1994, areprojected to be about 161 higher than for the for existing flows. (Furtherinformation regarding these assumptions is included in Annex 16 and isprovided in greater detall in the project file). PTT's net income isprojected to decrease through FY94. This is due largely to increases ininterest expense in FY93 and FY94 (resulting from the incremental debtrequired to finance PTT's expanding capital investment plan: PTT's totaldebt 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 andremain at that level throughout the projected period. The ROR is projectedto 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 indexpublished by the Ministry of Finance, will increase at about 171 p.a. fromB 27,201 million in FY91 to B 60,020 million in FY96.

5.9 Due to PTT's expected continued high level of profitability, itsself-financing ratio over the medium term is forecast to remain at healthyA'S is. Except in FY93 (when internal cash generation will not besufficient to cover the projected higher interest expenses and stillcontribute 251 toward the substantial capital investment program), theratio will range between 251 and 381. The SFR is projected to be about 161in FY93. Agreement was reached at negotiations that, except in 1993, PTTwould generate funds from internal sources equivalent to not less than 251of the annual average of its capital expenditures incurred, or expected tobe incurred, for that fiscal year, the previous fiscal year, and the nextfollowing fiscal year. For its fiscal year ending in September 30, 1993,PTT would generate funds from internal sources equivalent to not less than151 of the annual average of its capital expenditures (para. 7.lg).

5.10 PTT's capital structure is projected to remain satisfactorythroughout the FY92-96 period. The debt to total capital ratio is expectedto average 501 and remain at or below 551 on a revalued asset basis. Thedebt service coverage ratio is estimated to range between 1.7 and 3.1 timesthroughout the projected period. Agreement was reached at negotiationsthat PTT's debt-equity ratio (calculated after the revaluation of PTT'sassets) will not exceed 60/40 and that its debt service coverage ratio willbe at least 1.3 times. Debt refinancing would not be included as repaymentof debt for debt service ratio calculation purposes so long as the term ofthe debt, including the refinanced portion, does not exceed 801 of theuseful life of the assets financed by that debt. Indeed, such refinancingsare encouraged as a way for PTT to smooth its schedule of debt serviceobligations (para. 7.lh).

- 44 -

D. Investment Prok * and Financing Plan

5.11 Annex 17 provides PTT's FY92-FY96 Investment program, whichamounts to about US$2.3 billion. The investment program was reviewed bythe Bank mission and the necessary adjustments were made to provlde for amore realistic implementation schedule. It was agreed that the Bank wouldwork closely with PTT in developing future investment programs and coherentpoli^ies for PTT's joint-venture participation. The Bank and PTT haveagreed that the Bank should be consulted about the revisions andpreparation of PTT's long-term investment plan in order to make moreefficient use of capital resources in the gas sector (para. 3.2). Duringnegotiations, agreement was reached on annual review of PTT's investmentprogram by the Bank, with PTT required to take into account the Bank'scomments (para 7.1i).

5.12 A financing plan for PTT over the project period (FY92-96) ispresented 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 74Leas: 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 75Less Inereas/Add doorease in cash 396 16 1Other (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 theFY92-96 period. The proposed Bank loan of US$105 million is expected tomeet about 41 of mT's total financing requirements for the perlod. Duringthe FY92-96 period, PTT expects to meet 251 of its total capitalrequirements from internally generated funds.

5.14 Borrowings from external sources amount to 751 of PTT'sfinancing requirements for FY92-96. ITT's sources of foreign borrowingsare expected to be the Bank (with its 17 year term, 4 year grace period,

- 45 -

and interest rate of approximately 7X), the Overseas Economic CooperationFund of Japan (with a 30 year term, 10 years of grace, and 2.5X interestrate), the Japan Export-Import Bank (with a 15. year term, 5 years of graceand approxiartely 71 interest rate), and foreign commercial banks(typically with 10 year terms, 2 years of grace, and pricing atapproximately London Interbank Offered Rate (LIBOR). PTT expects to raisefunds locally by issuing bonds and by borrowing from local commercialbanks.

- 46 -

VI. JUSTIFICATION AND RISKS

A. Economic Benefits

6.1 Projected supply and demand of natural gas indicate thatbeginning in 1993-94 and continuing through the life of the proposedproject, Thailand will be facing a deficit in gas supply (para. 2.14). TheGovernment policy to cope with the deficit would be to adjust the supply toEGAT, by far the largest consumer of gas, while providing other existingconsumers with their full gas requirements. The economic viability of theproposed gas project should be assessed based on the economic position ofnatural 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 andignoring its environmental externalities, would not be sufficient to supplythe fuel needed for the incremental power demand during the 1990s; (b)natural gas; (c) imported coal; and (d) imported fuel oil. EGAT's analysisindicates that natural gas utilized in the combined-cycle power plantrepresents the least-cost fuel for power generation (para. 2.16).

6.2 Although the economic viability of gas supply is demonstrated bythe priority ranking of the gas option in EGAT's least-cost developmentplan, the internal economic rate of return (IERR) of the proposed projectshould be calculated based on its incremental costs and benefits. Theincremental costs include: (a) capital and operation and maintenance (O&)costs of gas development and production; and (b) capital and O&M costs ofgas transmission. The gas development and production costs are estimatedbased on the planned schedule of drilling and installation of the requiredfacilities by the gas producers to produce 1.5 tcf of gas. These estimatedcosts, both capital and O&M, are investment-grade estimates and highlyreliable because they have been submitted as part of the Gas SalesAgreement for the "Definitive Cost" of the field development and productionplan (para. 3.8). The estimates have also been verified by DeGoyler andMacNaughton. The capital cost of the proposed project is based on PTTconsultant's estimate, representing the construction cost of pipelinesystems connecting the Bongkot field to Erawan platform, and the Erawanplatform to Khanom. The project cost estimate is now confirmed by actualbids and quotations received from the suppliers for various projectcomponents. The O& cost for the project is assumed at 3X of the capitalcost.

6.3 The incremental benefit of the proposed project is estimatedbased on the economic value of marginal gas supply. The marginal economicvalue consists of: (a) the netback value of gas used in EGAT's combined-cycle power plants; namely, the value of fuels (mainly fuel oil) displacedby gas, corrected for the differential in thermal efficiency; and (b) thenet value of liquids extracted from the raw gas prior co its being used forpower 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 ofreturn Is largely due to: (a) the value of condensate (gas liquids) whichis produced in association with the gas and sold in international marketsfor almost the same price as crude oil; and (b) the high efficiency ofnatural gas in combined-cycle power plants.

6.5 The analysis of the sensitivity of the IERR to the underlylngassumptions indicate that if the capital and O&M co. ;s increase by 10, theIERR decreases only by 31. Hence, the project would have to incurexceptionally high development and production costs (the main project riskdue to complex reservoir geology), in order to render the projectuneconomic. 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 conservativein that the price of fuel oil is assumed to be 801 of the crude oil priceprojected by the Bank. Historically, the fuel oil price in the Singaporemarket has hovered around 85-95X of the crude oil prices. Furthermore, itis assumed that the total volume of gas which will be produced from theBongkot field would be limited to 1,500 bcf, namely the contractualreserve. The more likely scenario is that at least 1,750 bcf of gas willbe produced from the Bongkot field. The IERR was also tested assuming thatthe gas would displace the fuel oil on a Btu-Btu basis, hence discardingthe thermal-efficiency value of the gas in power generation. The IERRcalculated on this basis is 141.

6.7 The financial rate of return calculated is 161. Annex 18 alsoshows the detailed calculation of the project's financial rate of return.This calculation is based on the capital and operating cost estimatescontained in the project cost table, including taxes and duties. Althoughthe Gas Sales Agreement between PTT and EGAT does not provide for a firmprice for the Bongkot gas, which comes on stream in 1994, PTT intends toseek a price for this gas from EGAT which would cover its costs and whichwould yield a reasonable (121) return on its investment. PTT is currentlycontemplating a price of Baht 80-82 per mmbtu, based on the present costestimate of the project. The final price of the Bongkot gas to EGAT willbe decided in 1993, when the project costs are more accurately established.

B. Environmental Benefits

6.8 An added benefit of the proposed gas infrastructure investmentsis the major contribution natural gas will make toward mitigating theimpact of energy use on the quality of the environment. Without theproposed 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 aclean and low-polluting fuel; its expanded availability particularly in theBangkok area (and progressively in other parts of the country) will lead toa significant improvement in air quality in these areas by reducingemissions of, inter alia, S02 and particulates (para. 3.17). The new gas-fired power plants will in effect substitute for fuel oil or coal-firedstations. Based on the fuel substitution, the project is expected toreduce emissions of S02 by about 45,000 tons each year. The project wouldalso result in a net reduction in CO2 production by 2-3 million tonsannually.

C. Risks

6.9 Risks for the project revolve around two areas: (a) theavailability of sufficient gas reserves; and (b) the costs of producingsuch reserve. The gas reserves have been assessed and certified byDeGolyer and MacNaughton, which is pre-eminent in the field of reservesestimation, to exceed 1.5 tcf, the volume on which the proposed project isbased. The risk of insufficient gas reserves is therefore low. The risksassociated with a potential increase in production costs stem from thecomplex nature of the reservoirs, in that the volume of gas is distributedin numerous small reservoirs, requiring a larger number of platforms andwells than would otherwise be expected. This risk has been mitigated bytaking 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 PTTduring the negotiations:

(a) That PTT shall, prior to entering into any amendment to theGas Sale Agreement (between PTT and EGAT) or the GasPurchase Agreement (between PTT and Gas Producers) --amendments which shall be considered by the Bank and PTT asaffecting PT-'s ability to perform under the LoanAgreement-- exchange views with the Bank, and shall takethe Bank's views and recommendations into consideration indeciding whether or not to enter into such amendment. Itwas further agreed that amendments that would be consideredas affecting the ability of PTT to perform under the LoanAgreement are those dealing with the: (i) quantity of gasto be purchased by or sold to PTT; (ii) price of gas soldto or purchased by PTT; and (iii) duration of theagreements (para. 3.10);

(b) That PTT shall furnish to the Bank not later than December31, 1992, for its review and comments, a report containingthe results of the inspection test, evaluating theoperating condition of the existing 34-inch pipeline; andthat PTT take into account the Bank's comments and thepertinent recommendations of the inspection reportregarding the operation of the pipeline (para. 3.13);

(c) That PTT shall take all measures required on its part toensure full implementation of the action plan and theassociated monitoring activities contained in theEnvironmental Assessment Report (para. 3.17);

(d) That PTT shall, not later than December 31, 1992, furnishto the Bank for its review and comments, an audit report ofthe safety of PTT's operations and take all measuresrequired on its part to ensure implementation of thereport's recommendations taking into consideration theBank's comments (para. 3.21);

(e) That PTT shall furnish to the Bank during each fiscal yearuntil completion of the project, commencing November 1,1992, a quarterly progress reports on the physical progressof the project (para. 3.39);

(f) That PTT would be audited, in addition to the Office of theAuditor General, by a private independent external auditoracceptable to the Bank and PTT, and that it would submit

- 50 -

to the Bank, audited annual financial statements within sixmonths of the close of each fiscal year (para. 4.14);

(g) That except in 1993, PTT would generate funds from internalsources equivalent to not less than 25Z of the annualaverage of its capital expenditures incurred, or expectedto be incurred, for that fiscal year, the previous fiscalyear, and the next following fiscal year. For 1993, theinternal cash generation would be 15X (para. 5.9);

(h) That PTTIs debt-equity ratio (calculated after therevaluation of PTT's assets) would not exceed 60/40, andthat it would have a debt service coverage ratio of atleast 1.3 times. Debt refinancing would not be included asrepayment of debt for debt service ratio calculationpurposes so long as the term of the debt, including therefinanced portion, does not exceed 80X of the useful lifeof the assets financed by that debt (para. 5.10);

(i) That PTT and the Bank, not later than December 31 of eachfiscal year until the completion of the project, commencingin 1992, shall carry out a joint review of PTT's investmentprogram for the period FY92 to FY96, PTT paying due regardin each instance to the Bank's comments and recommendations(para. 5.11); and

(j) That PTT engage qualified consultants, under terms ofreference, conditions and timing satisfactory to the Bank,to: (1) not later than October 31, 1992, commence carryingout an engineering study for a new project to transportadditional gas from the Erawan platforms, including thefeasibility of constructing a second pipeline from Erawanto an onshore location in the Central Region (para 3.14);(2) not later than March 31, 1993, commence preparingsafety engineering and environmental standards for itsentire operations (para. 3.22); and (3) not later thanDecember 31, 1992, commence carrying out a study forimproving PTT's Management Information System (para. 4.19).

7.2 During negotiations, .mderstandings were reached that: (a) PTTwould take the necessary measures to hold regular meetings with EGAT atleast every six months in order to coordinate more closely regarding theproper programming of their investment (para. 2.18); and (b) the InternalAudit Office would: (i) not later than September 30, 1992, report directlyto the Governor of PTT, as proposed in the revised organizationalstructure; and (ii) be provided with a budget and staff allocation forrecruiting three additional engineers who would be in place not later thanMarch 31, 1993 (para. 4.13).

- 51 -

B. Recommendation

7.3 With the above agreements and assurance, the proposed projectconstitutes a suitable basis for a Bank loan of US$105 million equivalentto PTT, with the guarantee of the Kingdom of Thailand, at the Bank'sstandard variable interest rate for a 17-year term including a 4 year graceperiod.

- 52- ANNEX-THAILAND

BONGKOT GAS TRANSMISSION PROJECTCommerclal Energy Balance, 1989

(ooo We)

Ind _P n duo 2, 240 4,36.2 479. 96.6Iaiq,uW 247.0 10,340.8 5,6. 513.

1MB. Mwlii Bunk"ta 0.0Stock 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 (02stwiudoONhrsi 3 .4 34Gan wag 0.0Pslom 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 0.0Oleb Huadno 0.0OUwTnrmwln 0.0Own 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 19.248,2R 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 t1884Nan-Malic MIn 341.6 620 6.9 1,072.5TraroflEWIk% &Uaoh. 2L1 11LI 1462MinaOwuwfg S6a 5a8.Food ad Toao 217 39.1 272.0 6608Pow. Pulp aN ProInti 937 61.1 15.W aodd Wood Produrn 31.9 27.9 5.8COmAmujaon 110.3 110.3Taxl md Loom 411.3 303.8 715.1Non-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.1PAN 0.0Anto nal Navloalan 0.0Non-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,O060AwlCuS 1,16L. 7.7 1,67n9Coa. & 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 3a354A7 1 4.72 19,195 ,571 37,406

Aukw 5*c 048 1948A_~ -S

el..

W - ~~~~~~g

o . E I }gg R | ; | igUE~~~~~~.

- CS - g aF

ANNE2dPap 2.1THAILAND

BONGKOT GAS TRANSMISSION PROJECTCommercdal 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" ?ADao_l 4,147 tm 5.410 5,410 6.i16 6,"5s G6M CMS 5.94 G.M 7,@ tMknpow 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.=9LW*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 4.239UV**l 1.314 1.419 1S541 1.66 1.79B 1.942 2.09 12S 2U47 Z843 2-855 &644codS 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 3THAILAND Page 1 of 3

BONGKOT GAS TANSMISSIONPrices of Selected Energy Products

(APt 1,1991)

.*... ......... .. .......... .... ......................... ..................

EX- TAX MAR TtX ET PRZX OtILFUM ITAIL PItCOt0W OtLAPL0 TAXRE?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 0.00EER 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 . 555.09 796.1x-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.SZFtEL600 (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 TAXPRIM2 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 0.00PUEL600 (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 76.75 102.5URIEL2000 CM) 1.9ZS0 0.70JO 0.1736 2.f 04014 3.31 0.00 0.00 0.00lEL2300 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) "07.0Source: PTTTOA lX&CLU)'800

- 56 -ANNEX 3Pa ge 2 of 3

Bongkot Gas Transmission Project

U.sb"h5W LasNM

L W0DNTI&L 7. LWA MANWACr O W O A" b04DG(ai. dmin 3= kw mi Ow)

FlMw s kwh too Bak Exw _aW Z N40 ~ ~ ~ ~ ~ ~~~~~~_ :O LIOa B*WKew 10 kwh 0.70 31kkyou £ 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/kWhNot SW mr Z4 MOMWbadmo 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 VNM 40 kWh u.12 mkK4 230 t L7? U.k/WJ 4a imam ls 20 kw)NSA US kWh LU UWh mma 10 kWh 12.3 5aIbs eoUS kS 21 U./W 0- 1OkWh LU .kkWN4. 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,WLLAWON UUSUU chowe L2. U.k/Wh

Csu. ~ ~ 3dlmiWS kWm.v

Or 10 wh La U.k/kwhAS 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 kWh3 10kWh : LM ./W

JN v.4l 1 of tla KV: *4i W_ 13.45 *.kkW_mm chep 2 0 --W

5 m w ~aq. 3.U. U.k/kWhI 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 3Page 3 of 3

TI.AILANI) . . IBONCKOT 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 0.581PRICE 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 1I 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 35.535I 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 40.25aSOURCE: 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 mostrespects. They were formed as extensional rift basins along highly activelateral fault systems. They are filled with Cenozoic Age clastic sediments(sands, silts, and shales) extending from the Paleocene to Pleistocene. Theenvironment of sedimentation ranges from non-marine lacustrine and fluvialdeltaic to near shore lagoonal and shallow marine with deltaic association. Thebasins are separated by intervening highs where thin Cenozoic sedimentsunconfornably overlie older sediments (Mesozoic and/or Paleozoic Age) and in someareas volcanic terrain or crystalline basement.

2. The fault movements which formed the basins in the Gulf of Thailandpersisted throughout the Cenozoic and affected the concurrent deposition ofsediment. As movement continued on the lateral faults, structural forces Aithlneach basin alternated between compression (uplift and folding) and extension(subsidence and sag). As each of the forces occurred in turn the precedingstructure was overprinted with the latest movements. At present each basin isparadoxically characterized by low relief features (both highs and lows) vhichare highly fulted. An echelon rifts are predominant suggesting that the latestactivity is primarily exte_sional.

3. With respect to hydrocarbons found, the basrins are all gas prone. Theonly significant oll discovered thus far is in the southeastern part of the MalayBMain (offshore peninsular Malaysia) and even in this area gas remains a majorcomponent. Isolated oil discoveries have been made in the Chumpon and Songkhlabasins which are as yet unevaluated. This oil was found in the underlying pro-Cenozoic sediments. Relatively minor oil reservoirs have been encountered in thePattani Trough, notably in the shallower part of the Cenozoic section. Highcrustal heat flow, associated with the lateral faulting appears to have placedthe bulk at the most prospective sedimenta7y interval in the over mature gas/condensate realm. The high heat flow regise interacting with the pro-Cenozoiclimestones (CaCO3) also appears to have produced significant quantities ofcarbon-dioxide gas (CO2 ) which is associated with the hydrocarbon gs.

4. The ten gas fiolds and six as yet unevaluated gas d$scoveries in theThai portion of the Pattani and Malay Basins as well as the approximately ton gasfields and unappraised discoveries in the northwestern part of offshorepeninsular Malaysia (Malay Basin) have strikingly similar characteristics. Thegas is reservoired in sandstones of several types associated with river and rivermouth and shallow marine systems, i e , fluvial-deltaic. In any given areascores to hundreds of reservoirs are productive. Productive reservoirs vary fromjust 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 reservesassociated with high side fault closures and much of the remainder is associatedwith romnant folds within the low (graben) fault blocks. Gas is also trappedstratigraphically in lenticular sand bodies not associated with faulting orcrestal portions of folds but those reserves are somewhat randomly distributedand of lesser significance. The close association between the concentration ofproductive reservoirs and fault closures suggest that: (L) fault planes servedas paths for gas migration during at loast part of their existence; and (ii) thatthe gas source rocks my be pro-Conozoic (this is almost surely the case for thecarbon dioxide gs).

5. The salient points are that the gas fields contain many individualreservoirs of varying size and shape and most individual reservoirs are small.When placed on production each reservoir depletes fairly quickly. Thus in orderto 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 moreindividual reservoirs, workovers and recompletions are rather frequent. Thesefactors make both the cost of development and the cost of production relativelyhigh.

Reserves

6. When considering estimates of gas and liquid reserves discovered todate in the Gulf of Thailand several factors must be kept in mind. The more orless official reserves published by the Department of Mineral Resources (DMM) areprimarily a compilation of the latest reserve data provided by each companyoperating in Thailand who have made discoveries. As such the reserves are nottotally consistent or standardized in the usual manner , .e., API (AmericanPetroleum Institute). However it should be noted that due to the distributionof the reserves In a multitude of small reservoirs without readily definablelisits, roserve calculations are based on statistical occurrence rather thanmeasured quantities, at least prior to significant production history. Thisnecessary approach to reserve estimation is itself at variance with API criteriawhich assumes a degree of measurability. In essence when statistical methods ofestimation are used the distinction between proved and probable reserves isblurred, with proved reserves somewhat loss proved and probable reserves somewhatmore probable than indicated by API standards. The relatively high costassociated with this gas makes reosrve estimates highly price sensitive andhence, somehat subjective. Thus the lack of standarllzed reserves in the DMRannual reports is not as serious as It may seem.

7. Using DH. data, the latest submission by Unocal, and the most recentBongkot field reserve estimate made by DeGolyer and MacNaughton (DM), theestimated reserves of ga and condensate in Thailand are:

- 60 -ANNEX4Page 3 of 4

Offshore - Gulf of ThailandGas Reserves (end-1990)

(bef)

a. Proved and Probable Gas Discovered 8,275b. Produced 1,207c. Remaining - Developed 3,868

Undevelopod 3,200

Subtotal Remaining 7,068

d. Posasble Additions (Discoveries not yetappraised and expected additions toproved and probable reserves) 3,738

Total Discovered and Indicated 12,013

(DMR Data) 12.318

Offshore - Gulf of ThailandCondensate Reserves (end-1990)

(million bbls)

a. Proved and Probable Liquid Discovered 253b. Produced (cond. 44, oil nil) 44c. Remaining - Developed 138

Undeveloped 71

Subtotal Remaining (cond. 194, oil 15) 209

d. Possible additions (Discoveries not yetappraised and expected additions toproved 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 InMalaysian waters.

- 61 - ANNEX 4Page 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/wacfd. 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 cancomfortably be increased to about 950 - cfd based on established remainingreserves (20 year reserve life); (ii) that forecasts of production increraing to1,450 m cfd by the end of the century are reasonable if current discoveries neetspoctations (not dependent on nev discoveries); (iLL) the proportion of liquids

(condensate) declines as fields are depleted; and (iv) the possible or indicatedLiquid reserves are underestimated (more likely) or these reserves contain drier

gas (less liLkely).

THAILAND: BONGKOT GAS TRANSMISSION PROJECT nnex 5PRRSENT COS ?RODUCTION S CONSIPTION

* _.(incffd)'

PEROLEUM AUTHORITY OF THAILAND|I MONTHLY NATUnAL GAS FLOW llEPORT |.

'FATRL SUPPLY TTLt[itt735 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 s199. MS9CfD GiPI ASPII IIYn

fteIUHBI DMII.GS USER gPn 21 -mMscroJ ItY 2 S

91 UMSCOIN r193 _""441---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 - viaETIUWE a!L._TAD*ie".co imui,uu s,w 2,285 i.1

(14 iujlu) ~~~~~~~~~~~~~~~~~PnOPANr.-..JA1..- TOP

ANNEX S

Page 1 Of STHAILAND

BONGKOT GAS TRANSMISSION PROJECTNatural Gas Demandlsupply Profiles 1990-2005

ng or.,~~~~\'- .,

Unoci S65 669 750 700 700 700 700 700 7o0 700 700 700Smoot 0 0 0 0 ISO 200 250 250 250 250 250 250Tl Ohhore 550 9 750 700 850 900 Ka 950 950 950 950 950Em 0 60 6O 60 60 60 60 60 60 60 60 55Tdal 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 0JLA a 0 0 0 0 0 0 0 250 250 250 250 aMYW=ia 0 0 0 0 0 0 0 0 0 0 0 0Tol Impot 0 0 0 0 0 0 0 0 250 250 250 250uS~ ~ - A.'I 7 <;0o T d Wsm w 7 4S t

Fsdsock 79 132 132 132 132 147 204 204 204 204 204 204lndslal Fud 20 59 s8 120 171 240 257 278 300 324 351 435TOM 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% WINEGAT(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 662TOrAL. ;-, 7.6 :"w 083 . .1. 747 167 16 17 1,84 1 ' 1*7 ' 170.3

.

ANEX6Page2oIS

THAILANDBONGKOT 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 iOOuNh 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 101Pq sy 5 C C 6 5 55 C5 CS 65 65 65ChuuIcmlProduct 2 6 10 16 20 24 26 28 32 35 39 50CMSUc&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 1IT _Imw 2 2 3 6 a 6 9 10 11 12 13 17Glum 1 2 3 4 4 6 5 6 6 7 a 10Mew - 2 9 4 5 6 7 a 8 9 10 13Cm" a C.SSC aW lsbIS 1 5 14 28 31 32 35 36 42 47 61 esTO"s 3 4 6 9 11 12 14 15 17 18 23album 1 1 1 23 3 3 4 4 5 5 6TOTALINDUSTWuALviJS. A >fl ' 2 9 K a 7 t ;$taeo /7 . n ..n..rno.. S2 4~-Iii NO AW :

ANNEXS

THAILANDBONGKOT GAS TRANSMISSION PROJECT

Natural Gas Allocaton 1990-2005nwncl)

Unocal 650 729 750 700 70m 700 700 700 700 700 100 700EaksO 0 0 0 0 150 200 0 0 250 20 250 250Tda Crbdwro 550 669 75000 850 00 950 950 250 950 250 050

Mda* O 0 0 0 0 0 0 0 0 0 0 0Jll 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 204kd lalFuel 29 59 es 120 171 203 196 196 300 324 951 429ToW 106 191 220 252 303 350 400 400 504 520 555 633% d &8"y 20A . 2n 3 39 40 40Y 40Y 4244A 50AAval 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 622TOT 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 0 003-5 3x30011 145 132 83 69 95 109 9B 53 34 110 81

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THAILANDiONGKOT GAS TRANSMISSION PIPELINE PROJECT Annex a

System Facilitles and Pipeline

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-68 -A=N 9Page 1 of 4

BONGQOT GAS TRANSMISSION PROJECT

BONGKOT FIELD

1. The Bongkot gas field (formerly called 'B3 structure) will be theprinmry source of gas for the proposed Thailand Gas Transmission System ExpazLsionProject. This field is located ln the northwest extremity of the Malay Basin(all offshore) about 180 km southeast of the Erawan gas field (terminal ofpresent gas pipeline). The 13 Unocal discoveries are located in the southcentral portion of the Pattani Trough. The Pattani Trough and the Malay Basinare 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 grantedin 1972 to Tenneco and British Petroleum. During the next several years Tennecodrilled three exploratory wells and BP drilled one. All four encountered gas andthree of these in quantities indicating potential com _rciality. However, in May1976 the remaining rights and obligations were transferred to Texas PacificThailand, at. al. (TP) by means of farm-in from Tenneco and BP. The first TPexploratory well was completed in November 1976 and was considered a commercialdiscovery (officially the discovery well). TP conducted an appraisal programover the next *ix years (1977-82) in which 18 additional exploratory wells weredrilled and 3-D seismic survey covering 110 kIm was made over what was consideredthe heart of the field. Based on the results of the 23 wells, TP appliod for andreceived a Production Liconse (up to 30 years) from the DMM TP's developmentplan was never accepted by the DK& due to inability to reach agreemnt on a salesprice formula with Texas Pacific. After protracted negotiations an agreement tobuy-back the TIP Production License was reached and consumated in July 1988. Therepurchase price was $100 mm.

3. The Bongkot fiold, as currently defined, is comprlsed of some 20structured highs (14 high saLs fault closures and six renmant fold closures) andintervening saddles over an area of approximately 225 kmI (60 km along NW/SE axisand up to 10 km wide, averaging nearly 4 km). While gas reservoirs areconcentrated on the hLghs, which cover about 40 percent of the total area, theyare not limited to them. This is due to the stratigraphy of the sandstonereservoirs. These are large in number and consist of relatively smalldisconnected bodies deposited in a fluvial to shallow marine, or perhaps1acustrine, environment, l.e. irregularly shaped channel, bar, lagoonal, orcoastal deposits. The 23 wells drilled to date encountered from as little asone to as many as 26 reservoirs with as little as 6 feet to as much as 300 feetof net gas pay. A purely arithmetic average for all 23 wells results in 143 netfact of gas pay in 8.5 reservoirs per well. A total of 22 production tests wereconducted (the remaining reservoirs confirmed by wire line sample tests) andnearly half of these indicated a reservoir boundary withln 500 feet of the wellbore. ThLs data when coupled with the lack of electric log correlation ofreservoir between wells makes it difficult to determine whether any of the 196gas reservolrs penetrated occurred in more than one well. Therefore it can beconcluded that the reservoirs are numerous, each contalns a relatively smallreserve, and are lrregularly distributed and uimappable at present.

- 69 - ANNEX 9Page 2 of 4

4. In order to proceed with development, DeGolyer and MacNaughton werecousissioned to provide a reserve determination for the Bongkot field. D&M hasa long established reputation as an industry leader in the area of reservedetermination. They also know the rather unique situation in Gulf of Thailandfiolds as well, having made four prior reserve estimates for Bongkot and severalfor Unocal. Early difficulties with the original Unocal reserve estimates havehoned 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 irregulardistribution of a large number of reservoirs any calculation of in-place reservesmust be based on statistical occurrence; (b) it was deemed that the number andplacement of available well data when combined with seismic derived structuremaps provided a usable and generally reliable statisti ~al sample; and (c) thatthe recoverable fraction of in-place reserves is cost and price sensitive, sincereservoir distribution limits the reserve quantity per well, requiring a largenumber of platforms and wells in a diminishing returns regime for maximumrecovery. After comprehonsive analysis DWH certifies 2,168.6 Bcf of recoverablegas (1,494.2 Bcf proved and 674.4 Bcf probable additional) in the Bongkotdevelopment area. DUM has excluded those reservoirs where CO2 is excessive.They anticipate that up to 18 platforms and 160 woRlls may be required to achiovethe certified reserves and are estimating 55 percent recovery from 3,973 Bcfproved and probable reserves in-place. This relatively low recovery estimate (60percent to 70 percent is normal) reflects the intensive development -equired andthe economic sensitivity of reserve estimates to both cost and price. D6I hasattempted to be prudently cautious in this respect.

5. The DMR awarded a Production License to the Joint Venture Groupassabled to develop and produce Bongkot gas on the March 15, 1990. The JointVenture (JV) consLsts of Petroleum Authority of Thailand Exploration andProduction (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 areassurrounding 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 foractivity and expenditure. A Development Plan must be submitted for theProduction Areas within eight months (November 1990), which has been met, and aseismic program must be commenced on Reserved Exploration Areas within 24 months(March 1992), contract already signed. It is further required that threeexploratory wells will be drilled prior to the end of the third year of gasproduction (mid-1996).

6. Immedietely following the award of the License, the JV partners enteredinto a participation and operating agreement. In this agreement PTT EP acceptseach of the other parties as co-concessionaire in return for a proportionalpayment of the acquisition cost borne by the DHR in the rep%rchase of TexasPacific rights. Total was elected Operator. The Operator undertakes theresponsibility of preparing the Initial Program (Development Plan and DefinitiveCost Estimate) which must be adopted unanimously after which they will befinancially 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 ManagementCommittee representing all parties with a proportional vote. The development and

- 70 - ANhE 9Page 3 of 4

operating costs will be met by monthly cash calls initiated by the Operator andapproved by the Kan-gement Cou.ittee. Any party(ies) may conduct sole riskoperations. 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 theproduction therefrom; and (c) the installation of additional productionfacilities including platforms, well, etc. Parties may withdraw from the ventureagrooemnt only after completion of the Initial Program. The withdrawal may beaccomplished by party deeding its share proportionally to remaining parties, byplacing interest in trust with the Government of Thailand as trustees, or byselling or otherwise assigning its shares to a new party providing this party isacceptable to the Government of Thailand and is willing to abide by the terms ofParticipation and the Operating Agreement. Except for gross negligence thoOporator is not solely liable for any damages awarded as a consequence of theJoint venture. The Operator is obliged to carry adequate insurance and any awardamounts above insurance limts will be shared by all parties proportionally. TheOperator may be changed any time 95 percent of non-operating parties deemOperator to be negligent. The Operator may resign after giving six months noticeproviding the Initial Program has been completed. Another party to the JV maybo elected Operator should PTTEP decline to act as Operator. Ax.ter the thirdanniversary of gas delivery PTTEP shall have the option to become Operator aftergiving 24 months notice to the other parties (earliest five years after start ofgas sales). It is contemplated the 24 month period would be used to provide asmooth transition from the current Operator (Total) to the new Operator (PTTEP).

7. The Develcpment Program for the Bongkot fiold is designed to producea minimum 1500 Bcf over the life of the Gas Sales contract between the JV andPTT. Further the sales contract provides that a minimum production level of150 - cfd shall be maintained for the first five years of production wlthsubsequent 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 theCO2 fraction will not exceed 23 percent of pipeline gas. The actual productiontargets 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 acost 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 productionstart-up planned in October 1993.

- 71 - A= 9Page 4 of 4

9. The Initial Program will not be sufficient to develop the 1, 500 Bef ofrecoverable gas reserve called for in the Gas Sales Agreement. The Operator, isalready planning a second phase of development but implementation will besomewhat dependent on first phase results. The most recent plans include threeadditionAl well platforms and 27 additional platform wells completed by year ond1996. Some six appraisal wells (non-platform) will abe required -for properplatform locations. The 47 producing wells are expected to raise productivecapaclty to more than 250 - cfd, the current target for 1995-96, 100 m cfdabove the contract minimum. The Operator (Total) has not made any plans beyondthe second phase on the assumption that PTTEP will be the Operator for anyadditional phases at development.

10. PTTEP with the assistance of Statoil has prepared a total developmentscenario for the purpose of determining economLes of the Pipeline Project.PTTEP's scenario envisions a total of 109 wells to be drilled following theInitial Program, 103 development wells and 6 appraisal wells (most likelyexpendable wells) on 10 adLitional platforms. This additional drilllng programis expected to cost $514 on ln 1991 constant dollars. Thus the total developmentis expected to require; (a) Central Productlon and Process facilities; (b) 13well platforms; and (c) 123 development wells, at an estimated investment costof $897 -. Related exploration activities are $55 - bringing the total JVinvestment to $952 -. This investment is expected to recover 1,700 Bcf as and24 - bbl of condensate. Gas delivery at plateau production will fall between250 - 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 pastexperLence in similar fiolds in the Gulf of Thailand (Unocal average experiencein 6 fields). These include average reserve/well at 13.8 Bcf (Unocal 8 - 15Bcf); initial producing rate of 12.5 mm cfd (Unocal 10 - 12 mmefd); rate ofproduction decline average/well predicted is 20 percent (Unocal 20 percent), etc.Expected costs of platforms and wells are also comparable to current Unocalexperience. The initial results of the new 3-D seismic survey give promise thatbetter than expected development efficiencies can be achieved. The clarity ofstructure and faulting is much improved over the initial 3-D survey. Many of thegas reservoirs, both proved and prognosticated, can be identified and delineatedby means of seismic amplitude anomalies. While substantiation of the seisaicdata will require drilling, the seismic results support JV enthusiasm that aproduction plateau of 350 -m cfd can be achieved by 1999 for a duration of sevenor more years. The seismic data also indicates that the earlier wells at Bongkotwere located on the basis of the deeper structure (where CO2 concentrations arehigher) consequently missing the better part of the shallower structure (whereC0 concentrations are lower) since the structures are offset with depth,particularly the fault closures. Thus, the statistical methods used to determinereserves serves to overestimate the quantities of gas (including C02) in thedeeper reservoirs and underestimate the quantities of gas (including COZ) in theshallower reservoirs. Thus the CO2 fraction way be overstated and the estimateof condensate (shallow reservoirs also richer in liquids) reserves may also below. In view of this PTTEP has used an estimate of 912 btu/cu ft for theirdevelopment scenario rather than 875-900 btu/cu t: as determined from producedsamples.

- 72 -

Page 1 of 10

Bangkok-Erawan-Khanom Gas TransmissionPipeline-Environment Assessment Summary

L _Backgroun

The Petroleum Authority of Thailand (PTT) completed the constructionof a natural gas pipeline and associate onshore dew point control unit fromthe Erawan field of UNOCAL Thailand Ltd. in the Gulf of Thailand toconsumption centers on shore in 1981. In 1985, PTT completed anotherpipeline connection PTT's Platong platform to PTT's main system and alsoinstalled an onshore compression stati.'n near the existing gas separationplant at Rayong. Recently, PTT concluded a natural gas supply agreementwith PTT Exploration and Production Co. for the supply of gas from the "B(Bongkot) structure gas field 160 kilometers south of the Erawan platformin the Gulf of Thailand. A study was conducted by Fluor Daniel in order todetermine the best way in which the "Bo structure field gas can betransported to various consumption centers via existing facilities or bythe addition of new facilities. The study concluded that the best way toperform this task would be the construction of a new 170 kilometer pipelineform the "Bw structure field to the Erawan platform, joining the existingsystem, and in addition the const.uction of a new 160 kilometer pipelinefrom 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 Erawanplatform to Khanom onshore. There are no structures at present in the Bfield, with construction of initial platforms and intra field platforms setto commence in March 1992. The "Bo field structures will be sufficientlycomplete to allow construction of the pipeline from the field to the Erawanplatform after May 1992. The major system components of the project aresummarized below:

A 175 kilometer long 32" diameter submarine gas pipeline indepths varying from 270 to 210 feet connecting the Bongkotproduction platform with the existing Erawan compression platform(ECP). This pipeline will be able to transport up to 750 NMSCFDof gas from the *Bo field and a potential future gas field to bedeveloped jointly by Thailand and Malaysia.

- 73 - ANNEX 10Page 2 of 10

A 165 kilometer long 24" diameter submarine gas pipeline indepths varying from 210 to 100 feet to sea level connecting theECP with Khanom onshore. This pipeline will be able to transportup to 330 MSCFD of gas without recompression and ultimately 500MMSCFD of gas with recompression at Erawan.

A new gas/liquids handling and tie in facility at the Erawancomplex, located on the existing UNOCAL platform.

A new gas/liquids handling facility at Khanom near theElectricity Generating Authority of Thailand's existing Khanompowerplant.

A new SCADA information system, including renovation of PTTIsexisting gas pipeline control system.A new control building at the Khanom pipeline terminal for boththe Bongkot to Erawan and Erawan to Khanom pipeliaes.

The target date for the completion of the pipeline and associatedfacilities from the "B" field to the Erawan platform is June 1993, whilethat of the Erawan platform to Khanom and associated facilities is December1993.

III. Base line conditions

The study area is focused on the offshore environmental areas wherethe pipelines will be laid, and the onshore area where the EGAT thermalpower plant is located.

A. Meteorology

The project area lies between latitudes 8 and 10 N, 1,100 kmnorth of the equator. Its climate is characterized by hightemperature and humidity, with rainfall varying according to themonsoon season. Meteorological parameters summarized below weremeasured in stations located close to the project area:

(1) Temperature: The mean maximum and minimum temperature rangefrom 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 rangeof 1,600-2,000 mm. Precipitation peaks to 428 m per monthin November and declines to 38 mm in February.

- 74 ANNEX 10Page 3 of 10

(3) Winds: Easterly winds are normal from May to October, withmean speeds ranging from 4.0 to 7.1 knots, and extreme gustsof 40 to 50 knots.

(4) Fog: This is seldom recorded in the area but mayoccasionally occur in March.

(5) Thunder storms: Activity peaks in May with an average of 18days.

(6) Storms: Intensity and occurrence of storm in the Gulf ofThailand range from 10 m/sec during 3 hours once a year toinstantaneous gusts of 58 m/sec once in 100 years.

B. OceanorraPhy

(1) Waves: Height and occurrence of waves range from maximum 4 mhigh once a year and 11.6 m once in 100 years. Wavedirection ranges from 220-270 degrees.

(2) Currents: Maximum currents of both flood and ebb tides is0.3 m/sec with flood tide setting north, and ebb tide south.

C. SeismoloFg

Thailand lies on a southern extension of the Eurasian seismicactivity zone. The closest boundary is just offshore of theislands of Sumatra and Java, some 1,000 im from the Gulf ofThailand. The main belt of shocks is seen to run offshore fromthe coast of Myanmar, then approximately along the Thai border.No earthquakes of magnitude greater than 2.0 were observe in theGulf during 1984-1987 period. It can therefore be concluded thatthe seismic risk along the pipeline is negligible.

D. Marise water quality

The distribution of water temperature and salinity in the lowerwestern part of the Gulf of Thailand are quite similar throughoutthe water depth resulting from the vertical mixing of the watermass. The dissolved oxygen (DO) concentration at the surfacewater 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 10Page 4 of 10

but reach 30 meter at far offshore areas. PH values are lowerthan 8.

E. Aquatic Biology

(1) Plankton: Low relative abundance of plankton was measuredalong the proposed pipeline route and vicinity area. About6 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 ofThailand. The sensitive productive area is 25 km north ofthe coastal pipeline route to Khanom.

F. FishvXX

The western coast of the Gulf from Surat Thani province toNakhom Si Thamarat province is an important fishery resource.

The distribution of juveniles have mostly densed along thenearshore coast more than for the offshore areas, due to the highfertility along the shallow coast. The planktons which somespecies use as food have mostly been found in the shallow area.

Thai fisheries developed very rapidly after 1960, with totalproduction increasing slx-fold between 1960 and 1970 and by afurther 501 in the period 1970-77. Recently, production hasfluctuated - the catch from otter trawling (of particularrelevance to the pipeline) jumped about 25X from 1985 to 1986then remained fairly static at about 1 million tons through 1988.Fishing resources are now over-exploited and associatedindustries such as cold storage, canning and fishmeal productionare under utilized.

86X of the marine catch is from the Gulf of Thailand.Trawling accounted for 5i4 of the catch. The percentage of otterboard trawling to other trawling was 821. Hence, 44X of thetotal catch was derived from otter board trawling.

Hundreds of trawlers will operate in the vicinity sf thepipeline route at all times of the year, with only the immediateareas of the oil platforms providing some deterrent. A typical

- 76 - ANNEX 10Page 5 of 10

trawler will be 16 m long, with a 90 HP engine and operate withotter boards weighing less than 100 kg. These will thereforepose little direct risk to a surface-laid pipeline. Fish traps,comprising floating bamboo rafts moored by wire to concretemocrings, presently extend to offshore areas as far as the "B3field (220 km).

Bottom trawling for demersal fish is illegal within 3 km ofthe coastline but is doubtless carried out by rogue vessels luredby the rich fishing grounds off Khanom. Smaller local vessels,including long-tailed motor boats also carry out line and rodfishing 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 coastalpipeline route cover 12,400 rai. The common tree species areKong-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 thegulf to Singapore, Nalaysia, Australia, Persian Gulf andwestwords, will cross the pipeline route at about 100 km from theshore.

Domestic coastal traffic, consisting of cargo vessels,tankers, LPG carriers, passenger vessels and tugs. The averagecargo vessel size is 750 DWT and the mean tanker size 1,500 DWT.

Traffic in and out of the coastal ports, down the southerncoast of the Gulf of Thailand, involves crossing of the pipelineroute. Typical commodities traded are rubber, copra, generalgoods, minerals, rics and fish.

I. Socio Economic Data

Amphoe Khanom is located at the north of Nakhon Si Thanmaratand 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 fromfisheries and agriculture.

J. Archaeologv

The region is regarded as one of the centers of ancient artand culture in the southern regions.

An archaeological site is located about 8 km from Khanom and2 km south of the onshore pipe crossing.

IV. Potential Significant Environmental Impactsand 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 onmarine water quality. Disturbance of the sea bottom will result inincreased turbidity and suspended solids contents. This will result in adecrease in water transparency, affecting the growth of phytoplankton byreducing the light available at the seabed. Further, direct habitatdestruction over the area disturbed would affect benthic organism.Indirect destruction of habitat by the increase in concentration ofchemicals such as sulphides, greases and oils and phenolic compounds in thesea water in the immediate vicinity of the pipeline due to the dissolvingof chemicals naturally present in the disturbed seabed sediment could alsooccur. However, in the former case, since phytoplankton are dominant onlyin the first ten meters from the surface it is expected that no significanteffects will be observed in the long term. In the case of direct andindirect habitat destruction, only about 0 37 square kilometers of seabedwould be subject to short term habitat destruction. Little impact on thelong 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 thepipeline surface will provide attachment points for plant species andbenthic life and will provide cover for fish.

B. Solid and Liguid Wastes

No process related solid wastes will be generated during the operationof the pipeline. Spoil generated during the construction of the onshorefacilities associated with the pipeline will be initially deposited insuitable areas at the construction sites and then eventually used foilandscaping around the construction site. Onshore spoil will be disposedof in suitable areas so as to minimize siltation effects. The spoil fromthe onshore pipeline excavation will be stored along the sides of the ditchand used for backfilling upon completion of pipelaying. Solid refuse fromboth the onshore construction sites as well as from the pipeline lay bargeand the platform will be collected and disposed of onshore.

Process waste water will be generated during the operation of thefacilities. The primary pollutant in this water will be waste oil. Thewaste oils generated during platform and pipeline operations will beseparated and the water treated to prevailing Thai standards (15 ppm ofoil). Domestic waste water and sanitary wastes will be pretreated anddischarged to the sea at B.O.D. load conforming to Thai standards. Solidwastes will be transferred to approved disposal sites onshore.

C. Obstruction of Navigatio

During construction, the use of a pipelaying barge which will have thepipeline suspended behind the barge, touching down on the seabed at adistance of 200 to 400 meters behind the barge will pose a iazard tonavigation. Further, during construction, the suspended pipeline canpotentially interfere with trawl fishing since fishing nets could getfouled on the pipeline. Both of these hazards will be mitigated by the useof appropriate warning devices and the prohibition of trawling in the areaaround the pipelaying barge. PTT and the government of Thailand agencieswill develop a plan to implement the prohibition of trawling. Since thenearshore pipeline will be buried in a four meter deep trench, noobstruction of navigation will be caused by the pipeline. Furtler, theplatforms will be equipped with appropriate navigational aids and warningsto prevent their being a hazard to navigation during pipeline operation.

- 79 - ANNEX lOPage 8 of 10

D. Gas Characteristics and Potential Leakage

Mercury in gas can pose an environmental hazard. The reported contentof mercury from the Erawan structure is 10 ppb. The gas from the "B"structure field is expected to contain similar amounts of mercury. Amercury removal unit will be installed in the future to remove mercury fromthe gas if it reaches unacceptable levels. The removal unit will be anabsorber which can reduce mercury levels to 0.1 microgram/m3. The usedabsorber will be sent back to the manufacturer for mercury reclamation.Mercury is also condensed on the production platform and accumulated untila proper way of disposal will be agreed with DMR. The mercury content andaccumu_ated amounts on the platform do not coincide and shcAld be resolvedby the EA consultant.

Non catastrophic, short term, gas leakage will have no significanteffect on marine water quality, since the gas will bubble to the surfaceand disperse. Catastrophic gas leakage is addressed under safety issues.

E. Socio-Economic Effects

The temporary increase in the population around Khanom by about 800workers, of which 80 will be local residents, will have an impact on thequality of life in the Khanom area. Problems such as overcrowding ofconstruction camps, life and property security problems, gambling, etceteracould result. In addition, the workers will stress the water supply,health services, and other community facilities capabilities.Transportation and navigation activities during thb construction periodwill probably result in an increase of transport related accidents. Theimpact of the additional workers will be mitigated by requiring thecontractors to provide and maintain good living conditions in theconstruction camps as well as requiring them to seek the assistance oflocal authorities and police forces as necessary. The economic conditionof the Khanom area will be improved by the influx of workers as well as bythe employment of local labor. The influx of the workforce will lead toincreased development of the commercial and service sectors such as foodservices and general stores for the supply of the workers needs. Duringoperation, only a small number of PTT employees will be working at theKhanom terminal and thus are expected to have a negligible socio-economicimpact. Indeed local people have been surveyed as to their attitude towardthe project and in general had positive opinions about the impact of thepipeline.

The effect of the pipeline on fishing productivity and livelihood ofthe fishermen, has still to be checked by the EA consultant.

- 80 - ANNEX 10Page 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 ofthe 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 10Page 10 of 10

C. Other Issau

No significant environmental impact is expected due to the sGismologyof the site or due to the ocean currents and tides at the offshore sites.Noise pollution will occur during pipeline construction resulting from theoperation of heavy equipment. Since the noise level is not anticipated tobe excessive and since only the construction workforce will be exposed,noise pollution during construction is not expected to have a significantimpact.

V. Environmental Management and Training

PTT proposes an environmental monitoring plan that will sample waterquality and aquatic biology during both construction and operation. Theplan will also monitor fish landing at Khanom, solid waste generation,water supply requirements and socio economic impacts. The results will beused to adjust the environmental management plan to reflect experience.The ITT Safety and Environment Subdivision of the Gas Pipeline OperationDepartment is directly responsible for the implementation of the pipelineenvironmental management plan which has been drafted by the PTT Safety andEnvironment Standard Division. Pipeline system personnel are trained inloss control, safety, fire control and hazardous chemical management on aregular basis. PTT realizes its responsibility for the improvement andmaintenance of good working conditions, working environments and workingapproaches with respect to internal and international standards. Safety isparamount at PTT and will be monitored as part of the environmentalmanagement plan.

Dated Dec 13, 1991

Apnex 1,1

THAILANDBONGKOT GAS TRANSMISSION PIPEUNE PROJECT

Project Implementatlon Organization

|. MwId Dl Ngeo Mard Ealpnmne

MiftetownwcmProcfumNo r Sp lmIuinui. Cwntjow andOfhre constrxtIo9*09_ *o d onsobConsuco

cm

| ,9

THAILAND Annex 1.2BONGKOT GAS TRANSMISSION PIPEUNE PROJECTProject Schedule

1991 I 1992 1993AcvItpDascrIpUon | ; i. 3 e~> e28 .. i. 1J M M J S NJ F M A MJJ S N D MJJISIOINID AJIJ IAISIOI

Ati 2. 1991 so-LIM Doc ~17, 1991ConWrac Award Padiag b Ppelne wan1d SCADAApr 30.1991 BIdd loCoracts bO Wdders

Enrominenlal Survey-EIA Repot TOR -i I _

Data Coiecion -

MadneSv i ii " System Englneebg & Pipelho Design " fr..tEcn4edrmg & 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 CL* Pq Supply

~~~~~ ,~~~~~~~~~~~s ~~~~3# 24lPIps- Mianulackn te !o !rO P24OP' Dlvr Plpe kr Coalti ng

32 E24 F@ Cor oslanlciele

C____ C by UNOCALConoslon £ bIg VPlehbe 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 TotolLocal 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 - 3.00Lino Pipe - 20.07 20.07 - 38.60 38.60 - 18.53 18.53 - 77.20 77.20ipe 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 95.00 110.00TOTAL - 5.20 5.20 - 10.00 10.00 - 6.80 4.80 - 20.00 20.00SCADA/T.loam 0.96 1.72 2.68 1.65 3.30 5.15 0.69 1.58 1.58 3.70 6.60 10.30Rigor 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 15.00HIS L.. Training 0.03 0.23 0.26 0.50 0.65 0.50 0.02 0.22 0.24 0.10 0.90 1.00InVLroAMeatal 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 2.00axeo 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.Slh7xical Cantinsgnc 0.81 5.77 6.56 1.55 11.10 12.65 0.74 5.33 6.07 3.1n 22.20 25.30Price 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

IULNDBong&ot Gas Transmission ProjectEstimated Disbursement Schedule

(US Million)

IBRD Fiscal year Estimated Dsbunrsement Pipeline Subsectorand Semester Semester Curnmulative Profile

1993December31, 1992 52.0 S50 3.0June30, 1993 22.0 75.0 10.0

1994December31, 1993 16.0 91.0 27.0June30, 1994 'r.u 96.0 40.0

December31, 1994 9.0 105.0 48.0June 30, 1995 67.0

December31, 1995 82.0June30, 1996 95.0

1997December31, 1996 103.0June30, 1997 105.0

- 86 -ann 16

,UARND

PSOTMRAS PROEC

ISCAL YEAR 1966 1967 16 i9o 1910

a" 37873 3754 40559 44U78 562Ow rRevue 705 1013 M M 1205

Tatmi ft=mmm m m ii az

Coo 3230 33M 34725 39570 4427Sak Ewwe 4O 405 452 480 634M.M p_FhI 1396 1066 1269 1250 2264ODwSpe_ 43 40 34 35 386WprealaUu_ 1124 1003 1173 1271 136oRSAIBSUIGStote Go_vemnt ON m 675 6 1161

MOLO_hrti kwoP_~~~~ M___li

h130 1264 1200 1382 1266Lome kron Forwign EOi_e 406 362 674 415 400

TIW Non Opwadn2 _ UX Zg 2074

Not Income Z m Za 1411

Avrage Aimal Rm"udNP Fked AMe 20=57 2123 224 236 261

FOReof rumn) 11 11 14 11 13Operng RaOO) 94 94 93 e5 6

- 87 -

TIULND Armex 15QOKOA 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] CahGwtopwadnobvmw 2224 2394 3039 250 3106Non-Cash tes 31 266 2827 2520 2744

Total internal CerArshm l_n 1 AM la

C4PiW Cntr oaw 1 7 23 0a 935Long-Turm Loas Rced lb 0 0 2847 4522 0Depost 0 6 0 563 0Da dpoaslof Pbged Ammi 3 2 1- 1 1Other 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 126Interm 1290 1284 120 1382 loop

l tal Debtn8 14U 4748 1412

RefundableDepo it 0 39 734 0 112Other LbIbUIt 0 0 0 109 4

Total US" of Fud 724Z

Ince In Non-cai WodnAg Capi 906 1499 2W5 064 -511Increa 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 3869Det SeNic Coverag - tiOme 4.1 2.2 1.2 0 4.1Sel-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 yeasaverae 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 1990MIM

Cam am2 2S6 137 29 152Shart-Tom Invegronts 50 0 0 0 0Auounts RuAble - Trade (Nu 48 482 7m 6541 8336NWue|R@culi w796 905 1032 1200 2020bwdodei 106I 1532 1610 1777 2067_Mi aid Su 250 S2 64 775 m7Obtr CuOrut AsaW 2205 231M 3130 309 4404

LWn-Twm Im _uIO 1?97 2211 27 3118 49Rope". PMI ad oEu Ne) 21001 21536 234 21109 23728Constuedo 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 95Accfunt Paabe Trade 2361 2446 2233 3135 47e9Ottw Accownt a ylW 963 1197 620 1270 3149Accrued r heI- 1567 1339 2047 1427 514S&or-Tem LoNs 624 1239 658 464 246

fur Coumnt" Ubile 1471 1624 1344 1S22 3329

Long-TerM ULwowLong-ToM LcWN 10404 l1616 16263 16320 16302Other Long-TomnLbOW"to 565 313 1n2 11 7

Totid ama im amu am ammounry

G _oem Conbuio 2411 2418 2441 2506 343Retand Emlng 7764 648'; 947 10152 11563Revaaton Surpks 4438 6045 )16 8801 9903Foreign E_mn Lsme (3250 (3582 (31C7) (3193 (28)

Total E:ulht 1 tm3 1m aims 22 0mTOTAL 6LWM ND-EQUITY flE 2I _4M M

Long Term Dow t dofamt INWUtY 59 55 50 47 43CurrWRaoo0m)n . 1.7 1.6 1.6 1.8 1.5

- 89 - Ann 16Pace I of 7

Prr. RkuW PMGon

(Bh Mllbn)

FISCAL YEAR 191 192 193 1994 1S99 1996

Ra-uSa"es 76279 78860 SE104 103858 124733 136938Ote 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 122406Se"lng Epmes 843 92 976 1056 1144 1231Adiliralve _inpenee 2194 2367 2859 3330 3795 4262other Bpeneu 26 11 14 14 14 14Deselsi*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 _oneMfZtwe 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 RPvaluedFbod Aut 2544 223 28171 34682 40693 50870

Rast o Ratum f) 13 16 16 1S 15 13Opwating Raio(%) 94 96 96 96 96 96

- 90 -

Anne 16Pags2of 7

ll4AIUANQKONKO OAS M1MISSON PROJECr

PrrTs Flnandal Prdreons

Funds Flow rnomrn

FISCAL YEAR 1991 1992 1993 1994 199 16

8011RCES OF RJN08

,*rnal Cash 020nonqwae ho h m 468 4282 4571 S24 62S0 6748D _rcaon 1566 1496 1568 2284 2597 2803Dehfered C 26 11 14 14 14 14Othelt"m notlnvomn cash 1831 467 67 1116 2607 1594

ToW ltwna go Gn2Mml ml m~ m "'so15Long-Term Lam 0 5321 10073 14390 10346 4233OteW UabuU 1 0 0 0 0 0Surplus From Contrlbutors '18 0 0 0 0 0OhwAsets 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 2635Loanto PrEc 52 52 52 52 52 0Intrest 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 1661Icreasse 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 9804Debt Service Cove (Umes 4.1 3.1 2.3 1.8 1.7 1.9SeI-fncinq RtUo(%)Ja 121 25 16 25 25 38

la - Intena cash generton lss non-cash wridnog capl Im d btsvicespessed as a perentageof thrse ye avrage capita spenditure

ANNEX 16- 91 - PageSof7

TAIWLADQ" 318w0 PROJEt:r

B a ShM

fl8ALYEMR 199a m ) 1993 1994 19 19-6ASETS

Cuh 49 2239 2463 2709 284S 4461Accounts Receivable (Trde) 6612 9413 9692 11306 13424 14739Accounts Rable (PTEP.) 1813 1484 741 690 1275 1275luwdm1m 3977 3292 5063 5991 66 8150OtheCuuWCAse 3334 434 4697 599 502 6147

Totl CMnAono m 2iM am amn maz amwlobvwft In Su_skladn and Afll 527 6306 li1S 15017 17396 17713

Pperty. Piant NWEquipmet 27201 26644 2969 39 41720 MM020ConasuWourkIn Progm 777 61 10544 11703 17418 1735OtherAss 273 311 298 284 270 256

TOTAL ASS9EM un Z.4S01 82US IMZ2f 114496

LSARILMN1PAD EOUITYCurrent U&bMWin

Bank Overdraft s 0 0 0 0 0Accout Payable. Trade Local 3589 4472 5060 6180 62 7631

: Foren 594 1472 1000 1509 1954 1907Accrued Interee 575 249 564 1C59 1419 1154Accuud ReenutoTresusy 2157 1601 1S50 1476 1696 246Oter Current ULbl_ 4390 3S0 4212 4536 4662 5253

TO UNUONSM 1M 1M0 14M 760

Long-Tm UsbIl_esLongi-Term Loans (Net) 15273 19895 29542 42304 493 50923LonTerm 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

EoiGovernment ContrIbuto 3291 3291 3291 3291 3291 3291surplus from C*ontRb 336 336 336 336 336 336RPtad Eamkg

Approprleted 7466 7486 7486 7466 7466 7466_napproprIated 7352 10034 1216 14078 16646 2110

Patok1 Surplus 11493 11541 11202 11906 14181 15182Foregn 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 u3Current raUo (OM) 1.8 1.7 1.8 1.7 1.e 1.9

- 92 - AM 16Page 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 byproduct (e.g. , for premium gasoline, regular gasoline,kerosene, high spoed di-sol, low speed diosel, fuel oiletc.). These projections are included in the projectfile. Essentially petroleum product iL projected toincrease on average approxinately 14X per annum over thenext five years. Annual totals in million liters areshown below.

ya r 1992 1993 1994 | 1995 1996 HI Petroleum ProductSales VolUm(UK liters) 8208 10470 11651 13153 13637

(b) Price projections were also made on an individual productbasis, and are lncluded in the project file. However,generally fluctuations from 1991 prLec levels relate tothe projected prices of crude oil per barrel, which areas 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 asfollows:

(a) Gas flow in Milion Cubic Feet per Day (MMCFD) isestimated as shown below.

m ~~~~~ m

Year 1992 1993 199' 1995 1996

GALS FLW(MMCFDIUNOCAL I 230 230 230 230 230UNOCAL II 368 368 305 258 240UNOCAL III. & IV 139 152 165 212 230BONGKOT 150 200 210JDAESSO 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 existLnggas flows, and 80 Baht per MHBTU for the Bongkot Pipelinegas, 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 51UNOCAL II 50 50 52 54 56

T. III & IV 59 61 63 54 56BONGKOT 55 57 60JDESSO 34 37 45 48 54

4. In the cascs of imported oil, the cost of sales includes variousimport expenses such as custom duties, import duties, surveyors" fees, andcontributions to Oil Stabilization Fund.

- 94 -ANNEX 6Page 6 of 7

5. Inflation factons are proj cted throughout the five year periodat the rate of 7X per armum for selling and administrative expenses.

6. Depreciation is calculated by using the straight line methodover the ostimated useful life f the asset, at the following rates:

ASSETS RATE

Products Extractlon Plant Group 6.67XTransmission Plant Group 4.OOZGas Plant Group 6.67ZGenoral Plant and Other Property

Buildings and Improveant 3s33XTools, Equipments and Other Proporty 10.001Railroad Transportation Equipment 6.67XTransportation Equipment 20.00X

Computer System & Peripherals 15.001 to 20.001

7. Remittance to the Government is expected to remain at 35s ofnet income throughout th proj-ction period (calculated on net income basedon book value -- not revalued asset -- depreciation).

8. Foreign Exchange Losses are an amortization of the balance oftbh deferred losses from devaluation of the Baht against foreigncurrencies. The balance of deferred losses on exchange from conversion ofoutatanding foreign loans as of September 30, 1991 mounted to Baht 2,605.9million. The projections assume that the current exchange rates of thebaht into all currencies (including both the dollar and the yen) willremain constant. Accordingly, if the baht in fact weakens against the yen(it is less likely to move dramatically agalnst the dollar since it is tiedto the dollar), then the foreign exchange loss could be understated (ardnet income correspondingly overstated). Conversely, a strengthening of thebaht against the yen would provide an increase to PTT's net income.

C_nital Tvewstmen

9. Detail regarding PTT's proposed capital investment ±.s givenb-low.

- 95 - gX 16Page 7 of 7

tfaht Million)

FISCAL MmS 1992 19*3 1994 1995 1996

A. PRO= IDVZSSNHJ1. Ga Plat Project tUMt III (Rayem) 50 500 1475 14752. Gas Plnct Pojeot UnRit IV ohnam) 175 412 924 4893. lafrigszatd Senk Co.ssumtima 2004. Pows Plant - Co. Gezsation 200 2505. 2id Otffhoe Pipeline 52 1300 7600 5200 14086. JnA Pzoject 78 3127 DUomkot Gba lranainison Pipalin 3020 4333 2546 212 7418. 3 1227 tp.lina 100 315 258 193

10. Jthmsvaksm Oil Depntt s0 190 360

?O?AL ~f TrW ~ U nIr Mm nu ianS. 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 and43 days of sales throughout the projected period.

Acputs Payabl

1I. Trade Accounts Payable are projected to range between 29 and 31days 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 ofapproxiuately 72), the Overseas Economic Cooperation Fund of Japan (with a30 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 7Sinterest 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 byborrowing from local comuerciLal banks, both of which sources typically giveloans of 5 to 10 years with an interest rate of approximately 11.

- 96 - Annuul7

THALANDaONTM GAS TRNSMISSION PfOEM

Pw ra CIDISI mmS m

(Sam Mi an)

FISCALYEAR 1992 1993 1994 1996 1996

A. PROJECT INVEfrMENr1. GaM PaPJectUritUHiao ) s0 Soo00 1476 14752. G Plant rt Unt IVQhmm) 175 412 924 4893* ReMgae Tank C _anuln 2004. Powe Pln - Co. Geneadon 200 2505. 2ndOlft eline 52 1300 7800 5200 14088. JDA ct i7 3127. Bonokot Ga Tranmhnion PeIn 3020 4333 2048 212 741a B212J27 Pie 100 315 258 19310. 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 18Page I of 4

BONGKOT GAS TRANSMISSION PROJECTEconomic and Financial Analysis- Assumotions

Economic Analvsis

1. The capital cost for development and production of the Bongkotfield is based on the estimated costc for drilling 123 wells, installing 13well-platforms and a central production and process.ing platform, and thecost for related exploration activities. The total capital cost is theestimated investment needed to produce 1,500 bcf of gas and 24 millionbarrel of condensate. The operating costs associated with the estimatedinvestment 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 (excepttaxes and duties) and the physical contingency. The pipeline operatingcost is assumed to be 3 percent of the capital cos:.

3. The annual quantity of gas supply is basid on minimum dailycontractual quantity delivered by the joint-venture ga- producers to PTT.The average calorific value of the gas is assumed to I-- 000 btu per cubicfeet. The annual prodtction of condensate is proportio.. _o minimum dailycontractual quantity of gas supply.

4. The price of crude oil is based on Bank projection. The price ofcondensate is assumed to be US$1.00 less than the price of Bank-projectedcrude, 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$2more than the FOB price of the fuel oil, to cover the cost of oceanfreight, insurance and losses.

5. The gas net-back value is based on the economic value of gas usedin a combined-cycle power plant. This takes into account not only theenergy cost of the alternative fuel (i.e., the fuel oil used in a thermalpower plant), but also differential in equipment efficiency (i.e.,differential in efficiency of a gas-based combined-cycle and fuel-oil-basedpower plant).

6. The combined-cycle power plant considered for. the purpose ofthese analyses is the proposed plant at Khanom, 600 MW capacity, estimatedto cost US$815 per Kwh ( based on actual bids received by EGAT). It isassumed to have operating costs of US cents 0.6 per kwh, a plant factor of751, efficiency of 46X, a construction time of 3 years, and a life of 20years.

7. The fuel oil-based power plant is assumed to have a plant factorof 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 25years.

Financial AnalAsIXS

8. The capital cost of the plpcllne for the purpose of finLneialanalysLs L. ssumed to be the Projoct base cost ineludlng taxes and dutiesand the physieal contingency. The operating cost is assumed to be 3X ofthe capital cost.

9. The purchase price of gas is calculated using the gas priceformula provided in the Gas Sale Agreement singed between PTT and thejoLnt-venture gas producers. The gS solling price is calculated using theprice formula provided ln the Gas Sale Agreement singed betweon PTT and theEGAT.

ANNEX 18Page 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. NucaPa oP.. cap. o . wPILEm PaL.e cp.&oplef. codw - ..... d N*ack COW. 8ia Bons own. ¢am BohaYe 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 -17.01961 114Jo 1OAO 135.6S _ _ 0.00 13.o - _ _ _ _ -125.'.. U._2 CAo -125.60196 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 4-6w7t164 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 1062196 U620 .80 138.70 - .96 O0. 148.6 62.60 125 4.14 16.36 141.66 1S91. 20.46 02.00 23.41o6 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 JO3321t97 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 40122m 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*s200 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 334652001 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 283402002 40.10 6.00 6.10 - 0am 108G0L 916 1.76 4.14 20.61 Sml.78 2072 3W7 413J64 s07n2003 8.30 680 6O - P." 9.6 7.2 01.26 1.75 4.14 20.S 377.78 3042 6s. 413M 340.092004 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 412.6 314.762005 58.10 67.60 06.60 - 0.96 0m 106.66 01S. 1.7 4.14 18 37.78 722 34SI 412.66 W7S200m - 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 S320I0U - 0 10 4.10 - 90.6 96 8348 01.J 1.00 4.14 19.91 m.7n 324.S2 60A 07. 344.23me6 - =80 32.60 - 0691t O0. 42.4 61* 0.80 4.14 1902 377.78 336.32 0BA6 37. 74 46.2201t _ 2020.0 00.00 _ .06 0.90 2.06 *1.25 0.60 4.14 t 1U.l 277.7 472 .66 337.72 867.7tTOTAL 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 18BONGKOTTRANSMISSION an PRO Page 4 otFINANCAL ANALYSIS.1991 aeonst4 olbr

FInancIl Rate of Retun

Purchase Price Vdume of Gas Purchase Pipeline Cap. Operating Total Gas Gas SellingolGas 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 - -88711993 - - - 170.60 - 170.60 - -170.601994 1.87 64.00 119.82 81.89 9.96 211.67 171.02 -40.651995 1.93 8260 159.18 - 9.96 169.14 225.18 56.041996 2.03 96.10 194.65 - 9.96 204.61 271.53 66.921997 2.12 109.50 232.39 - 9.96 242.35 319.99 77.641998 2.23 91.25 203.13 - 9.96 213.09 276.13 63.041999 2.34 91.25 213.14 - 9.6 223.10 286.14 63.042000 2.45 9-.25 223.55 - 9.96 233.51 296.55 63.042001 2.15 91.25 196.41 - 9.96 206.37 269.41 63.042002 2.16 91.25 196.91 - 9.6 206.87 269.91 63.042003 2.16 91.25 196.95 - 9.96 206.91 269.95 63.042004 2.16 91.25 197.30 - 9.96 207.26 270.30 63S042005 2.17 91.25 197.95 - 9.96 207.91 270.95 63.042006 2.18 91.25 199.34 - 9.96 209.30 272.34 63.04 02007 2.20 91.25 200.91 - 9.96 210.87 273.91 63.042008 2.22 91.25 202.45 - 9.96 212.41 275.45 63.042009 2.24 91.25 204.13 - 9.96 214.C9 277.13 63.042010 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

THAILANDGAS TRANSMISSION EXPANSION PRWECT

PETROLEUM AUTHORITY OF THAILANDOrganizalon Chart

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MAP SECTION

IBRD 23411 CHINA,, ,- ' . . ~~100° 102° 104

MYANMAR *'L_ ; THAILANDBONGKOT GAS TRANSMISSION PROJECT

' it ,REP._ >.s 14' PROPOSED PIPELINE ROUTES AND OFFSHORE PLATFORMS~/ \ ,iTHAIIAND *, >BANGKOK FUTURE PROPOSED EXISTING

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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 DISCOVERIESI td BD GAS FIELDS

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o + **^)\ \ i O ~~~~~~ ~ ~~~~~~Rayong ° AO B0 120 160 200

1 9 _ ___ ) SaX p - . N~~~~~~~~~~~~~~~~lLCMETERS

b,ftefX 0 7 > ~~~~~~~~(,;,L)f of ThailondC .21t~ 7 MYANMAR l 'i

- #7hw*^,,. 1 vrw WJ /4~Kirl Khan CAMBODIA

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