Z,&A/ -7 , - T/.

Document of

Thle World Bank

Report No. 12700-TH

STAFF APPRAISAL REPORT

THAILAND

SECOND GAS TRANSMISSION PROJECT

AUGUST 30, 1994

Industry and Energy Operations DivisionCountry Department IEast Asia and Pacific Regional Office

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CURRENCY EQUIVALENTS(As of December 31, 1993)

Currency Unit = Baht (B)US$1.0 = B 25.52

B 100 US$3.92

UNITS AND EQUIVALENTS

bbl barrelbcf billion cubic feetbpd barrels per daybtu British thermal unitGWh gigawa.t 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 monoxideCO2 Carbon dioxideDMR Department of Mineral ResourcesEIA Environmental Impact AssessmentEIB European Investment BankECCT Energy Conservation Center of ThailandEGAT Electricity Generating Authority of ThailandJDA Joint Development AreaJEXIM Export-Import Bank of JapanLNG Liquefied Natural GasLPG Liquefied Petroleum GasMIS Management Information SystemMOF Ministry of FinanceNEA National Energy AdministrationNEB National Environmental BoardNEPC National Energy Policy ComrnitteeNEPO 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

PIT's FISCAL YEAR

October 1 to September 30

THAILAND

SECOND GAS T SMSSION PROJECT

Loan and Project Summary

Borrower: Petfoleum Authority of Thailand (PTT)

Guarantor: Kingdom of Thailand

Amount: US$155.0 million equivalent

Terms: 17 years, including a grace period of four years, at the Bank'sstandard variable interest rate.

Project Obiectives: The project's objectives are to promote greater sector efficiency andincrease the utilization of domestic natural gas resources. As such,they will help PTT to: (a) move towards a fully commercial operation(corporatization) under the new organization, as well as continueprevious efforts to strengtnen its institutional capacity to apply safetyand environmental standards and conduct project aralyses, includinginvestment programming and (b) construct a pipeline for transportingdomestic gas, which is the .cast-cost option to meet Thailand'sgrowing power generation requirements.

Project Description: The project includes: (a) a comprehensive study regarding PTM'scorporate strategy, organizational effectiveness and ownershipstructure; (b) institutional building and training of PTT's staff; (c) a36" diameter, 425 km offshore gas transmission pipeline that extendsfrom an existing platform at the Erawan fields in the Gulf of Thailandto onshore receiving facilities at Rayong; (d) a 28" diameter, 110 kmonshore pipeline that extends from Rayong to an area near the EGATpower plant at Bang Pakong; (e) related facilities, including acompressor station, metering stations, gas processing facilities, andtelecommunication and control systems and (f) project engineering andmanagement consultancy services.

Benefits: The project would have significant economic and environmentalbenefits. The gas would be used for power generat.on, in combined-cycle plants, which has been shown to be part of Thailand's least-costsolution to power generation. The economic benefits of the project arederived from the higher value that gas attains, when displacing otherfuels. Equally important, natural gas is a clean and low-polluting fuelwhen compared to alternative sources of energy. In addition, theproject will provide a detailed analyses for PMT's corporatization andeventual privatization.

Risks: Risks entail the following: (a) the availability of sufficient gasreserves and the cost of producing such reserves; (b) safety andenvironmental problems associated with the construction and operationof the project facilities and (c) potential disputes in various contractualarrangements. However, the gas reserves have been assessed andcertified to be sufficient. nle risks associated with a potenial increasein production cost.- have been minmized because appropriate

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contingencies have been included in the cost parameters. The safetyand environmental risks have been miniimzed because appropratemitigation measures have been designed. The potential for contractualdispute has been reduced because the agreements have been structuredaccording to international norms.

Estimated Cost:Locarl Tot

U ~US$ million (1993)Land & right of wav 4.8 - 4.8Linepipe & coatings - 236.8 236.8Onshore pipeline construction 10.0 30.0 40.0Offshore pipeline construction 24.5 103.0 127.5Facilities 7.5 31.3 38.8Engineering consultants services

and project management 16.9 15.2 32.1Studies & TA - 2.0 2.0Insurance and others 3.3 3.7 7.0Taxes and duties 22.2 - 22.2

Base costs 89.2 422.0 511.2

Physical contingencies 8.9 42.2 51.1Price contingencies 10.8 26.3 37.1

Total project costs 108.9 490.5 599.4

Interest during construction - 75.1 75.1

Total financing required 108.9 565.6 674.5

Ei-nanciLnS Plan:- TJS$ million (1993)

JEXIM - 100.0 100.0ADB - 100.0 100.0EIB - 47.0 47.0Equity 93.6 78.9 172.5Commercial borrowing - 100.0 100.0IBRD 15.3 139.7 155.0

TOTAL 108.9 565.6 674.5

Estimated Disbursements:

IBRD Fiscal Year 1995 1996 197-S$ million-

Amuwal 75.0 65.0 15.0Cumive 75.0 140.0 155.0

Pover Cag : Not Applicable

Economic Rate of Reun: 36%

Maos: IBRD No. 25766 and IBRD No. 25767

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T1HAELAND

SECOND GAS TRANSMISSION PROJECT

Table of Contents

M eNo.

Loan and Project Summary .................................... i

I. ENERGY SECTOR

A. Background . ......................................... 1B. Resource Endowment ............ ........................ 2C. Future Outlook and EnergyDem-d ........ ................... 4D. Insutions........................................... 5E. Prices .............................. ...... .... 6F. Issues and Strategy ............................. ...... 6

L. GAS SUB-SECTOR

A. Background .... 9B. Domestic Gas Supply and Import Potenti .. . . 9C. Gas Demand ..... 11D. Gas rices ..... 11E. Role of the Private Sector .... 12F. Experience with Previous Bank Loans .... 13G. Raionae for Bank Involvement .... 14

ii. TiHE PROJECT

A. Project Background .... 15B. Project Objectives .... 15C. Project Descrption .... 16D. Stats of Project Preparaon .... 16E. Environmental and Safety Aspects .... 17F. Project Implementation and Schedule .... 19G. Project Costs .... 19H. Project Financing Plan .... 20I. Procurement and Disbursement .... 21J. Monitoring, Reporting and Supervision .. . . 24

This report is based on ft findinp of an appraisal mbsion to hailand in Septembe I9 tha included MessrsiMme. M.Fabnd Crisk Managr), N. Chamou (Financial Speciit), T. Fizgead (Ptreum Geology), P. Wrg (ervoirSpecalist) W R. Pickford ESpedaist). Ih report was ediwd by Ms. B. Koeppel. Mr. M. Edmondsprovided research assisae and procesed the repoft T Pee Reiews are Mes. P. billa and C. Redfer Mr.A. Mhalotm acted as advir for die reorganizatio component The proct was clared by Mes. C. Madavo, DirecEAI and V. Nayyar, Cf EAIME.

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IV. BORROWER

A. Background .................... 25B. Organization .................... 26C. Staffing and Training .................... 27D. Operations and Mangement .................... 27

V. FINANCIAL ANALYSIS

A. Past Financial Perfomance .................... 33

VI. PROJECT BENEFITS AND RISKS

A. Benefits .................... 37B. Rsks ...................... 38

VII. RECOMMENDATION . ................................... 39

ANNEXES

1. Domestic Energy Prices .................................. 402. Geology and Petroleum Potential of Thiland and Adjoing Basins ........ 413. Gas Production Forecast . ................................. 454. Project Schedule ............................ 465. Project I le on Orgmzation ...... 5.................... S06. Digramatic Description of the Project ....................... 517. Estmated Schedule of Disbursement . 528. Project Supervision Plan . ................................. 539. PTT Historical Financial Stements ......... ................. 5510. PTr Projected PFnancial Sttements ........... ............... 6011. Economic Anayses and Underlying Assumptions ........ .......... 6612. Selected Docments and Data Available in Project File .. ........... 75

CHARTS

Energy Sector Organizati.s . ................................. 76PTT Organ on ....................................... 77

MAPS : IBRD No.25766 and IBRD No. 25767

CHArR I

ENERGY SECTOR

A. Backgomund

1.1 Over the last decade, energy consumption in Thailand has been strongly affected by rapideconomic growth and funmentl dhanges in the structure of the economy. During this period, theGovernment and the Bank have cooperated to devise the best policy mix with regad to investmentplaniing, pnce formulation and institutional strucuing in order to meet the country's future energyrequirements and avoid ifrastructure botflenecks that could hamper economic performance. in thiseffort, the Bank helped Thailand construct several major energy projects and cenducted a major studyto identify the optimum fuel supply options over the next decade or two, while the Govermnent isconsidering to introduce organizional reforms that should corporaize, and, eventually, privatize theenergy entities. The proposed project represents another step towards this end.

1.2 Psas Consption Patern In 1991, the total supply of commerial energy in Thailandwas about 33 million tons of oil equivalent (toe) - a two-and-one-half fold increase over 1980 - andthe figure was growing at an average rate of 11% per year. Petroleum represented 62% of the total,natural gas 21%, lignite 13%, hydropower 3% and coal 1%, and 60% of the supply was imported. Inaddition, Thailand consumed about 10 million toe of renewable eneirgy in 1991, mainly in the form ofwood-fuels. However, despite the country's impressive economi;, growth (10% a year, for the last sixyears), per capita energy consumption and the type of energy consumed is that of a low-incomedeveloping country, which is a modest 540 kg oil equivalent of energy per capita and a reltively highshare (25%) of traditional fuels. This pattern is due to the large mrual popuation and the relatively highprice of commercial energy (compared with rural income levels), which plases commercial energybeyond the reach of the low-income group. Table 1.1 shows the past supply of primary energy bysources.

TABLE 1.1: THAILAND - Prhiary Eney Supply by Sores(million toe)

Eneiu Sources 9

Oil 10.5 20.5Naural Gas 3.2 7.0Hydro Power 0.9 1.1Coal/gnite 1.6 4.5Renewable 112 10.8

Totia 27A 43.9

Source: DE, Thailand.

1.3 Commercial energy, particularly oil and gas, plays a critical role in the economy because(a) the country is only modesdy endowed with these resources and (b) the dramatic in usalion inrecent years has led to a sharp increase in energy consumption. In fhat, demand continues to far exceeddomestic supply and this gap is likely to increase in the future, in view of the conthiued and rapid

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economic growth expected and the uncertain prospects of discovering any additional major oil and gasreserves.

1.4 Final commercial energy consumption in the economy is dominated by the transportsector, which in 1991 accounted for 39%, followed by the industrial sector (31 %), and residental andcommercial sectors (24%). Traditional fuels continue to represent a significant, albeit rapidly decliningshare of energy consumption in the rural residential sector (see Table 1.2).

TABLE 1.2: THAILAND - Final Energy Consunptlon by Sectors(million toe)

Sector 195 I 1991

TrnpwQX i 6.0 11.9bJnduy 5.4 9.6Residential and Commerci 6.1 7.2Agriculltue 1 1.4 1.8

TOtW 18.9 130.3Source: DEA, Thailand.

1.5 Providing fuel in the power sector is a particularly critical issnie. since electricity demandhas grown by about 14% a year over the iast five years: To meet projected demand for the year 2000,the Electricity Generating Authority of Thailand (EGAT) needs to double its generating capacity fromthe current 9,000 MW to about 18,000 MW. In 1991, the fuels used to generate power includednatral gas (40 %), lignite (25%) and heavy oil (24%), while hydro was about 9%. However, EGAT'scholzes are increai1 ngly limited. First, the remaining supply of hydro is difficult to develop because ofhigh costs and environmental and resettlement problems. Second, lignte reserves are insufficient tomeet the increased requirements and its use creates environmental problems, as well. However, if gas(which is the most preferred fuel) would ultimately not be available, then EGAT must include locaUyproduced lignite plants (or imported coal-based plans) and dual-firing capability (to supplement gaswith fuel oil) in its master plan.

B. Resource Endowmenot

1.6 While Thailand has a diversified energy resource base, consisig of petroleum (oil,condensate and natural gas), lignite, hydropower, biomass and geothermal energy (which is still at anexploratory stage in the northern region), these resources are limited, which means Thailand is a netimporter of energy.

1.7 Oil. Given the geological features of the country's hydrocarbon basins, crude oil is notexpected to be a major contributor. At the end of 1992, there were about 245 million barrels of provenand probable oil reserves. Of these, about 177 million barrels are condensate, which would have to beproduced in association with offshore gas, and about 68 million barrels are crude oil. Additional oilreserves are estimated at about 440 million barrels, of which about 350 million barrels are condensateand 90 million barrels are oil. Production is currantly limited to Phet crude from the Sirikit oil field,which produced 22,000 barrels per day (bpd) in 1991. In addition, about 27,000 bpd of condensate

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were produced in association with gas fro;n offshore fields in the Gulf of Thailand. To meet the oildemand, Thailand imported 160,000 bpd of finished petroleum products, and 220,000 bpd of crude forprocessing in its three local refineries.

1.8 Gas. Natural gas has been discovered mostly by companies looking for oil. At the end of1992, the remaining reserves were 7-8 trillion cubic feet (tcf). Gas production in 1992 was 850 millioncubic feet per day (mmcfd), of which 750 mmefd were produced from the offshore fields However,the country's natural gas resources will not be sufficient to meet future demand; therefore, Thailand haslooked into importing piped gas from neighboring countries (potentially from Malaysia, Myanmar and,recently, Vietnam), or importing it in the form of LNG from international markets. The demand fornatural gas arises mostly from the power sector and the trend is expected to continue in the foreseeablefuture: A conservative estimate indicates that the country's demand will continue to exceed supply byover 60% for the next 1D-20 years. Gas is an attractive option for power generation, both economicallyand environmentally, when used in combined-cycle power plants (para. 6.4); it is ths feature of nauralVs in the context of Thailand's economy, along with its environmental benefits, that gives rise to thep.oposed project. Table 1.3 shows past gas consunpption.

TABLE 1.3: THAILAND: Natural Zas Consumption_(mmrfd)

Feedstock 69 100hxl Y 20 40Power 252 554

ToWal 341 694

Source: DEA, Thailand.

1.9 Coal. Coal resources are all relatively low grade; the quality is generally categorized aslignite, although some deposits verge on being sub-bituminous. Information about reserves is somewhatambiguous since no common standards are used to classify them. Total minable reserves are estimatedat around 1,200 million tons which, according to current projections for lignite demand for power;.- -teration and industry (about 25 million tons per year by 1996), should last for about three decades.Ln 991, about 65% of the total coal consumed in the country was for power generation which usesdomestic coal (lignite) exclusively. Non-power n e of domestic lignite is mainly in the cement ;tdustry.Lignite therefore, is expected to play a long-term, albeit limited role as an energy source.

1.10 Hydro. Hydroelectric potential is estimated at about 10,600 MWV, of which only 3,000MW have already been developed or committed. The remaining potential is, in general, economicallyless attractive and environmentally quite difficult to develop. Thus, the potential for hydro would belimited to small/medium scale new projects and low-impact pumped-storage stations. This said, noserious attempts have been made so far to clearly define and classify the various environmetalproblems involved, and, particularly, to quantify the costs of mitigating measures needed to curtil theadverse impacts. Thus, given the country's large and unexploited hydro potential, and given its needfor increased energy supply, Thailand should more rigorously reexamine its potential hydro projects;and, through an enhanced financing plan (schemes such as BOOT or BOT) and an enhanced design ofthe environmental mitigation plan, some options which are economically and environmentally viable,could materialize.

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C. Future Outlook and Energy Demand

1.11 Thailand's economic performance over the last ten years has been very impr.ssive,registering double-digit GDP growth over much of that period. While growth is expected to slow, theoutlook continues to be good because of a favorable international economic environment for Thailandand the country's sound economic policies and credit-worthiness. The Bank's long term projection isfor Thailand's economy to grow at 6%-8% over the next 10-15 years. With regard to the energysector, it is expected that private sector participation will increase, that the energy entities will soon becorporatized (and eventually privatized), and that the Government wil: intervene less in energy affairs.

1.12 Final energy demand projected by the Bank (as part of the analyses carried out for theFuel Option Study) is presented in Table 1.4 below. The Bank's forecast is slightly different from theGovernment's in that the Bank calculates a higher share of energy consumption in the transport andindustrial sectors.

TABLE 1.4: THA1AND - Forecast for Final Sectoral Energy Demand for 1993-2010(ktoe)

Sectar 1991a/ 1992y h [993- 1" 200s 2010hndustrial 9,533 10,382 11,089 15,415 22,813 28,510Transport 11,910 12,696 13,786 20,815 32,474 43,191Residential & Commercial 7,29 7,389 7,714 9,567 12,437 14,921Agrichre 1,827 1,922 2,003 2,464 3,154 3,612

TOTAL 30,4791 32,389 34,592 48,2611 70,7 90,234Implied Elasticity for Period 0.78 0.70 0.88 0.881 0.84 0.76Average Annual Growth for Peiod 6.9% 5 5.6% 5.0%

al Actual.h/ Estimated.Source: Bank Mission.

1.13 With regard to the type of fuel needed to meet the above sectoral demand, it is expectedthat (a) the consumption of non-wcommercial energy, such as bagasse in the industrial sector andwoodfuels and charcoal in the residential sector, will decline from its current share of 24% to 11% ofthe total by 2010, as the country develops; (b) industrial use of gas will be reduced to a level lowerthan the one currently projected by PTT, consistent with the priority ranking of the economic value ofgas in different applications (this will mean more gas for the power sector); (c) residential andcommercial sectors will increasingly use either LPG, as long as it is subsidized, or electricity (gas is noteconomic as there is no need for space heating, and kerosene, the most common woodfuel replacement,is not subsidized); (d) transport and agriculture will continue to use mainly oil (the role of compressednatural gas (CNG) in transport is expected to be very limited, if any) and (e) where end-use applicationis not a constmaint, imported coal, fuel oil, lignite and electricity will compete based on their totaleconomic costs, which include environmental costs. Table 1.5 provides the total prianry energyrequirements, including the fuels needed for the power sector.

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TABLE 1.5: THAILAND - Projected Primary Energy Requirement(ktoe)

1993 1998- 2005-- 2010--Oil 23,694 32,537 48,796 63,717

Gas 7,376 12,923 13,826 7,661

Coal 380 828 8,895 22,733

Lignite 4,536 5,875 9,331 12,551

Hydro 378 480 538 643

Total Commercial 36,364 '2,644 81,387 107,305

Non-Commercial 7,470 8,384 9,308 a 952

TOTAL 1 43,8341 61,0281 90,6951 117,1571

Source: Bank mission.

D. institutions

1.14 The institutions in Thailand's energy sector are mature, and their inter- and intra-sectoralarrangements are quite sophisticated. The policy framework is extensive and there are numerousenergy-related agencies that spread across many ministries and include several cabinet-level committees.The chart in the annex provides an organizational diagram of Thailand's energy sector.

1.15 The key governmental organizations involved in energy affairs are:

(a) At the highest level, the National Energy Policy Council (NEPC), which is chaired by thePrime Minister, and whose members include deputy prime ministers and ministers whoseportfolios involve energy, as well as representatives from the National Economic andSocial Development Board (NESDB), the secretary general of National Energy PolicyOffice (NEPO), the director general of the Department of Energy Development anidPromotion (DEDP) and the director of the Budget Bureau. On behalf of the cabinet,NEPC approves major policy changes, plans ar.2 projects in the energy sector and definesroles, functions and priorities of the various ministries and state enterprises in the sector;

(b) The NEPO, which is the secretariat to NEPC, and adts as an operating arm to theCouncil. NEPO functions primarily as a link between NEPC and the country's stateenergy enterprises. NEPO plays a pivotr4 role in fonrulating the energy sector policy aswell as providing coordination and advisory functions;

(c) The Department of Mineral Resources (DMR), whose Director General reports to thePermanent Secretary of the Min!stry of Industry; it is responsible for assessing thecountry's coal and petroleum reserves, and for the preliminary exploration of coal andpetroleum. Two of its important functions are to grant concession licenses for explorationand mining, and to supervise the various exploration and production activities (includingthe monitoring of their enviromnental impacts);

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(d) NESDB, which is a central planning agency that assesses the country's economy andprepares the five-year plans. In the energy sector, it is responsible for recommending tothe Council of Ministers whether it should approve or reject major energy projects;

(e) DEDP, which is a recent establishment (it assumed the responsibilities of the now-defunctNational Energy Administration), is under the Ministry of Science, Trchnology andEnvironment (MSTE), and is responsible for developing non-conventional energy sources.

1.16 The two major state energy enterprises are the Petroleum Authority of Thailand (PTI) andthe Electricity Generating Authority of Thailand (EGAT). PTT, the proposed borrower (see para. 4.1),is involved in downstream oil and gas activities (upstream activities are carried out by the privatesector; see para. 2.12). EGAT is involved in generating electricity and producing and utilizingdomestic coal (lignite). Since it was established about 25 years ago, EGAT has grown to a staff of32,000 with US$2 billion in annual revenues. At the end of 1991, it had an installed capacity of 8,000MW and generate. 50,000 GWh of electricity. As with ?1T, EGAT is devis4g plans for restruct'rngand privatization to promote a larger private sector role in power development. From 1994-1996, thiswill invoive (a) corporatizing EGAT, including the sale of EGAT equity on the security market; (b)selling 51% of the Electricity Generating Company (EGCO), an EGAT subsidiary created in 1992; (c)soliciting build-own-operate (BOO) proposals for new generating plants through an open competitionamong independent power producers and EGCO and (d) incorporating the Metropolitan ElectricityAuthority (MEA) and Provincial Electricity Authority (PEA), and increasing PEA's regionalization, toprepare for privatization.

E. Prices

1.17 Current prices for all energy products in Thailand reflect their actual economic costs,except lignite. Thai lignite, due to its poor quality (high sulphur and ash content), can not be traded inthe international market; therefore, its economic cost is based on EGAT's internal transfer price. Whileno other major issue exists in the pricing structure of the energy products in Thailand, some minordistortions remain in the price structure of petroleum products (LPG continues to be subsidized) and inelectricity tariffs (power distribution companies .ay no capacity charge). The Government is aware ofthe potentially negative effects these minor distortions can have on investment decisions and inter-fuelsubstitution and is taldng steps to narrow the differences, consistent with the structure of economiccosts. (Annex 1 provides the domestic prices of energy products. Gas prices are discussed in paras.2.8-2.11).

F. Issues and Strategy

1.18 In principle, Thailand's energy sector faces two major is-sues. The first is how to meet thecountry's future ena.gy requiemets, given the insuiiciency of domestic energy resources, in a mannerwhich is econrmically rational, enviromnentally sound and financially viable. The second is how todivide the heavy burden of massive energy investment between the public and private sector - giventhat neither can carry this alone - so as to ultimately shift investment to the private sector completely,

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without disrupting the country's rapid economic growth. The proposed project contains elements whichaddress both: The pipeline would transport domestic gas to the market (the fuel is the least-cost andleast-polluting solution for power generation in Thailand), and the proposed technical assistance includesa component for restructuring PTT to a corporatized and, eventually, privatized entity (see paras. 3.7and 4.234.28).

1.19 Other ;mportant issues in the sector are:

(a) Enviironental impacts. The environmental impact of energy production and consumptionhas become a topic of public debate and a real constraint to developing lignite powergeneration and hydropower. The Government recognizes the importance of these issuesand is committed to developing the sector in an environmentally sound manner. Thw, itnow requires the power sector and major industries to use pollution-control technologies,such as scrubbers, in all existing and future lignite-fired power plants and in the cementindustry. Further, the Bank is helping the refinery operation, through the Air QalityEnhancement Project (scheduled to be appraised in July 1994), to produce less pollutingprod cts. In addition, the Government is in the process of developing enviromnentalpolicies and standards to mitigate pollution through taxes, penalties and incentives.

(b) Reguatory Jfamework. The Govermnent has pursued sector efficiency objectives withconviction and the results are impressive. However, one key issue is that there is noindependent regulatory body. Given that the need for sector regulation in Thailand is notdriven by inefficiency, but by the need to bring in private investment, the regulatoryframework must be designed in conjunction with the decision on restructuring the sector.While the issue of regulatory framework at macro level is being currently addressedthrough an on-going sector study by the Bank (Increasing Private Participation andImproving Efficiency in State Enterprises), there is still need to examine the benefits ofregulatory framework at sectoral level. Therefore, the Bank has recommended (in theFuel Option Study) that the Govermment prepare an independent regulatory framework thatcould be functioning by the time Thailand restructures the sector (during the plannedcorporatization of the energy entities).

(c) Energy conservaion. The Govermnent recogiizes that energy use must be rationalized ifthe country is to cope with its supply constraints. Thus, conservation is a formal objectiveof Thailand's energy sector policy, which is beginning to move towards an integrated-resource planning approach that focuses both on supply and demand. Two prograrAs thatpresently address this are adopting a master plan for demand side management (D¶SM) andintroducing time-of-day tariffs aimed at reducing peak demand. The DSM mAster planproposed an initial five-year pilot program t'rough which EGAT would saveapproxinately 1,427 GWh per year by the end of the fifth year. These savings, whichalso include a capacity saving of 225 MW, would be achieved through iroentives for allcategores of consumers to produce and/or instaU energy-effitcent technologies. Theprogram is estimated to cost US$188 million. Potential benefits are calculated to be aboutUS$260 million in capital investment and US$30 million per year in fuel expenses. Thiswould equal a very low energy supply cost of US$2.051 per kWh. Also, the structure ofelectricity tariffs is being gradually improved through the introduction of time-of-daytariffs for major consumers. This measure aims to increase the power system's loadfactor, thus reducing expansion needs.

(d) Environmental ad S4fey Stand. There is a need to create an acceptable se,, ofenviroMnental and safety standards to exploit hydrocarbon resources in the Gulf ofThailand. This issue is currently being addressed through a study carried out by DMR(para. 3.13).

CHIAPrER B

GAS SUB-SECTOR

A. Badcground

2.1 Exploration for hydrocarbon in Thailand began about 1971 after the Governmentestablished the petroleum Law. Oil and gas exploration and development activities have been extensiveenough to conclude that the area has gas resources but relatively minor oil potential. The country'stotal hydrocarbon resources are spread over at least eight different geological structures, offshore andonshore. In the offshore areas, the most sigrificant to date have been found in (a) the Pattani Basin,which extends through the middle of the Gulf of Thailand and includes all the currenty producingUnocal fields (the source of supply for the proposed project) and (b) the Malay Basin, which extendsfrom Malaysian waters into the Gulf of Thailand and includes the Bongkot structure, the largest knownexisting gas field in the Gulf (also the source of supply for the proposed project). In the onshore areas,hydrocarbon potential is believed to exist in the northeast (in the Khorat Basin), and in the central-west(in the Phitsanulok Basin), where Shell's small Sirikit oil field is situated. Annex 2 provides adescription of Thailand's petroleum geology.

2.2 Most of the discoveries from work in the existng basins have been non-associated gmadeposits, which have been rich in heavier hydrocarbons, including ethane, propane and natural gasliquids (NGL).

2.3 Although the poteal for hydrocarbon resources exists, the prevailing geology in thebasins indicates that further development will not be easy: Due to the erratic deposit of fluvialreservoirs and complex structurig, the hydrocarbons are trapped in numerous small reservoirs thatned sophistcated drilling and recovery techniques. Further, the small size of many fields and therapid reservoir depletion create the need for a large number of offshore platforms, which, in turn, leadto high development and production costs. In a number of cases, the long lead time and additionalcosts have made field development uneconomic.

B. Domestic Gas Supply and lInport Potential

2.4 Due to the complex geology mentioned above, calculations of Thai reserves (prior toproduction history) are generally based on statistical occurrence rather than measured quantities. Inessence, when statistical methods are used, the disinction between the proven and probable reservesbecomes less clear, with the proven reserves being somewhat less assured and the probable reservesbeing somewhat more probable than indicated by the American Petroleum Institute (API). The officialbasis for the data on Thailad's hydrocarbon reserves are the DMR reports, which, in turn, arecompiled primarily from the latet information submitted by each company that has made discoveries.Based on these reports, the most likly level of gas resemves remaining in Thailand ranges from 6.5 to11 tef, and the possible reserves could be as high as 17 tcf. However, for the purpose of the proposedproject, only the cerdfied level of gas reserves has been used in the project analyses, which represents

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a conservative estimate. The details of the certified reserves which have been designated to the projecthave been provided to the Bank.

2.5 Except for minor oil production by tie Defense Department in Fang Basin (thenorthernmost part of the country) in the 1960s, comnercial production of hydrocarbon began in 1981by Unocal at the offshore Erawan field. This was followed in 1983 with the production of Thai Shell'sonshore Sirikit oil field. Table 2.1 lists the production by major fields since 1981. As shown in Table2.1, over the past 12 years, hydrocarbon production increased from 1,000 bpd of petroleum liquids and29 mmcfd of gas, to 49,00 bpd of liquids and 853 mmcfd of gas. Production is expected to increasefurther.

TABLE 2.1: I AD - Past Production of Hydrocatbon(Gas: mmcfd; Condensate/Oil: 1,000 bpd)

meI.da 1981 19s 13 1984 95 96 1967 6 169 1o L1 199 n go

Unoca I (Bwan)Gas 29 129 148 186 185 162 209 217 221 231 277 250coad. 1 6 6 7 7 7 6 6 7 8 10 9

Unocxl 1Baanpot, Satm, unatong. Kaphong)Gas 3 31 151 159 249 333 325 337 417 350Cond. - - 0 2 7 8 9 12 11 11 12 10

UnoalM (Funan, Jakrawan Gomin)Gas - - - - - - - - - - 0 151Co-d. - - - - - - - - - - 0 8

uXshell (Shirii)l

Gaslkc - - 5 17 28 29 31 30 32 41 42 45on!W - - 6 14 21 20 17 18 20 23 23 22

Es so (N_ }=Gas - - - - - - - 0 38 57

-§-XsoudPar Firddbanbs 29 129 156 234 364 350 489 580 578 609 774 853-- <>wad 1 6 6 9 14 1S 1S 18 18 19 22 27onR - - 6 14 21 20 17 18 20 23 23 22

a/ EsimatAd, as data not compiled by 2/10/93.Souce: DMR, PTr ana Bank nission esdmaWe.

2.6 Gas Imports. Given the country's limited gas supply, Thalba has often consideredimpordng gas either in the form of piped gas from the neighboring cointes of Malaysia, Myamarand, recently, Viet Nam, or in the form of liquefied natural gas (LNG) from international markets.While discssions with Malaysia and Myanmar have occasionally led to the various goveentsamnouncing final gas sales-prchase agreemens, to date no agreements have been signed. WithMyanar, negotations have resumed and it is expected that about 300 mmcfd gas will be importedbegining early 1998. With Malaysia, the issue is more complex because the two countries possessradically different gas utilization plans and different levels of relative need. Thus, it is expected that theThai-Malaysian joint development of the JDA gas fields in the Gulf of Thailand will progress morerapidly than will negotiations on imporng gas. Nonetheless, it is possible that about 150 mmcfd of gasfrom Malaysia will be imported by the year 2001, to be used in the border areas. The option of

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importing gas from Viet Nam is not being considered because that country does not produce enough gasto export. The high netback value that natural gas produces, and the projected growth in the country'spower generation (which ensures a high-volume gas consumption), justifies, prima facie, the large-scaleinvestments required to import LNG. The potential use of LNG in Thailand would be identical to thatof imported gas with regard to its economic value and priority ranking in various applications andsectors. The Government is looking into LNG option, to detennine whether it is viable.

C. Gas Demand

2.7 Demand for gas in Thailand is substantial: Based on estimates, it will exceed the projecteddomestic supply by an average of over 60% for the next 15-20 years. The largest consumer is thepower sector which currently uses over 90% of the country's total supply. Because of the enhancedeconomic value of gas (para. 6.4) when used in a combined-cycle power plant, as well as itsenvironmental benefits, the demand for gas in the power sector is growing. And, because demand forelectricity has grown at 14% a year over the last five years, even under a high-case gas supply scenarioof 1,700 mmcfd available by 2003, this quantity meets roughly just one-third of Thailand's powerrequirment, under a low growth scenario. Moreover, if the requirements of industrial users are addedto those of the power sector, the covAtry could use an estimated 3,000-3,500 bcf. This quantity wouldnot be available through domestc resources or from imports from neighboring countries.

D. Gas Prices

2.8 The unique features of the domestic gas industry in Thailand have produced a relatvelysophisticated pricing structure which involves a separate pricing system for producers and consumers.

2.9 Prodcer Prices. The cost of producing gas in Thailand is relatively expensive comparedto neighboring countries such as Malaysia or Indonesia. This is due to the gas fields' complexgeological features which result in tho well-head transfer price bearing the high cost of fielddevelopment and production. At present, only one major company, Unocal, is producing offshore gasin the Gulf of Thailand. By mid,-i94, Total Company will also produce offshore gas from theBongkot field (in the Gulf). While the gas sales-purchase contracts between PTT and the twocompanies are different, the principles are essentially the same: (a) the initial transfer price is based onthe long-run economic cost of supply and on the replacement value of altemative fuels; (b) the price-adjustment mechanism contains indices reflecting the international prices of energy products (mostlyfuel oil), the fluctuations in foreign exchange rates and in the domestic and international rates ofinflation; (c) prices include a floor and ceiling level to protect sellers and buyers and (d) prices areadjusted annually, except after devaluatons, when they are inmnediately.Y' The Bank-estimatedaverage well-head price for Unocal's gas ranges from US$1.77 per mmbtu to US$2.08 per mmbzu; for

.1/ The gs pcing stuctue for the Namphong field, which produces a relatively small amont of the dry gas used in theadjacent power plant, is somewhat different because of specific development costs and the composition of the gas (all methme).The average well-head price for Namphong gas is about US$1 per mmbtu.

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the Bongkot gas, the range is US$1.98 to USZ2.25 per mmbtu. The structure and level of producerprices in Thailand is consistent with international norms.

2. 10 Consumer Prices. The principle the Government applies when setting consumer prices(for power and industry) is also sound in that it links the consumer gas prices to alternative fuel pricesin each activity. The present price of gas to industry, which consumes less than 6% of the total, isintende,i to encourage LPG consumers to shift to gas-.' The price to the power sector - which usesover 90% of total gas - was previously set by the Government. However, on December 12, 1991, anagreement was signed between PTT and EGAT which set the price based on (a) the price paid by PTTto upstream producers (well-head price); (b) the average cost of gas transmission including a reasonablereturn to PTT and (c) the value-added tax. The Bank estimates that the current average price of gassold by PTT to EGAT is about 78 Baht per nmmbtu (US$3.06 per mmbtu). During negotiationsagreement was reached with PTT that it submit to the Bank, by December 31, 1994, an amendment tothe gas sales-purchase agreement (between PTf and EGAT), to ensure the sale and purchase of new gasreserves under terms and conditions satisfactory to the Bank.

2.11 Although current gas sales-purchase agreement referred to in para. 2.10 covers theprinciples of gas sales-purchase between PTT and EGAT, since last year, P1T and EGAT have beeninvolved in a Bank-sponsored study which would establish a long-term pricing formula for future gassupply that is in line with international standards. It would create two separate contracts - one for the"firm" gas supply and one for the "interruptible." A daily quantity would be defined for the firmsupply (about 500 mmcfd), to fuel EGAT's combined-cycle power plants, and the contract would be atake-or-pay agreement. The price of the firm contract would be equal to the pipeline cost oftransporting the gas, plus the gas commodity price, which is equal to PTT's volume-weighted averagepurchase cost. The price of an interruptible contract would be based on the cost of alternative fuel andnegotiated by the parties. The new price mechanism was approved by the Government on August 17,1992.

E. Role of the Private Sector

2.12 Thailand's hydrocarbon resources are produced either totally by the private sector orthrough a joint venture between the private sector and PTTEP, which is a subsidiary of PTT. In thelatter case, the private sector is the major shareholder and has included major international oilcompanies such as Unocal, Shell, Esso, Total and British Gas. In the oil sector, Thailand's threeexisting refineries are either privately owned (by Esso), or owned through joint ventures between theprivate sector and PTT (PTT owns 30% and 49% of Bangchok and Thai Oil refineries). ihailand iscurrently constructing two new refineries, with majority shares owned by Caltex and Shell. Indistributing and marketing oil, PTT competes with international oil companies, having a one-third share

2/ No such inecntive is provided to fuel oil users, because gas has a lower netback value when substiting for fuel oil.

3/ Industry's price is significantly higher than the one established for the power sector, since the margin of subsion betweenLPG and gas has been high, even after a discount, to allow for penetration of gas into the LPG market.

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of the market. The other two-thirds are shared among Caltex, Shell and smaller finns. The only areain which PTT has sole responsibility is the transmission of gas, the bulk of which is sold to EGAT.V1

2.13 With regard to private sector participation in gas transmission, the most likely investorswould be Unocal and Total, the two private gas producers currently active in the Gulf of Thailand.However, both have told the Bank they are not interested in participating in gas transmission because ofcorporate strategic reasons.1Y Not only are Unocal and Total disinterested, but no other private partyhas approached PTT or the Government to invest in the project. ADB, JEXIM and EIB, which arecofinancing it, have also found this same lack of interest from the private sector. In fact, with projectsin the oil and gas sectors of this dimension, where investors are interested in participating, they registerthis very early in the project cycle, often even before the Bank is involved. Thus, it is unlikely thatthere are any viable interested parties.

F. Experience with Previous Bank Loans

2.14 Until now, the Bank has made four loans to Thailand's oil and gas sector: The first (loan1773-TH) was to construct the country's first gas transmission pipeline; the second (loan 2184-TH) wasto construct a gas separation plant; the third (loan 2184-TH) supported oil field development; and thefourth (loan 3508-TH), now being disbursed, is to construct the Bongkot gas transmission pipeline.These projects, implemented over the past 11 years, have been completed on schedule and within thebudget, and have realized their main objectives. Three lessons are particularly relevant to the design ofthe proposed project. First, given that the region's geology is complex, the hydrocarbon reserves mustbe evaluated comprehensively (before proceeding to full development and production) and the high costof developing the fields should be addressed: The proposed project has considered these factors.Second, given Thailand's procurement practices and import tax laws, the Bank has learned to prepareprocurement packages in a way that inimzes their numbers, yet conforms with Bank guidelines, henceavoiding potential delays resulting from procurement-related issues. As a result, the proposed projectconsists of only about eight main single-responsibility contracts, of which the Bank loan will fund two.Third, the Bank learned that coordination at two levels was problematic; this occurs within the PTT(between the Engineering and Finance Departments), and outside (between PTT and EGAT), regardingthe timing, load requirements, capacity and type of power plants that rely on the PTT gas supply.During project preparation, the Bank helped increase cooperation and interactions between PTT andEGAT, as well as within the agency.

i/ Pff is also responsible for the primary transportation of oil in the country. However, Thailand has very little indigenous oil.

5/ In an October 27, 1992 letter to the Bank, Unoal stated that its 'reason for not wanting to paricipate is rooted in thebeliefthat we can return the maximum benefits to our shareholders when we stick to our core business, and that is developing andproducing oil and gas.' Total provided essetially the same response with regard to the Bongkot project. Moreover, thecompanies believe th e large capial commitment neerd to develop and produce the additional gas would constrain theirresources.

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G. Ratonale for Bank Involvement

2.15 The overriding rationale for Bank involvement is to continue helping the country build apolicy framework with which it can operate the sec or efficiently. For the many years that the Bank hasbeen involved in Thailand's oil and gas industry, the Government and energy-affiliated agencies havesought and implemented Bank advice on how to build such a framework. These interactions haveproduced major energy projects based on economnically-rational justifications, deregulation of all but oneof the petroleum product prices, rigorous analyses of environmental impacts (of the energy projects),and the initial reforms to ultimately create completely commercial entities. Further, the Bank, with helpfrom the agencies, identified the optimum fuel choice (see the Fuel Option Study) and prepared a masterplan for utilization of domestic and imported gas over the next decade or two. These activities havesignificantly enhanced the sector efficiency and its profitability; however, issues remain. The mostimportant are corporatizing/privatizing the energy entities (so as to raise capital to meet the massiveinvestment requirements); establishing an independent regulatory body (to assure private investors theirventure capital is protected by a fixed set of rules and procedures): creating an internationally-acceptable set of uniform environmental standards and regulations (to cxploit hydrocarbon resources inthe Gulf of Thailand); and amending the country's legal codes for oil and gas activities (to provide anenvironment that would attract greater private sector participation). The proposed project addresses oneof the key issues of corporatization, which constitutes a first step towards privatization. As for creatingappropriate regulatory structures, these can only be defined after the Government decides the nature ofthe restructuring (corporatization).

2.16 The project is consistent with the country strategy discussed by the Board in September1994, because the physical infrastructure and institutional weaknesses will be the main issues for thenext decade or two. It includes components relevant to both constraints. First, it helps finance theconstruction of a pipeline, which will ease the bottleneck in transporting the domestic natural gas.Second, it will train staff to carry out project analyses and application of safety and environmentalstandards, as well as help the borrowing entity reorganize towards a corporatized structure, whichwould reduce the public sector's need for investment capital.

2.17 The project is also consistent with the sector strategy because it promotes the use ofnatural gas, which the recendy completed Fuel Option Study concluded was the least-pollutng andleast-cost fuel with which to generate power.

2.18 Therefore, Bank lending in the sector is consistent with both the country and sectorstrategies and the Government decision regarding sectoral priorities. Without Bank involvement, keysectoral issues may not receive proper attention, and the development of an enabling environment, forgreater private sector participation may be deferred.

THI PROJECT

A. Background

3.1 Over 90% of Thailand's natural gas comes from the Gulf of Thailand, transported thr )ugha 34-inch offshore pipeline from the Erawan platform to Rayong, on the northern shore. The pipelinehas been operating for almost nine years, and its present flow rate is about 750 mmcfd. Althougn thepipeline has never operated at its maximum capacity of 850 mmcfd (because of limited supply), thelatest major inspection confirmed that the pipeline could safely transport that amount.Y

3.2 During the negotiations (in the spring of 1992) of Loan 3508-TH (Bongkot GasTransmission Project), PTT and the Bank agreed that the need for the second pipeline depended on (a)the present and projected reserves and production of gas from the Unocal and Bongkot fields; (b)maximum allowable capacity of the existing 34-inch pipeline (at that time, the latest inspection reportwas not yet completed) and (c) the possibility of malfunctions in the existing (sole) pipeline to Rayongand the speed in which the malfunction could be corrected.

3.3 To assess the above factors and to determine whether the second pipeline project wasneeded, the Bank agreed to provide, as part of Loan 3508-THl, US$2 million for the requiredinvestigations. The studies intended to confirm the reserves' availability, the time needed to developand produce gas and the optimal means of transporting it from the Erawan platform to the onshoreconsumig centers. Also, the studies would establish whether the proposed pipeline should beconstructed offshore, closer to the shore, or onshore.

3.4 Two studies were conducted. The first confirmed that gas was indeed available and a gasulization master plan study concluded that the proposed project should be given high priority and alsoddetrined the routing and size of the pipeline. The Bank reviewed the consultant's report and agreedthat the project constituted a high priority investment in the master plan created for the country's gastransmission network.

B. Project Objectives

3.5 The objectives of the project are to achieve greater efficiency in sector operations andincrease the utilization of domestic natural gas resources. They involve helping PITT to: (a) movetowards a fully commercial operation under the new organization; (b) strengthen its institutionalcapacity to apply safety and environmental standards as well 'as carry out project analyses and

6/ The Brish Gas Corporation conducted a comprehe inspection in April 1993, using the lates tectnology and asophiscated surveying mehanism to detect any corrosion and/or defonration the pipeline. MTe resutd of the inspection, inform of a summaiy report, was made available to the Bank, confirmig that the pipeline could in fiact wthstand a maximum flowTe of 85O mmcfd.

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investment programnming and (c) construct a pipeline to transport domest-i gas, which is the least-costoption to meet the country's growing power-generation requirements.

C. Project Description

3.6 The project consists of an offshore and an onshore pipeline and the facilities to transportthe natural gas produced in the Bongkot and Unocal fields in Gulf of Thailand to onshore locations incentral part of the country. Map IBRD No. 25766 shows the location of the offshore and onshorefacilities and the routing of the proposed pipeline as well as the existing pipeline. Annex 6 describesthe project facilities.

3.7 The major project components are:

(a) A technical assistance component, which includes a study on corporate strategies andfinancing plans for PTT's corporatization, as well as a training program for PTT staff inproject analyses (including investment programming) and in applying safety andenvironmental standards (see paras. 4.23-4.28)

(b) A 36-inch diameter, 425 km offshore gas transmission pipeline installed in water depthsranging from 200 ft-270 ft. It will extend from an existing platform at the Erawan field toonshore receiving facilities at Rayong;

(c) A 28-inch diameter, 110 km onshore pipeline that extends from Rayong to the block valveNo. 6, near EGAT's power plant at Bang Pakong;

(d) Related facilities at Erawan riser platform, at Erawan compression and central processingplatform, at Rayong receiving terminal and at block valve no. 6, that include scraperlaunchers and receivers, slug catchers, pressure and flow controls, pipe manifolding,various tie-ins, as well as an onshore compressor station;

(e) Modification/expansion of the existing supervisory control and data acquisition (SCADA)system and the pipeline telecommunications network;

(f) Consultancy and management services for bisic design, detailed engineering, preparationof bid documents, procurement of goods and works, supervision of the construction andcommissioning the facilities;

D. Status of Project Preparation

3.8 The project is in an advanced stage of preparation. Technical specifications, details aboutthe project management unit, various studies and basic design have been partially completed. Contractsfor the pipeline materials and the coating (financed by the ADB and JEXM), have been awardedaccording the ADB's procurement guidelines. Bidding documents for the contract to lay offshore pipehad been prepared by PTT's consultants (Bechtel), and were reviewed with the Bank in late January.

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The bid documents were issued and the bids have been received. The Bank is in the process ofreviewing the bid evaluation report submitted by PTT. Other engineering, procurement and projectrelated activities are progressing according to schedule. No land acquisition problem is anticipated (seepara. 3.15). The overall status of project implementation suggests no impediment to the current rate ofprogress.

E. EnvironmentW and Safety Aspects

3.9 Termns of reference for the environmental impact assessment (EIA) of the project wereprepared jointly by the Bank and PTT's environmental consultants (the Team Company), which alsoconducted the EIA for the Bongkot Gas Transmission Project (Loan 3508-TH). The final ETA reportfor the proposed project has incorporated the Bank's comments, including measures to ensure that theproject complies with the Bank's environmental guidelines (see Project File for a summary of the EIA).

3.10 Tht project would have minimal negative impact on the environment because the use ofnatural gas would be significantly less harmful than either fuel oil or coal. While natural gas is notpollution free, it is inherently cleaner than other fuels: It is free of most pollutants present in liquid andsolid fuels and generates less carbon dioxide (CO2). The reduced CO2 emissions offer a highly cost-effective response to the greenhouse effect. The gas used in combined-cycle power plants emits only40% as much CO. as a coal-fired power plant. Moreover, treated natural gas has no sulfur content. Inaddition, the gas to be transported by the project pipeline is non-associated gas, which carries much lessenvironmental risk than of oil or associated gas. Nonetheless, a few areas carry some potential risk tothe environment. These include the disruption to marine life (which could be caused by changes inseabed conditions near the pipeline during construction); the discharge of liquids such as processedwater, deck drainage and sewage from production and living quarters platforns; the disposal ofmercury (which is sometimes present in the gas) and the noise and vibration caused by equipment onthe production platforms. The EJA report fully addresses these issues and provides for appropriateactions such as pre-treatment of liquid effluent before discharge to the sea, safe disposal of solid wastesto approved land sites and safe disposal of elemental mercury. Any disruption to marine life would notbe severe because the project involves only about 0.37 square kilometers of seabed. In fact, once thepipeline is operating, it is expected that its surface would provide attachment points for plant speciesand will provide cover for fish. The design of equipment will be according to intenational standardsfor maximum safety and allowable levels of noise and vibration. Further, the EIA report will analyzealternatives, including the effect of various pipeline routings on natural biological resources such ascoral reefs. Proposed measures will ensure that the environmental impact, if any, will be kept withinlimits prescribed by Bank guidelines. During negotiations, agreement was reached with PIT that it willtake all measures required on its part to ensure full implementation of the action plan contained in theEnvironmental Assessment Report (pam. 3.9).

3.11 The entire project design will be in accord with international safety codes and standards.Natural gas condensates will be separated from gas on the production platforms, before the gas isintroduced into the pipeline. However, small quantities of liquids will be present in the gas as theresult of condensation of hydrocarbon gases; thus, the condensed gases will be periodically removedfrom 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).

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3.12 Offshore facilities are being constructed by Unocal and the operator (Total) of the Bongkotgas field (for upstream facilities), .nd by PTT's construction contractor (for downstreatn facilities).Unocal and Total have extensive e perience in similar operations elsewhere in the world. Theconstruction of the downstream facilities will be supervised by Bechtel International, which also has vastexperience in this area. These companies use high standrds of safety and environmental protection,and they require the same from their sub-contractors.

3.13 Further, a study for Development of Environmental Standards and Regulations forHydrocarbon Exploration and Exploitation in the Gulf of Thailand was initiated by the Bank as part ofthe Bongkot Gas Transmission Project. The objectives were to assess present environmental legislationand regulatory provisions, as well as current concessionaires' practices, and drft regulations andguidelines for environmental control with respect to hydrocarbon exploration and exploitation in theGulf of Thailand. It recomnends (a) strengthening the Thai environmental institutional processes,including reporting, review and approval procedures; (b) providing standards and guidelines forenvironmental impact assessments and for environmental management and monitoring by DMR; (c)establishing concessionaires' requirements for environmental compliance and (d) notifying authoritiesabout oil spills or other releases. In addition, the study recommends various operational standards andguidelines for the construction process and management activities for both onshore and offshorefacilities. During negotiations, assurances were given by PTT that it would use its offices to encourageDMR to implement the recommendations contained in this study. Furthermore, during negotiations, itwas also understood that PTT would assist in persuading DMR to conduct a base-line environmentaldata survey for the Gulf of Thailand.

3.14 PTT's operational safety record has been excellent, and it is expected that it will operatenew facilities according to the same high standards. Notwithstanding PTT's excellent operational safetyrecord and its commitment to sustaining the environment, the oil and gas industry in Thailand is stillrelatively new and the industry has not yet produced the standards and regulations needed for safety andenvironmental protection. P'IT currently has no well-defined safety engineering standards andenvironmental regulations, nor does it have an adequate institutional framework with which it canproperly administer this aspect of its operation. As part of the loan 3508-TH, agreement was reachedthat US$200,000 would be included for consultancy services to help PIT adequately prepare safetyengineering and environental standards for its entire operation; also, that PIT would implement thestudy's recommendations. The study is currently being prepared and its implementation should beginby September 1994. During negotiations, agreement was reached with PfIT that it will implement therecommendations of the study. Regarding the institutional framework, PIT'S new organization,effective January 1, 1992, includes a safety and environmental committee chaired by P'IT's Governoras well as a safety and environmental standards divisions in each of four business units. The heads ofthese divisions report directly to the presidents of the respective business units. Further, each divisionhas one or more sub-divisions (e.g., for pipeline and gas plants within the natural gas business unit) toenforce the standards and regulations at the operational level. While PlT's environmental arrangementis satisfactory, the staff will need more skills and experience to properly apply and execute the safetyand environmental regulations resulting from the above study. Therefore, the proposed project includesabout US$150,000 to train PTT's environmental and safety staff. During the negotiations, agreementwas re: ched with PTT that it will carry out the training program for its staff by March 31, 1995.

3.15 The number of people expected to be resettled within the five meter right-of-way is about40. During the negotiations, PTT and the Bank agreed on "Principles for Payment of Compensationand Relocation" of the affected persons under the project. A field survey conducted by the Bank's

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Resetlement Specialist after negotiations has confirmed that the number of affected people will beapproximately 40. Furthermore, some structures such as shacks and animal sheds would also need tobe acquired. For most of the route, the pipeline will be built in the existing EGAT right-of-way, whichis well protected and maintained. However, if, on the basis of subsequent detailed surveys, it is foundthat the number of affected people is substantially more than the numbers indicated in the informationcurrently available, the same principles of payment of compensation and resettlement would be appliedfor them. It was agreed that in that case, PTT and the Bank would, however, need to revisit the issueof compensation and resettlement.

F. Project lmplementation and Schedule

3.16 PTT will assume overall responsibility and control of project implementation (see Annex5, Project Implementation Organization). In the past, it has implemented several similar projectsincluding the construction of the existing 34-inch offshore pipeline and the Bongkot Gas Transmissionprojects, both financed by the Bank. PIT has appointed Bechtel International Inc. to assist in carryingout all stages of the project implementation cycle. PTT personnel will also be assigned to the projectfor on-the-job training and other selected tasks.

3.17 The critical-path master schedule prepared by PTT and Bechtel calls for completing thephysical works by March 1996 (Annex 4). This schedule may be somewhat optimistic, although thework has progressed according to this timetable until now. However, to allow for the possibility ofdelays during testing and commnssioning, the project completion date is assumed to be June 30, 1997.

G. Projet Cos

3.18 The project is estimated to cost the equivalent of US$674.5 million, including taxes andduties (US$22.2 million) and interest during construction (US$75.1 million). Foreign exchange coststotal US$565.6 million or 84% of total costs. Table 3.1 gives a breakdown of project costs by majorcomponents. The estinate is based on 1993 prices and many items reflect the acal prices or thoseprovided through informal but firm quotations. A 10% physical contingency has been added to the basecost estimate and price contingencies of 3.2% and 6% have been applied to the foreign and local costcomponents of the base cost plus physical contingenr v. respectively. The physical contingency isadequate considering the advanced stage of project desil. .. 4 the fact that pipeline engineering andmaterial involve few uncertainties. While the physical contiugency allowance for the constructioncontract may need to be higher than 10%, the allowance could be lower for pipeline material; therefore,an average of 10% is considered adequate. The price contingencies are based on Bank guidelines forintemational price increases (for foreign exchange costs) and the Bank's projection for price increases inThailand (for local costs). Taxes and duties were based on an average rate of 40% on all goods subjectto such rbarges. The interest during construction is calculated based on PIT's financing plan, applyingappropriate interest rates and the grace period of each lender, and assuming that interest will be accruedonly after funds are disbursed.

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TABU 3.1: TlHlAND - Project Cost Estimates(US$ million - 1993)

Baht olon US$ dmil ForeipCoinpa_e_tsl a s % ofCouxponents ~ ~iLoc a Forgn Total Local_| Forelp | jTotalW

Land Acquisition 122.4 - 122.4 4.8 - 4.8 0

Pipe MaterW - 4,115.7 4,115.7 - 161.4 161.4 23.9

Pipeline Coating - 1,922.7 1,922.7 75.4 75.4 11.2

Onslhore Pipeline Construction and 255.0 765.0 1,020.0 10.0 30.0 40.0 5.9Commissioning

Offshore Pipeline Construction and 624.8 2,626.5 3,251.3 24.5 103.0 127.5 15.3Commissioning

Facilities- SCADA/Telecomniunication 51.0 63.8 114.8 2.0 2.5 4.5 0.4- Materials 30.6 66.3 96.9 1.2 2.6 3.8 0.4- Installtion 45.9 107.1 153.0 1.8 4.2 6.0 0.6- Cmpressor Station 61.8 561.0 624.8 2.5 22.0 24.5 3.2

Corrosion Control 76.5 40.8 117.3 3.0 1.6 4.6 0.2

Consultancy Services 329.0 387.6 716.6 12.9 15.2 28.1 2.2

Corporatization Study and Traminig 0.0 51.0 51.0 - 2.0 2.0 0.3Program

PTT Project Mane 102.0 0.0 102.0 4.0 4.0 -

Insurance 7.6 53.6 61.2 0.3 2.1 2.4 0.3

Taxes and Duties 566.1 0.0 566.1 22.2 - 22.2___ -.

Base Cost 2274.6 10,761.0 13,035.6 89.2 422 511.2 62.5

Physical Contingency 227.0 1,076.1 1,303.1 8.9 42.2 51.1 6.3

Price Conting-cncy 275.4 670.7 946.1 10.8 26.3 37.1 3.9

Total Project Cost 2777.0 12,507.8 15,284.7 108.9 490.5 599.4 72.7

1e s_During Con fuction (O 0.0 1,915.1 1,915.1 - 75.1 75.1 11.1

Total Ibang Required 2777.0 14,422.8 - 17,99.8 108.91 S65.6 6745 | 83.8

Source: Bank mission estims.

H. Project fTh Cindg Plan

3.19 Total fmnaning required, including interest during construction (estimated at US$75.1million based on the 4-year implementation period), would be US$674.5 million (see Table 3.2). Thefinacing plan has been developed on the basis of discussions with PIT, the Export-Import Bank ofJapan (JEXIM), the Asian Development Bank (ADB), and the European Investment Bank (EIB). Theprocurement packages were designed to take into account the various co-lenders' internal requirement3,the project implementation schedule, and IT's concern regarding its large exposure to non-dollar hardcurren-y, particularly the Japanese yen.

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TABLE 3.2: THAILAND - Project Financig Plan(US$ million)

I Co4Lnauer Load Forep Tot| %

Asian Development Bank (ADB) - 100 100 14.8(ADD together with lEXIM will fIance 73% of pipeline material and coating)

Japan Exim Bank (JEXIM) 100 100 14.8

European Investment Bank (EIB) - 47 47 6.8(EIB will finance onshore pipeline construction)

PTT's commercial borrowings and bonds - 100 100 14.8

PTT's intermal cash generation 93.6 78.9 172.5 25.7

IBRD 15.3 139.7 155.0 23.1

Total Fb ng Required |5 56S.6 045 101

Source: Bank mission estimates.

3.20 The Bank loan would fnance the construction of the offshore pipeline as well asengineering and project management consultancy contracts, studies and training (US$155.0 million).ADB and JEXIM would joiindy finance about 72% of the cost of the pipeline materials (linepipe) andcoating contract, and the EIB would finance the construction of the onshore pipeline. The proposedBank loan of US$155.0 million would be made directly to PIT at the Bank's standard terms forThailand. PIyT would bear the foreign exchange and variable interest rate risks, which would beguaranteed by the Government. The Bank loan would be for 17 years, including four years of grace atthe Bank's variable interest rate. The loan would finance 23% of the total project financing requiredand 27% of its foreign expenditures.

3.21 Since the Bank loan will become effective after the ADB/JEXIM and BIB loans, it wasagreed that PIT would promptly notify the Bank when the respective loan become effective (the EIBLoan Agreement stipulates cross-effectivuiess with the Bank loan).

I. Procurement and Disbursement

3.22 Procurement. Procurement arragements are summarized in Table 3.3 below. The costof each item includes its pro-rata share of the project's physical and price contingencies.

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TABLE 3.3: THAILAND - Summary of Procment Angeme(US$ Million)

P focmurment Method TProject Elments f - O 1h N.B.F. TotS)

Ld and Right of Way . S.9 5.9

Works

- Offshore pipeline construction 119.7 29.9 149.6(119.7) (119.7)

- Onshore pipeline construicon a/ 47.0 47.0

- P 'eline material and coating - -l 275.3 275.3- Facilities - 45.5 45.5

Enigineeng and management services

- Primary consultans - 33.5 - 33.5- (33.0) - (33.0)

- Prr's project management - 4.9 4.9

Miscellaneous

- Corrosion contol - 5.5 5.5- Insurance - 2.8 2.8

Consultants

- Cipoatzation study and tning 2.3 - 2.3(2.3) (2.3)

Taxes and Duies 27.1 27.1

TOTAL | 119.7 35.8 443.9 599A_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ j (1 1 9.7)1(3 5.3 ) j _ _ _ _ _ _ j(1 5 O

I/ Financed by EIB._/ US$200 million of the amount is fnanced by ADBWJEXIM.

Note: Figures in parentheses are the amounts fianced by the Bank.N.B.F.: Not financed by the Bank.Other: Includes consultant services.

Soune: Bank mission esdmates.

3.23 The following four major contacts comprise the bulk of the procuremen:

(a) Supply and delivery of pipeline material and coating contract (with a total estmated costof US$275.3 million, US$200 million of which is being financed by ADB-JEXIM and thebalance by PMT), which is being awarded under international competitive bidding ([CB)according to the ADB's procurement guidelines;

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(b) Engineering consultancy and project management contract (US$33.5 million), a Bank-financed component, which has already been awarded by PTT according to the Bank'sprocurement guidelines for the use of consultants;

(c) Construction of the onshore pipeline contract (US$47 million, financed by EIB), whichwill be awarded according to ElB's procurement procedures; and

(d) Construction of the offshore pipeline contract (US$149.6 million, of which US$119.7million is financed by IBRD), which will be procured through ICB according to theBank's procurement guidelines and using the Bank's standard bidding documents.

3.24 Various equipment and miscellaneous items, including compressors, are also needed forthe project. These items would be supplied and installed by PIf's contractors. PTT would alsoprocure land, civil works and buildings in accordance with its own procurement procedures, which aresatisfactory to the Bank. The remaining consultancies included in the project would be selected andappointed according to the Bank's guidelines for use of consultants.

3.25 All civil works and engineering-management consultant services contracts would be subjectto Bank's prior review except studies and training conts for the employment of consulting firmsestmated to cost less than US$100,000 or for the employment of individuals estimated to cost less thanUS$50,000.

3.26 Disbursement. Loan disbursement is based on the assumption that the loan will becomeeffective in the first quarter of the Bank's fiscal year 1995. The estimated disbursement of the Bankloan is smmized in Table 3.4 below. It is expected that it will be fully disbursed by June 30, 1997(para. 3.17), the scheduled completion date of the project. On this basis, the closing date is set forDecember 31, 1997. The scheduled disbursements are faster than the standard profiles for the regionand the subsector, reflecting the advanced stage of project preparation. Phasing of the estimateddisbursements and the Bank's standard disbursement profile for the subsector are shown in Annex 7.

TABLE 3.4: THAILAND - Esuimated Loau Disbursment(US$ Million)

Bank FY 199 196 1997

_nnual 7s 765Cumumla 75 140 155

Source: Bank mission esimates.

3.27 Due to a tight project implementation schedule and the critica nature of the engineeringconsultancy and management services, PTT had to advance its contract with Bechtel. Furthermore,advanced procurement action for offshore pipeline construction contracts would also be needed.Therefore, retroactive financing equal to US$15 million is recommended for expenses incurred afterSeptember 1, 1993, to partially reimburse amounts of the consultancy and offshore constructioncontracts, already paid by PIT through advanced contracting approved by the Bank.

3.28 The Bank loan would be disbursed against the categories outlined in Table 3.5 below:

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TABLE 3.5: THAILAND - Allocation of the Proposed Bank Loan(US$ million)

Components Estimated cost Inlding \a Pctage of Expeditesphyskal and price contgeny cced l

Construction of Offshore Pipeline 108 100% of foreign expenditures

Engineering Consultancy and project supervision 30 100% of expenditures

Corporatization study and training programn 2.5 100% of expenditures

Unallocated 14.5 I

TOTAL IqSSOl

\A In this Table estimated cost of each component h.7s been reduced by 10%, and shown as unallocated, to provideflexibility in the event of fubture loan reallocation.Source: Bank mission estimnates.

3.29 All disbursements would be made against full documentation. To the extent possible,withdrawal applications should be consolidated into amounts of US$1.0 million equivalent or more,prior to submission to the Bank.

J. Monitoring, Reportng and Supervision

3.30 The Bank will monitor the progress of the proposed project in terms of physical executionand financial reportng to ensure that all conditions of the proposed loan are satisfied. For this purpose,the Bank would, on average, conduct two supervision missions per year during the active project phaseto review project implementation, inspect job-site activities and discuss, as required, any related matterswith Government and PTT officials. In addition, PIT would be required to forward periodic progressreports. During negotiations, agreement was reached with PITT regarding the format, content andfrequency of these reports. The basic requirement would be quarterly progress reports for eachapplicable project component and PIT's semi-anmual and anmnal financial and auditors' reports asdefined in para. 4.18.

3.31 Project supervision by the Bank would be coordinated through a supervision planpresented in Annex 8, and confirmed during loan negotations. Bank field supervision would requireabout 44 staff-weeks during the life of the project, of which about 28 would be needed during the firsttwo years of implementation. Supervision would be carried out mainly by Bank technical and financialstaff, which would include an enviromental specialist.

THE BORROWER

A. Background

4.1 The borrower of the proposed loan will be the Petroleum Authority of Thailand (PTT)which was incorporated as a State Enterprise under Petroleum Act of Thailand (BE 2521) in 1978 forthe purposes of developing the oil and gas sector and enhancing Thailand's fuel security.-' It is whollyowned by the Kingdom of Thailand and falls under the jurisdiction of the Ministry of Industry. Itbecame operational in July of 1979.

4.2 The role of PTT has been critical in developing Thailand's oil and gas sector which hasgrown substantially through private and public sector initiatives. PTT's man area of activity is in thetransportation of oil and gas and distribution of petroleum. It is involved in (a) upstream operationsthrough PTT Exploration and Production Co., LTD (PTTEP), a wholly-owned subsidiary which wasestablished to handle petroleum exploration and production activities and (b) downstream activitiesthrough various joint ventures.Y Table 4.1 provides a list of PTT's joint ventures and the percentageof PfT's share in each entity.

TABLE 4.1: THAILAND - PITs Joit Ventures

[ ~~~~~Joint Vaiture % Sham n1a19

PrT RExploration and production 84.63Thai Oil Co. Ltd 49.00Bangclak Petroleum Co, Ltd 30.36Banglok Aviation Fiuel Services Co, Ltd 10.00Rayong Refinery: Shell 36.00Star Petroleum: Caltex 36.00Thai Petroleum Pipeline System 30.60lPiel Pipeline Tranwortion Ltd. 10.00Lube 0O Blending Plant 70.00Lube Base Oil Plant 30.00Thai LNG Co, Ltd 10.00Thai Petroleum Tanportion Ltd. 100.00National Fertlization Ltd 12.00National Petrochemical Co. Ltd. 49.00Thai Olefin Co, Ltd. 49.00The Aomatics Thailand) Co. Ltd. 100.00

1 it was formed by combining two previously existng state enterprises: the Naural Gas Organization of Thailand mid the OilFuel Organization.

It A tchnicality in the Thai Petroleum Law prevents P ftrm co-venturhg dhily with pivae exploration and production.PIT can participate in joint ventues trough PITEP which, as a limited company, can legally be the co-venturer. Pl'samounts are kept separte from those of PTT.

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B. Organization

4.3 PTT reorganized in January of 1992. Its current structure consists of four business unitsand a head office. The organizational chart of PTT is available in the anmex. The business units are:(a) Oil Marketing (including logistics and transportation, trading, refming and marketing); (b) NaturalGas; (c) Petrochemicals; and (d) Central Services. Petrochemicals is a fairly small operations andCentral Services provides technical and construction support to other operations. One of the purposesof the restructuring of PTr was to create separate profit centers as an interim step to PTT's eventualcorporatization or privatization of the various business units. Each unit operates on a commercial basisand is responsible for PTT's interaction with the joint ventures in the respective fields. The head officeis responsible for the overall corporate planning, project preparation and corporate finance.

4.4 In October 1993, PTT's Board expanded from 11 to 15 members, increasing the numberof appointees by the cabinet from five to nine. As such, this may potentially reduce PTT's autonomy,which had gradually increased in the last few years.

4.5 The Governor and the Chairman of the Board of Pff are appointed by the Council ofMinisters, upon the recommendation of the line Ministry. With the exception of the current Govemnor,who has risen through the ranks of PTT, previous governors were from outside of PMT. Boardmembers are generally high level civil servants and include representatives from the Ministries ofFinance, Industry, Transport and Communications and the Juridical Council. The Directors act in apart-time capacity. PMT also has an executive committee, consisting of the Chainnan of the Board andfive Directors. The Executive Committee meets frequendy and is empowered to make decisions oninvestments, contracts, staffing and other operational matters.

4.6 The management team within PIT consists of the Governor and three deputy governors incharge of Finance, Corporate Policy & Planning, and Human Resources. Below the deputy Governorsare vice presidents responsible for the day-to-day operations in finance, planning, and human resources.The Vice Presidents of each business unit report directly to the Governor. In addition to the permaentExecutive Committee of the Board, PTT also uses ad hoc anl standing committees to analyze specificissues. Vertical communication between top management and line managers is adequate though some ofthe policy and operational procedures, especially since the reorganization, have not yet been fullyformulated and communicated to staff in writing. This has caused some overlap of activities,particularly between the business units and the head office. This issue will be reviewed and addressedas part of the proposed corporatization study.

4.7 Overall, PIT is a well-run entity. Because of its strong financial performance andefficient operation, PTT has met Ministry of Finance's criteria for a "good state enterprise" and,therefore, freed from some common requirements of the public sector, such as pay scales, bonumses andreward systems, recruitment, and promotion and procurement procedures. Also, PIT has ioducedcommercial practices in many areas of its operations and is currently experimenting with such initiativesas cost management program, introduction of business performance measures, etc. Despite these, PITstill has to meet a number of conditions that are required of all state enterprises but which at timesconflict with a fully commercial approach. For instance, stringent and time-consuming budgetary,financial and accounting requirements of the Ministry of Finance still absorb a large proportion of

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management time. In addition, decisions concerning the investment plan and financing venues continueto be frequently determined by the Government. These still limit PTr's autonomy and independence.

C. Staffimg and Training

4.8 PTT's staff totaled 3,600 at the end of fiscal year 1993 and this number has been steadilydeclining since 1989 (Table 4.2). The skills mix has also undergone a significant change. The numberof university graduates has risen from 1,239 in 1988 to 1,700 in 1993, while the number of low skilledstaff has declined from 1,573 to 1,000. This underlies PIT's attention to improving the quality and theproductivity of its staff. Given PTT's expansion in assets and lines of operations, this decline indicatesa de facto downsizing. PTT has also an active training program. In addition to in-house courses andprograms within Thailand, in 1992 and 1993, 120 and 160 of PTT's staff attended various trainingprograms overseas, among them executive management programs at reputable universities in the UnitedStates. However, the Bank and PTT have agreed to strengthen the areas of project analysis, planning,investment programming, corporate finance and financial systems, which are incorporated into the$350,000 technical assistance component of the project (see paras. 4.13 and 4.27).

TABLE 4.2: THAILAND - PTT's Staffing Profile

___ ~~~~199 198 Mim 8(901 119119931Univesity Gaduas 1,239 1,398 1,361 1,364 1,600 1,700

Vocational Staff 927 887 957 _ _ __900 900

1,573 1,491 1,446 1,410 1,200 1,000

TOTAL 3,739 3,776 3,1 3,720 3,700 3,600

4.9 For several years, with Thailand's economic boom, PIT encountered a high level of turn-over of experienced staff. Under the system in place through FY91, PTr was bound by thegovernment salary scale which remained out of pace with opportunites offered in the private sector.After attaining the 'efficient enterprise" status, PTT has changed its salary structure. In 1992 and1993, PTT increased staff salaries by an average of 29.7% and 37%, respectively. The overallobjective is to keep salaries within 80% of private sector levels, which, combined with benefitsgenerally in the purview of the public sector, such as job security and generous pensions, shouldmaintin PIT's competitiveness.

D. Operations and Mnagement

4.10 Accounting System. P7T's accounting system is adequate and conforms with generalmodern oil and gas industry practices. The natural gas fnancial accounts are modelled after US gasindustry principles. PIT maintains separate accounts for the Oil, Gas, Central Services and HeadOffice. The accounts for the business units are prepared by the accounting and finance division of therespective organization and aggregated at the head office. Accounting applications such as general

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ledger, payroll, inventory transactions, accounts payable, and accounts receivable have been fullycomputerized. PITT prepares annual budgets for its capital and operating expenditures; it also preparesfive-year forecasts for facial planning purposes. Periodic reports are also prepared, enablingmanagement to compare actual results against budgeted amounts. The budget process has beenoperating satisfactorily. Nevertheless, with the expansion of its own operations as well as its growinginvolvement in joint ventures, PTT may have already outgrown its current accounting and financialsystem. These could be enhanced and expanded to incorporate more on-line linkages to the varioussubaccounts to allow for a substantially faster and more accurate means of consolidating variousoperations and to provide management with the flexibility to retrieve critical information on a timelybasis. This will be addressed under the assessment of ?TT's organizational setting which will becarried out under the proposed corporatization study (see paras. 4.23-4.28).

4.11 PITT has a good record in project cost control, implementation and management. It hasbeen borrowing from the Bank since its inception and is very familiar with the Bank's procurement anddisbursement guidelines. In the past, processing of bid docments, bid evaluations and award ofcontracts have been carried out efficientl' and on time.

4.12 Accounting Practices and Principles. PITT prepares its accounts in accordance withgenerally accepted accounting principles of Thailand which are in concurrence with the range ofaccounting principles recognized by the international accounting standards (LAS) for reportingtiansaction. In general, PTT recognizes assets, liability, equity, revemnes and expenses on accrualbasis. Inventories are valued on a first-in, first-out method. The straight-line method is used fordepreciation of property, plant and equipment over 30,000 Baht. Those below this amount areexpensed in the acquisition year.

4.13 Like many other countries, the Thai accounting principles differ in several instances fromthe LAS, as the LAS principles are not compulsory for countries to adopt.9' The main differencesbetween IAS and Thai accountng principles that would have an impact on PIT's accounts are (i)accounting for retirement benefits, and (ii) accounting for investments in joint ventures and subsidiaries.Regarding the former, PTT has a defined benefit plan for employees but is not required to calculate aperiodic pension cost based on accrued benefit valuation method. Concerning the latter, LASrecommends different accounting methods for holdings below 20%, between 20%-50% and above 50%,in consolidating a parent company's financial statements. Again, PIT's consolidated statements includePTT's own operations and not its holdings in the various joint ventures and subsidiaries listed in Table4.1 in accordance with the LAS recommended methods. Both of these practices, pension accounting andconsolidated statements, are likely to present a substantially different asset/liability picture for PITwiich cannot be assessed at the moment. In preparation for an evenual adaptation of these principlesby the Thai accounting standards board, these areas will be addressed in the design and enhancement ofthe financial and accounting system that has been proposed under the proposed project (paras. 4.25 and4.27).

4.14 PITT's accounting for foreign exchange losses is in accordance with LAS. PiTT's foreignexchange exposure results from its operating (oil trading) and its borrowing activities. IAS and theThai accounting principle concur (for the period under review) that exchange differences arising fromoperating activities be taken into income of the respective period. Exchange differences resulting from

2/ For intnce, there are significant differencs betwn the US generally acceted accoig principles and the LAS.

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balance sheet transactions, mainly long term debt, are recorded as deferred items and are amortizedover the remaining life of the respective itemA.2

4.15 Intenual Audit. PIT has an office of internal audit with a staff of approximately 43auditors of engineering, economic and finance background. It is an effective management tool and itreports directly to the Governor. Its main activity has been to carry out post-implementation reviews ofPTT's major projects. As such, it has been functioning more as an operations evaluation unit thaninternal audit, though it is technically responsible for audits of all of PTIT's operational work, includingaccounting and financial functions, and compliance with various company policies and procedures. Theunit should further carry out routine compliance and performance audit of PITs policies and otheroperations to highlight to management where further gains in efficiency can be made. These factorswill be incorporated into the corporatization study that has been proposed under the project.

4.16 Under the previous loan, PITT agrctx; to recruit 3 additional engineers. However, theresources of the unit may need to be further increased to allow for hiring of specialized consultants inareas where PTT's in-house expertise in the internal audit unit may not be sufficient nor economicallyviable to employ on a permanent basis (PTT has agreed to this). Furthermore, PTT may want toconsider rotation of staff into and out of the unit to bolster the units image as well as staff moral.

4.17 Extera Audit. PTIT's external audit has in the past been performed by the Office of theAuditor General (AG) which is responsible for auditing all state enterprises. The audit is performed inaccordance with accepted accounting and auditing standards in Thailand (see para. 4.12). The AG willcontinue to carry out PIT's formal audit which is acceptable to the Bank.

4.18 PIT is attempting to become a world class oil and gas company and is continuing toimprove its organization to fulfill its role as a modem and competitive energy company of internationalstanding. As part of this process, PTY has recognized the usefulness of preparing also financialstatements that conform to international accounting standards so that a meaningful comparison can bemade between its finacial position and performance and those of its comparators. While the AuditorGeneral will continue to carry out the official audit, PfI has agreed that its accounts be reviewed by aninternational accounting firm experienced in oil and gas sector and prepare a long form report that willhighlight the differences and restate the financial statements in conformity with IAS. The preparation ofthe long form report will commence with the 1993 fiscal year (but for some accounts, it may benecessary to go back several years). During the negotiations, it was agreed that PFIT will submit to theBank the audit report of the Auditor General within six months of the close of each fiscal year. Thesupplemented long-forms report will be submitted within three months after that date.

4.19 Insurance. PIT carries adequate insurance against loss or damage of property andsubsequent business interruptions which could cause serious financial risk. It also carries insuranceagainst third party legal liabilities, protection of cargoes and against delays or damage in transportation,and coverage against catastrophic losses. Under the previous Bank project, PTT obtained insurance forthe constuction of the projects through the contractor. However, PTT is now able to obtain the samelevel of coverage at substantal savings if it directly accesses the market. PT" will ensure that the

IQ/ Under US GAAP, exchnge differences related to long-tem ints may not be deferred an go tuh the income stementto shareholder's equity.

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coverage against various risks and the amounts are consistent with appropriate practice in the sector andacceptable to the Bank.

4.20 Taxes. PTT is required to retnit a portion of its net income to the Government asdetermined by the Ministry of Finance. The average tax rate in the past has been between 30-35 %. Inorder for PTT to comply with the "efficient enterprise" classification of the Ministry of Finance, PTTwill have to remit 30% of it net revenues.

4.21 Also in the past, the Government las reimbursed PTT for custom duties of importedequipment and materials in the form of equity contributions. This practice will not continue as theGovernment does not plan to provide PTr with such a concession nor contribute to PTT's equity. PTTwill in the future cover these costs from its own resources.

4.22 Management Information System. Prior to reorganization, PTT's ManagementInformation System (MIS) consisted of six separate systems, some of which were inherited from PTT'sparent organization. These systems included a SCADA system which monitors the operations of thegas separation plant and pipeline systems, a finance and accounting system, a management informationsystem, a marketing system, and two data systems - one for oil and one for gas. As the need arose tointegrate the systems to facilitate the transfer of information within the head office and between the headoffice and the business units, the last Bank project provided a technical assistance component to assistPTT in carrying out a thorough study to assess its hardware and software needs. For the first phase ofthe MIS project, PMT was able to obtain grant funds. The study was finalized in November and isbeing reviewed by PIT. PTT plans to secure additional grant funds for the implementation of thesecond phase as well.

4.23 Corporate Retudctng and Insfituional St ng Study. The issue ofprivatizimg PTT has played center stage in many Bank lending operations and its sector work. Asdiscussed in para. 2.12, nearly all the upstream and many downstream activities in Thailand'shydrocarbon sector are privately held. In the upstream sector, exploration and pr4duction is dominatedby private foreign companies, such as TOTAL, UNOCAL, etc. PTTEP, a subsidiary of PTT in theupstream sector, is a newcomer and fairly small. Similarly, the downstream sector is controlled by alarge number of private companies. While PTT's role has definitely been critical in developing thesector, it has done so through joint ventures and under separate legal and operational structures, oftenwith minimal interference in the activities of the entitiesAl' With the exception of three companies,PTT is a minority owner in most of its joint ventures. PTT has also taken steps to gradually divest ofsome of its interest in the subsidiaries and joint ventures. In May 1993, PfT sold 15% of PTTEP'sshares which met with success. PTT has further obtained permission from the Govemment to divest of51% of Thai Aromatics. What today remains in sole state ownership is the oil and gas transportationactivity. In the oil marketing operation, PTT competes with a number of international oil marketingcompanies, such as Shell, Esso, etc.

4.24 Internally, PIT has been undergoing significant transformations to develop a moreconducive institutional setting for an eventual corporatization/privatization. PIT's reorganization in1992 was one such step intended to create separate business units which could in time be divested.

1I/ In fact, one of the findins of the recently completed report (pam. 4.24) is t hM has taken a much too passive posturevis-a-vis its joint ventures.

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Other measures include introduction of a wide range of commercial practices common in similarcompanies world wide. While the need for and the speed of privatization of various state enterprises isbeing considered and discussed at the cabinet level, as privatization of state enterprises in the end is apolitical decision,A PIT initiated a 'diagnostic' study to evaluate its medium to long term role andoptions within Thailand's oil and gas sector, and to propose appropriate proactive (internal and extemal)institutional measures and ownership arrangements that can best support these objectives.' Thereport concludes that further commercialization of PIT within the existing structure of the sector wouldonly achieve improvements at the margin and is unlikely to bring about any significant changes.Neither is privatization of PTT a viable option for the near term due to the fact that a large portion ofPIT's investments are at mid-stream for which the Government will not be able to obtain an optimalreturn if sold prior to completion. The lack of an appropriate regulatory body in the hydrocarbonsector may be a further contributing factor which may limit private sector interest. Corporatization ofPTT, however, is the most practical and feasible option which could create not only a more autonomousinstitution but also help pave the way for an eventual full or partial privatization if and when such adecision is taken by the cabinet. These steps would facilitate the inflow of private resources into thesector and help finance the substantial investment program of the coming years.

4.25 The study further tables a number of issues such as the need for PTT to take a valuemaximzing approach to its investments and clearly separate between its commercial and developmetlroles; delegate further autonomy to the business units; identify PT's core competencies and long-term core business objectives and develop appropriate strategies for the various business lines; reviewPIT's relationship to and interaction with its joint ventures and the Government, etc. While the thrustof the study's argument and the issues raised are sound, given the limited resources which wereavailable for the diagnostic phase of the study (US$ 300,000 of grant funds from ADB), there is needfor considerably more in-depth analysis of the issues, development of concrete measures and actionplans, and the necessary means for the implementation of the recommendations. Therefore, theproposed project includes a US$1.5 milPon component to build on the findings of the diagnostic studyto (a) systematically evaluate PIT's options and prepare an action plan for its future corporatization andinvestment strategy at the corporate and business unit levels; (b) assess the effectiveness of PIT'sorganizational setting including a more detailed assessment of PIT's core business activities and theensuing strategy; (c) study the most appropriate means of potential di esdture of PIT through either aninitial public offerings in the domestic and foreign equity market, strategic sale, or gradual dilution ofpublic shares; (d) evaluate PTT's financing and financial structure, and preparation of PIT to accessindependently international credit markets without Government guarantee; and (e) explore the potentalof converting PTT into a common carrier for transportation of gas.

4.26 The above represents a preliminary identification of issues that wil be covered in theproposed conponent. However, detailed terms of reference for the study are now being developedjointly by the Bank and PTT. During negotiations, the Bank and PIT agreed on the main areas to beincluded in the final terms of reference of the study. It was agreed that the detailed terms of referenceof the study will be finalized by November 1, 1994, after the planned discussion with the Government(on the result of the diagnostic study already completed). It was further agreed that appointment of

12/ Under a sepame actviay, the Bank is assistng fte Govent in sg issLes concning privatiaton of ste

1I/ The report was caried by McKinsey & Co. in collabordon with Credit Suiss First Bostom.

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consultants will be finalized by Decenber 1, 1994, and tha the findings and ions ofCorporate Restructuring and Institutional Strengthening Study will be submitted to the Bank for itsreview and comments by July 31, 1995. Furthermore, an understanding was reached with PIT that itwill cooperate with and encourage the Government to implemen the actions recommended in the stdy.

4.27 Another component under the proposed project provides about US$350,000 to upgrade theskills of PIT staff in project analysis, investment programming, corporate fimance and finacialsystems. While PTT's planning and finance depatuents have highly motivated and competent staff,key individuals would benefit from additional training. At present, economic and financial analyses arebased on input variables such as international price estimation that are based on i-house data ratherthan on more systematic and interationally recognized data and methodologies. SimlDarly, PlT'sfinance department staff can benefit from upgrading their skills in corporate finance and from studyingvarious options for developing more appropriate financing systems. During negotiations, it was agreedwith PIr to finance, under this component, training expenses of PIT staff, as well as short-termconsultant services which may be necessary to assess PIT's existing planning and financial systems andmodifying them to PfIT's growing needs.

4.28 The project would also include US$150,000 for training PTT staff in the application ofsafety and environmental standards, which are now being developed through a study funded under Loa3508-TH. The need for this training is discussed in para. 3.14.

CHaAPIER V

FINANCIAL ANALYSIS

A. Past Flnancial Performance

5.1 PT's performance for the period of 1988-93 is su8mmared in Table 5.1.Detailed statements are given in Annex 9. The financial staements of PTT present the consolidatedposition and results of operations of Head Office and four business units (Down Stream Oil Business,Natural Gas Blusiness, Central Services Business and Petrocheniical Business) which were restru redon January 1, 1992.

TABLE S.1: TELAILAND - Summary of Past Perfornn(in Million Bhat)

FY endlingSeptew e30 11988196,9 W0119111991199(Book Value Bas)

Revemnes 41,357 45,743 58,046 77,190 76,399 85,665

Cost of Sales 34,725 39,570 49,426 65,756 63,446 71,288

Admiistrative Epenses 1,121 i,lOS 2,117 1,714 2,407 3,126

Totd Operating Expses | 37,303 42,200 53,267 69,473 67,976 77,205

bntert Expenses 1,2001 1,381 1,286 1,206 1,109 954

Net bnomeo 1,306 1,183 1,867 2,958 3,241 4,509

Totl Curent Asset 12,259 14,362 17,956 19,620 20,200 21,343

Net Fixed Assets 19,231 19,794 23,112 23,102 28,689 37,075

Total Assets 32,407 34,466 41,463 42,998 49,303 59,337

Curre Liablities 7,491 8,066 12,216 10,446 11,482 14,039

Long-Term Liablity 16,413 16,331 16,308 15,362 16,287 19,237of which: LT Loems (net) 16,292

Total Equty 8,503 10,069 12,939 17,191 21,534 26,061

Ratios:Return on avg assets in opel iton 8.2% 7.4% 12.1% 18.2% 19.1% 26.6%

Return on avg equity 18.7% 12.7% 16.2% 19.6% 16.7% 18.9%

Opeting Ratio 90.2% 92.3% 91.8% 90.0% 89.0% 90.1%

Current Ratio 1.6 1.8 1.5 1.9 1.8 1.5

Days Receivable 50 51 52 27 30 39

LTDebt:equity ratio (book value bass) 0.66 0.62 0.56 0.47 0.43 0.42

LTDcbt:equiy (revalued assets basis) 0.50 0.44 0.39 0.34 0.32 0.32

DSCR 1 2.3 2.3 2.8 2.5 2.3 3.2

Self-fhmaulngratio (-yr avg) a& r 101% 72% 48%

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5.2 During the 1988-1993 period, PITT's revenue nearly doubled from Baht 41 billion to Baht86 billion, translating in a real growth of around 10 percent per year, largely due to the increase inrevenues from the oil marketing operation. Oil sales volume increased from 4,770 million liters in 1989to about 13,779 million liters in 1993, a 23.6% real growth per annum. Nominal sales rose from Baht30 million in 1988 to Baht 64 million in 1993. Although oil sales constitute about 75 % of gross revenueand gas sales for about 23%, PTT derives much of its profit from the gas business. Net profit of the gasbusiness as percentage of gross gas sales has averaged around 19-20% since 1990 while that of the oilmarketing business has been at most 3-5 %.

5.3 Operating ratio (defined as total operating expenses excluding interest, taxes and foreignexchange losses to total revenue) fell from 91.8% in 1990 to 89% in 1992 but climbed up to 90.1% inthe fiscal year of 1993. Administrative expenses have remained at a reasonable level even though its ratioto sales has increased from 2.7% in 1988 to 3.6% in 1993. However, revenue generated per employeehas doubled during the same period, which is a more significant indicator. The change in staff profile(see para. 4.8) is one of the main factors for the increase in productivity.

5.4 During the past five years, PTT's financial performance has been solid. Assets (on bookvalue basis) grew from Baht 32.4 billion ($1.3 billion) in 1988 to 59.3 billion Baht ($2.4 billion) in 1993.Equity increased from Baht 8.5 billion ($300 million) to 26 billion Baht ($1 bi11ion). The growth ofequity has been achieved solely through retained earnings and without any new equity contributions frmthe Government. In fact, the share of accumulated contributions from the Government declineddrastically from 28.7% to 12.6%. Return on average assets in operation for 1992 and 1993 has been19.1% and 26.6% respectively. Retumn on average equity increased from 18.7% in 1988 to 19.6% in1990 bu; declined sligthtly to 18.9% in 1993A'

5.5 PTT's financial stucture is appropriate. The current ratio rose to 1.9 in 1991 butdeclined to 1.5 in 1993 primarily due to an increase in the current portion of long-term loans. Daysreceivables (total receivables/average daily sales) and days inventory (total inventories/average daily costof goods sold) showed improvements and declined from 50 and 17, respectively, in 1988, to 30 and 14in 1992, but climbed to 39 and 19 in 1993. Long term liabilities over equity has been below 60:40 ratioon revalued asset basis. In 1993, this ratio was 32:68. On a book value basis, the ratio is 56:44.1

i4/ In analyzing return on equity, it may be useful to separate the various componen In the following manncr Reurn on equity= (net income/total equty) = (net incmWe/sales) X (sales/total assets) X (total assets/total equity) = margin X asset utliaton Xleveag. An analysis of Plr's rate of retun along these three separat compont reveals that fth ren on equity has beenachieved throuh internal efficiency, namely higher margin and better utilization of asset, even with a more conservative leveageratio. Over the 1988-93 period, net margin rose from 3% to 6% anm h-et utilization (measuring sales per unit of assets) increasedinWally from 1.3 in 1988 to 1.8 in 1990 and declined to 1.45 in 1993. PrT's financial leverage during the same period becamemore conservative, declining from 3.8 in 1988 to 2.4 in 1993. HIad PTT maintained a sinilar leverage ratio in 1993 as in 1988,the retan on equity would have been as high as 30%.

1988 1989 1990 1991 1992 1993Net Income/Sales (net margin) 3% 3% 3% 4% 4% 5%Sales/Asset (Asset Utilization) 1.28 1.33 1.40 1.80 1.55 1.44AssetEqut (Leverage) 3.81 3.42 3.20 2.50 2.29 2.28Retum on end of year equity 15% 12% 14% 17% 15% 17%

1U/ The ADB uses a debt/equity ratio of 70:30 on book value basis, whereas the Bank has chosen a 60:40 ratio on revalued assetbasis.

-35-

5.6 PTT has been recipient of several Bank loans and has complied with Bank financialcovenants. As stipulated under the latest Bank loan (Loan No. 3508-TH), PTT was to maintain a self-financing ratio (SFR) of 25%, a debt-service coverage ratio (DSCR) of 1.3, a current ratio (CR) of 1.1,and a debt:equity ratio (DER) of 60:40 on revalued asset basis. PIT has complied with the requiredfinancial covenants. Calculation of the self-financing ratio based on audited statements places this ratioaround 72%, which is in excess of the 25% stipulated under the project. Unaudited 1993 data places SFRaround 48%. Several explanations can be given as to why this ratio has been rather erratic in the past.First, until 1990, PTT did not break down its long term loans as received and repaid. Secondly, PTT'sinvestments are lumpy and implementation cannot be "smoothed" over several years to present a betterself-financing ratio. Third, small delays or shifts in the implementation schedule can substantially swingthe ratio.

5.7 During the 1988-93 period, PTT's investment plan amounted to about Baht 27 billion($1.08 billion). At a higher than projected rate, PTT financed this investment by contributing around70% of the cost from its internal cash generation during the period, which is one other reason for thesubstantially conservative leverage (Table 5.2).

TABLE 5.2: THAILAND - Pl's Past Investments and Finandng 1988-93(in millions)r_______ D ait I US$ I___ %_____

QCapit nesmen 7 27,010 T 1,080 100%Sources of Funds _

Intemal Cash Generation 18,919 757 f 70%IBOrrowng J 8,091 324 30%

Totl Soures of Funds | 27,010 1,080 100%

5.8 PTT's total net long term borrowing increased only modestly over this period by about$300 million. At the end of 1993, nearly one third of total outstanding debt was denominated in Yen.Since the Baht floats against the US Dollar, in the past, PTT has experiencmd foreign exchange losses onits Yen operations and liabilities. In accordance with Thai accounting practices, PTT defers losses onthe revaluation of loans for completed projects and amortizes these throughout the life of the loans (seepara. 4.14). At the end of 1993, accumulated deferred currency losses amounted to Baht 3 billion andare offset against shareholder's equity. PTT has taken measures to manage its currency risk exposureto Yen by financing its projects through more dollar-denominated loans and through currency swaps.Despite some foreign exchange losses, PTT's debt service ratio has been satisfactory and has ranged frombetween 2.4-3.2.

5.9 PTT has also accessed the local credit markets. Table 5.3 below, demonstrates the issues,maturity, coupon and terms of PTT's bond issues. In 1992 and 1993, it accessed the local bond marketand floated four issues which are listed below.

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TABLE 5.3: TEILAND - PlITs Borrowing in the Local Market

Date Issued Amount Term Rate

April 16, 1992 B 1,200 mm 7 years 8.05

August 13, 1992 B 1,842 mm 8 years 8.88

June 15, 1993 B 2,947 mm 10 years 8.98

July 8, 1993 B 619mm 5 years 8.64

PROJECT BENEFITS AND RISKS

A. Benerts

6.1 As discussed in para. 2.7, Thailand will face a continuous gas deficit for the foreseeablefuture (including through the life of the proposed project). To cope with this situation, the Governmentis adjusting the allotment to EGAT, which uses over 90% of the country's total gas supply, whileproviding industrial consumers (which use the balance) with their full gas requirements. The economicsof the proposed project is a function of the economic value of the gas to EGAT in its power expansionplans. EGAT's fuel choices are limited. Large hydro-power projects are not viable because theypresent major environmental and resetdement problems. Domestic coal (lignite), even if developed toits full potential, would not be able to supply the fuel needed for the projected power demand.Moreover, its economic ranking, even without any pollution control equipment, at US$4. 1,er kWh,ranks this fuel lower than natural gas (at US$3.994per kWh). When the costs of such equipment areincluded, the cost of lignite-based power, at US$5.06iper kWh, makes it uncompetitive, regardless ofits availability. Power that is produced with imported coal, at a cost of US$5.16iper kWh (assumingno pollution control equipment is included), is more costly than that produced with lignite; however,where lignite or gas are not available, imported coal becomes the long-term "replacement" fuel becauseit is readily available in the international market, relatively low cost, and its future price is not expectedto rise significantly. Finally, power produced with low-sulphur fuel oil, at a cost of US$5.7tper kWh(without pollution control equipment), rns lower than both the lignite and imported coal.

6.2 Therefore, domestic naural gas utilized in the combined-cycle power plant represents theleast-cost fuel for power generation, primarily because the use of gas in such plants enhances thermalefficiency.

6.3 Economic Benefits. The project's internal economic rate of return (IERR) is based on itsincremental costs and benefits. The former include: (a) capital and operation and maince (O&M)costs associated with gas development and production and (b) capital and O&M costs of gas gatheringand transmission system. The estimated capital costs for gas development and production are based onplans and the definitve cost estimate prepared by each producer and approved by PTT, which includesthe cost of various drilling activities and of the installation of surface facilities to develop and producethe quantity of gas required over the life of the project (20 years). The O&M costs for gasdevelopment and production are based on the estimate submitted by the producers, reflecting their 12years of experience in Thailand's fields. The basis for the pipeline's capital costs is discussed in para.3.18, and its O&M costs are assumed to be 3% of the capital costs.

6.4 The incremental benefits of the proposed project are based on the econonic value ofmnarginal gas supply. The economic value consists of the netback value of gas used in EGAT'scombined-cycle power plants, when it is assumed that gas would substitute for a low-sulphur coal (andadjusted for the differential in thermal efficiency, see Annex 11).-A'fl

I6/ In Tailand's power sector, impoed coal is assumed to be the long-term energy source and, thus, the replacement fuel forgas.

17/ See Annex 12 for the economic value of gas used in the indusgy.

-38-

6.5 For the base case, the IERR calculated is 36%. Details, including the assumptions used,are given in Annex 11. This high rate of return is largely due to the high efficiency of natural gas incombined-cycle power plants.

6.6 The analysis of the sensitivity of the IERR to the underlying assumptions indicates that ifcapital and O&M costs increase by 20%, the IERR will decrease to only 31%. Hence, the projectwould have to incur exceptionally high development and production costs (together, these two constitutethe main project risks due to complex reservoir geology), in order to render the project uneconomic.The sensitivity of EERR to other assumptions is the following:

IERR (%)(a) Capital and O&M costs rise by 20%; 31%(b) Gas supply drops by 10%; 28%(c) Capital and O&M costs increase by 20% and 24%

gas supply decreases by 10%,

6.7 The financial rate of return is calculated at 16% (see Annex 11). This calculation is basedon the capital and operating costs estimated in the project cost table, including taxes and duties. Thepurchasing costs (of gas) are based on the ij _.vidual sales-purchase agreement contracts (between PTTand the gas producers) and the Bank assumption regarding the future values of different indices used inthe agreements. PTT's revenue estimates are based on the price of gas sold to EGAT, which ensures ita rate of return of at least 12%.

6.8 Environmental Benefits. An added benefit (although not quantified here) of the proposedinfirastructure investment is d<rived from the impact natural gas will have on the environment. Withoutthe proposed project, EGAT would use either lignite or fuel oil to generate power. Natural gas is acleaner and less polluting fuel; as it will be increasingly available, partieularly in the Bangkok area (andprogressively in other parts of the country), air quality will significantly improv- s emissions of, interalia, SO2 and particulates will be reduced. The new gas-fired power plants will substitute for fuel oil orcoal-fired stations.

B. Risks

6.9 Project risks involve three areas: (a) the availability of sufficient gas reserves and thecosts of producing them; (b) potential disputes in various contractual arrangements between PIT andgas producers; and (c) the safety and enviromnental problems. The gas reserves have been assessed andcertified by DeGolyer and MacNaughton, a company well respected in this area; thus, the risk ofinsufficient reserves is low. The potential increase in production costs stems from the complex natureof the reservoirs (para. 2.3). However, this risk was mitigated because contingencies were included inthe cost parameters and because Unocal has substantial experience producing gas (since 1981). Thepotential for disputes is minimal because contracts among the various parties are governed by industrynorms that prevail in international markets; also, due to the great demand for gas, the parties involvedin buying and selling gas have little reason to abrogate the contracts. With regard to safety andenvironmental risks, these have been mitigated through contingency plans prepared and agreed withPIT in the EIA report.

RECOMMENDATION

7.1 With the above agreements and assurances, the proposed project constitutes a suitable basisfor a Bank loan of US$155.0 million equivalent to PTT, with the guarantee of the Kingdom ofThailand, at the Bank's standard variable interest rate for a 17-year term including a four-year graceperiod.

ANNEXE

-40- ~ Annex 1Page 1 of 1

THLAND

SECOND GAS TRANSMISION PROJECT

Table 1.1: Domestic Energy Prices(January 1993)

1991 _aL. FOBShre of Tax Average Oil Prod.TOal O Excise & Oil Con. Wholel VWholale Ma t RtAil Prices

Co__CH_ CIP Ex-Ref Munkiipal Fund Futd Pdie VAT + VAT Mari VAT Prie (9)

LPG (Bahtkg) (1) 7.42 2.39 -2.11 0.00 7.69 0.54 8.23 2.36 0.17 10.75LPG (Baht/It) 0.076 4.04 1.30 -1.15 0.00 4.19 0.29 4.48 1.28 0.09 5.86 5.36

Prem.Oasolone (Bahtlt) 0.047 4.09 3.36 0.03 0.07 7.55 0.53 8.07 1.28 0.09 9.44 4.40

Unladed Gasolie aht/lt) 0.030 5.27 2.58 0.03 0.07 7.95 0.56 8.51 0.80 0.05 9.36 4.40

Reg.so-line (Baht/lt) (2) 0.082 3.54 3.36 0.03 0.07 6.99 0.49 7.48 1.07 0.07 8.62 4.32

Keosee (Bahi/lt) 0.109 4.25 3.30 0.03 0.07 7.65 0.54 S.18 0.76 0.05 9.00 4.24

Diesel (Da/) (3) 0.406 4.26 2.31 0.03 0.07 6.67 0.47 7.13 0.80 0.06 7.99 4.22

Fuel Oil (Bah (4) 0.250 2.14 0.50 0.03 0.07 2.74 0.19 2.93 0.46 0.03 3.42 1.96

Weighted Oil Avg.(B lt) (5) 1.00 3.67 2.03 -0.06 0.06 5.71 0.40 _5.11 0.79 0.06 6.96 3.77

Electricity (BaWKwh) (6)

Industra- MBA Ara 1.60ndustra- Outside MBEA 1.57Residential- MEA Area 1.81Residential- Outide MEA _ _ 1.40

LlGNITE (Baht/O (7) S79 21 600

COAL (Dolarlto (8) 50 5 55

Sorce: Thailad

Notes:

(1) LPG fiue refers to both lg and sml size.(2) Fguur for regular gasoli refer to gasoline with 83 RON.(3) Fiues refer to high speed diel, 1% ufut(4) Figures refer to fuel oil 1500.(5) Tbil figure Is compued by multMplying thw priCe of each roduct by its de.(6) Elotrc triffs comspond to a re tarffs reported by DEA in OElectc Power in Thailand 19910.Note that aa taffa hav not changed since 1991, the figures for that year are cwrtly valid.(7) Te tax figure for liie corresponds to a Royalty charge. Figure under EC-REP corresponds to producon cosL(8) CiF figre for coal includes $7 for freight and insurance and $6 for h g. The 10% tax chagedcrresponds to an import duty which is applied to the CIP price.

(C) These figurs correspond to Singapor and Monteuv madets as reported in *PI t's Oilgam Price Report, Vol. 71, No. 81, April 27, 1993

-41-Annex 2Page 1 of 4

THMAl[Mil

SECOND GAS SMISSION PROJECT

Geology and Petroleum Potential of Thailandand Adjoining Basins

Thailand's Basins

1. Offshore. Trwo areas offshore Tbailand have potential for gas and possibly oil incommercially viable quantities. By far the more significant at this time is the Gulf of Thailand. TheThai portion includes several present day sedimentary basins (as contrasted to areas which may havebeen basins in the geologic past but which have been diminished by regional uplift and subsequenterosion). These basins are: Chumpon (West Kra) Basin; Songkhla (East Kra) Basin; Pattani Trough;and the northern end of the Malay Basin. These basins are similar in most respects. They were formedas extensional rift basins along h;ghly active lateral fault systems. They are filled with Cenozoic Ageelastic sediments (sends, silts, and shales) during the Paleocene to Pleistocene Epochs, i.e., the last 60million years. The sedimentary environment was principally non-marine with near shore fluvial,swamr, and lacustrine (lake and lagoon) deposits dominant. Thin coal seams are common. The basinsin thf Gulf of Thailand are separated by intervening highs or ridges where Cenozoic sediments are thindue o non-deposition and/or erosion and unconformably overlie older sediments of Mesozoic and/orPlWeozoic age and in some areas volcanic terrain or crystalline basement.

2. The fault movement which formed these basins has persisted through the Cenozoic buthas diminished over time with the Pleistocene and Recent deposition showing little effects of the faultmovement. During most of the Cenozoic, movement continued on the lateral faults and the stucralforces within each basin alternated between compression (uplift and folding) and extension (subsidenceand sag). As each of these forces occurred, in turn the preceding structure was overprinted with thelater movement. At present each basin is paradoxically characterized by low relief features (both highsand lows) which are highly faulted (normally extensive faulting is associated with high relief). Variousaspects of the stuctural geometry suggest that the latest movements were primarily extensional.

3. With respect to hydrocarbons prospects, the basins in the Gulf of Thailand are all gasprone. The only significant oil discovered thus far is in the southeastern portion of the Malay Basin(offshore peninsular Malaysia) and even in this area gas remains a major component. Isolated oildiscoveries have been made in the Chumpon Basin (from pre-Cenozoic carbonates), the Songkhla Basin(in Cenozoic clastic which appears to be non-commercial) and in the Pattani trough notably in reservoirsin the shallower part of the Cenozoic section. A recent oil discovery, by Maersk et al, in the northernPattani trough (Tantawan-1) has the potential for becoming significant. High crustal heat flows,associated with lateral fault tectonics, appears to have placed the bulk of the most prospective Cenozoicinterval in the over mature gas/condensate realm. The high heat flow regime interacting with the pre-Cenozoic limestones (Ca C03) also appears to have generated significant quantities of carbon-dioxidegas (CO2) which is associated with the hydrocarbon gas.

4. The ten gas fields (Erawan in Unocal I; Baanpot, Satun, Platong, and Kaphong inUnocal II; Funan, Jakrawan, Trat, and Surat in Unocal IH; and Bongkot), and six unevaluateddiscoveries (Pladang in Unocal Il; Pakarang and Gomin in Unocal m; Pailin and Moragot in Unocal

-42-Annex 2Page 2 of 4

12/27; and Tantawan), as well as the approximately thirteen fields and unappraised discoveries in thenorthwestern portion of the Malay Basin offshore peninsular Malaysia have strikingly similarcharacternstics. The gas is reservoired in sandstones of the several types associated with river and rivermouth, lacustrine and shallow marine systems, i.e. fluvial-deltaic. Reservoirs in this depositional realm(predominantly channel fill and bais) are limited in extent and are further subdivided by faulting. Inany given area scores to hundreds of individual reservoirs are productive. These may vary from just afew acres to 2000 acres or more in areal extent but most are relatively small. Traps are formed byfault closures, sand lenses, and anticlinal trap, with high side of fault closures being predominant. Thesmall size and complexity of traps requires a concentrated three-dimensional seismic survey to assist inthe drilling of optimally located wells, i.e. the most reserves tapped with the fewest penetrations.

5. The salient points, given these geologic parameters, are that individual fields contain anabundance of individual reservoirs of varying size, shape, and thickness, and that most individualreservoirs are small. When placed on production, each reservoir depletes rather quickly. Since eachproduction well may penetrate from three to twenty plus reservoirs, workover recompletions arecommonly frequent. This, when coupled with the large number of platfonns and wells required, makesboth the cost of development and the cost of production relatively high (considerably more than isnormal for comparative field reserves).

6. Elsewhere, the Thai portion of the Andaman Sea shelf containing perhaps several basinshas been lightly explored and potential for hydrocarbons in commercial quantities may exist but carriesa high degree of geologic risk. A recent discovery offshore Myanmar about 250 Km north of the Thaiborder has upgraded the outlook for the offshore area west of the southern Thai peninsula. Details ofthis discovery, made by Texaco in early 1992, are sparse but it appears that a substantial gas reservoirwas found in an Oligo-Miocene (mid Cenozoic) turbidite sand, i.e. submarine fan deposit, with athickness reputed to be in excess of 100 m (330 feet). Further exploration and development will berequired to determine its significance as well as any effect it may have regarding Thai potential in theAndaman Sea.

7. Onshore. The petroleum geology of onshore Thailand falls into two distinct categories.These are a series of north/south trending Cenozoic Basins in the westem half of mainland Thailand,which became present day inter-montane basins in the north, and the large Khorat Basin in the northeastwhich is filled with older Mesozoic and Paleozoic strata. The Cenozoic basins in the west include theNorth Bangkok area (Suphan Buri and Kamphaeng Basins), the Petchabun Basin, the Phitsanulok Basin,and the Lampang, Chingmai, Phrae, and Fang intermontane basins. While these Cenozoic basins aresimilar in most respects to those in the Gulf of Thailand, they appear to be oil prone. A major oilfield, Sirikit, plus seven minor fields which have been found in the Phitsanulok Basin, to date are themost prolific of the onshore basins in Thailand. Small and relatively insignificant oil fields have beenfound in the Supl"an Buri, Kanphaeng, Petchabun, and Fang Basins. All of these produce from Oligo-Miocene sand reservoirs deposited in a non-marine, predominantdy lacustrine environment. Individualreservoirs are small. The large field, Sirikit, is typified by a large number of stacked reservoirs and arelatively thick and extensive source rock of Oligo Miocene lacustrine shales. Additional potential forhydrocarbons in the onshore Cenozoic Basins is obvious but the bulk is likely to be found as small oilfields with marginal commerciality due to the limited area and thickness of the Cenozoic section.Several more moderate size accumulations approaching the Sirikit level are possible but not likely.

8. The Khorat Basin covers a large portion of northeast Thailand. The basin sediments arecomprised of a thick section of Mesozic Cretaceous red beds (oxidized sandstone and shale) with

-43-Annex 2Page 3 of 4

relatively thin interbedded evaporites (anhydrite, gypsum, and salt). This interval has minimalpetroleum potential unless sourced by non-oxidized beds from below. The Cretaceous red bedsunconformably overlie early Mesozoic and Paleozoic strata, in particular an extensive and thick blanketof upper Paleozoic Permo-Carboniferous limestone and dolomite. It is this deep pre-Cretaceous sectionthat appears to be the most petroliferous. This section will likely be subdivided into several predecessorbasins as exploratory activity progresses. The pre-Cretaceous section appears to be structured by faultblocks, with high blocks prospective and hydrocarbons sourced from the low blocks, with Triassicshales, best developed in the lows providing the source. The Permo-Carboniferous limestone is theonly reservoir found to date. It is apparendy highly fractured, as noted in surface outcrop and in theperformance of the only field developed to date, i.e. Namphong gas field. Due to depth of burial andgenerally elevated heat regime, the Khorat Basin is likely to be gas prone. Prospecting is difficult dueto the overprint of Cenozoic structuring by compressive forces obscuring the structure of the underlyingfault blocks. Reserves and field performance are difficult to evaluate due to the fractured reservoirs in,which the bulk of the void space (porosity) consists of fractures. Gas recovery may be lowered byactive water drives resulting in vertical water coning near the producing wells. Because of its size, theKhorat Basin has a large gas potential but it will take many years to fully evaluate.

9. Three gas discoveries have been made in the Khorat Basin. The Namphong field is theonly commercial development. The two other fields are not currently considered commercial.Exploration at relatively low levels is being conducted over a sizeable portion of the basin. It isineresting to note that te Nang Nuan oil discovery in the Chumpon Basin in the Gulf of Thailand isproductive from a similar fractured pre-Cenozoic limestorne. The Nang Nuan field evaluation is fraughtwith the same problems of evaluation, i.e. water coning near the well bore.

Adjoing Bains

10. Malaysia. Most of the Malay Basin is located off the east cost of peninsula Malaysi.As noted in para. 1, the northern end of this basin extends into Thai waters which includes the Bongkotfield and two unevaluated discoveries in the Thai/Malay Joint Development Area (IDA). Some 13 gasfields with reputed reserves of approximately 20,000 bcf have been found to date in that portion of theMalay Basin immediately south of the JDA. Only one of these, Jerneh field, has been developed todate. The general geology is similar to that in the several basins further north in the Gulf of Thailand.Apparently the individual sand reservoirs are somewhat more extensive and the structures somewhatless faulted that in Thailand. This may be due to the greater marine influence on deposition and thegreater basin area (principally width) resulting in less intense structuring. Thus rapid depletion ofindividual wells is expected to be less severe than in the basins to the north. However, theseobservations are based largely on geologic perceptions since there has been no gas field production inthis part of the Malay Basin prior to 1992.

11. Viet Nam and Cambodia. Viet Nam territory, both undisputed and disputed, coversthe northeastern portion of the Malay Basin, immediately to the east and southeast of Thai waters.While discoveries in Malaysia and well-defined prospects in Thailand adjoin areas of Viet Nam claim,essentially no exploration activity has yet taken place in this part of offshore Viet Nam. SimilarlyCambodia claims extend into the eastern flank of the productive Pattani Trough and the northernmostportion of the Malay Basin. In Thailand Unocal's Kaphong (producing) and Trat (not yet onproduction) fields adjoin Cambodia claims in the Pattani Tough and well-defined prospects in theBongkot area adjoin Cambodia claims in the Malay Basin. This latter area is also claimed by Viet Namand overlap Thai claims in both basins. No significant variation in the geology and potential of the

-44-Annex 2Page 4 of 4

Pattani Trough or Malaya Basin is expected in either the disputed or undisputed territory claimed byViet Nam or Cambodia. Due to lack of exploration activities in this portion of these countries it isdifficult to ascertain precisely the basin limits east and southeast of Thailand.

12. Myaiua. The principal potential source for import gas from Myanmar is theMartaban gas field in the Andaman Sea offshore south west Myamnar (originally called the "D"structure). This field contains gas in an Upper Cenozoic Miocene limestone reef (or bank) situated onand confined to an underlying high block. Three wells capable of producing gas at high rates havebeen drilled on the Martaban feature which is delineated by a seismic survey. Further evaluation iscurrently taking place and barring unforeseen results, development should begin by late 1994. Thestructure of the field is a build-up organically derived limestone on an underlying high block (probablya subsea topographic high at the time of deposition). The limestone reservoir is high quality with 25-30% matrix porosity and up to 95% gas saturation. Due to the lack of strctural stress, fiacturing isexpected to be inconsequential. Given the excellent reservoir characteristics, the developmentinvestment (in terms of numbers of platforms and wells) should be relatively low, in contast to theGulf of Thailand. The main possible drawback is the likelihood of an active bottom water drive whichshould not be serious in terms of water coning but would maintain formation pressures and limitutimate recovery vs. that possible from pressure depletion.

13. The recent Texaco discove.- described in para. 6 may also lead to potial gasimports. This discovery is located offshore almost due west of Bangkok.

ThAILANDSECOND GAS TRANS3ISS8ON PROJECT

FORECASTED PRODUCTION PROFILESIbilLUONS OFSTANDARD CUBIC FEET PER DAY (IbUiCFD)

UNOCAL AREA3M99 199f 1996 1997 1996 19"9 2000 2001 2002 2003 2004 200e 2006 2007 2006 2009 2010 2011 2012 2013BASE 750 750 850 900 900 900 900 900 900 900 650 750 670 57s 350 250 250 250 250 25

M1C1"1 750 750 850 900 9 1.100 1.200 1.200 la200 1200 1,170 950 830 700 440 3tO 290 280 270 2Mc

SONGKOITK ;#.72b.$;} 1994 199 19 997 1996 1999 2000 2001 2002 2003 2004 200s 2006 2007 2006 2009 2030 2011 2012 2013BASE 200 250 310 350 350 350 350 350 350 350 350 350 350 350 350 350 250 too 40

3301 200 250 310 35o 390 600 600 600 600 600 600ao 0 00 00 600 500 400 250 190 I5O

TOTAL

2994 3995 1996 I 996 M999 20 2003 2002 2003 2004 200s 2006 2007 2006 2009 2020 2033 2012 2013BASE 950 I.0b 3.160 IS I?20 1.250 1250 225 3250 1.250 1.200 1,100 3.20 925 t70 600 500 350 290

Ntal 9ss 1.000 1.0 .250 .29 1.700 l*0 l.0 l30 10 1.770 .5s50 1.430 I3.3 1.040 830 690 s30 460 41

TOAL PROOUCTIOI 34 O1NARD

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WIOILIZE PIPE COAT IEG CC1l1op n C)(

PI!! COAI!fG (36 (lOll IFOE COAT hEG Fon 28 C 36 C111 PIPIESHItP Oec COAlED PIPF

4'r ' 04% ~ PEMfOL.EUR AuITIonHY OF TIIAILAIJOOft ~~ ~~~ * ~ ~ ~ ~ ~~~ N~ATIMFAL GAS PAIIALLEL PIPEL (NE -a _q____________I_____

I Pit...... ~ ~ ~ ~ ~ ~ ~ ~ I ,Ct*.* BAtCHEUL

ACT IVII Y194f II' JVK

UE~SCQIPt IOU a F AA

SUBRAI PIPELIIJE- J_ 1 JJA_ _ _ i :_ aj 9H

L~&g i RAISA_LGk SI= E31S

DEVELOP BID PACKAGE

Ptt FlVEKtl PrOCESS

55UE IFP ISWIMNA1E PIPEIl(!

BIODING PERI.DEVM.UAIE BIDSOWAJM 1CETING

CItYPE oWCuHEitSCHtYnICt AVAD ISW4AMINE PIPELI I)BILtitE LAYBAnGE SPREADiW$OUmSE tOILEAD VALVESmushAClLt AIO DELIVEn LOGEAD VAIYES

VALVES A SITE - I SWflII PIPE LAYING OPEnAIYIO I I I I I5

P1E - CO4ISSIOeISG ACTIVI1IES .

UK1 FlLLOVEALAN PIPELItNE tRAYOtG - BY 111)MWUE SELECITI PIT REVIEK

WIORME DVErtA SLSVEYALIG)(It 9SEEtS.L9VELLWP BID PACXAGE

ftii4mVthw faSSISStLE tP (OVEILAND PIPELI.EI

OtWOUG PERIODj!ALUAIijIslu

WOoJt KEtrIt I

Cc.,011 DOCUIARS*CDtIIMRA AWA _j0!Er.AJ PIPELIIC IMOIL1ZE C(tYTRACIE1 _ A rX -. - 17 lsMl i A T '

W4' a:1~I ~ ~ ;i~'~ PEE TllULEUR AUJiIOfl Y OF TIPAILAND) Ioz ___NiII". _ ~ _1 .. * I

I IN, u l l*o"o'' N"AlUilAL GAS PAnALLEL PIPEL INE | --------- _.-

PIIOJECT HASlIFn SCItEDULE I ---- -_ 1

ACTrivi rY 199 s 1994 1995 19OESCnIPTIOIIAlJl& U A MA J A O IJ I A JA O4 JSUVEfLANO PIPELIIIf lAYONG - DV 161 _ S 0 1 .nIG.r OF WAY PnEPAJIAIINSt11hN PIPEPUtHASE LOG4LEAD VALVES

KA)&fACtUIE -O DEL VEf LOM5EAD VALVES

VALVESAl SITElll 1 r 2

IEO IWELD, LOWiER-IN BAcCXFILL.

LtiS FILl. - - - - - - - -lAYOUG COD IESson - - - - - -C9I'ESSOn SPECIFICAltiONOIIX EVALUATE t AWA$ C._ t1ESSOrMKAMEACtLSE CCE'1SSO5hilP C014'DSSORS0

16T1ALt COI4CESSO1!PCClSSIL*4 c*oGEsScl

COIUISSION COKESSorkSFACILITIES\SCAOA\COU}UJICAI IO- - - - -- - - - - - - - - - - - -U----- - -tEVELUO 010 PACKAGEPIT GEVIEW

ISSLE VVP (FACILITIES\SCJDA\CC*GUItCATIONS)BIIDIMI PERIWEVALUATE 910510A11 %EETING

_ONtttACT AWA IFACILIIIES\SCAOA\CC|U|ICATI 01SI1001L1ZE

1PVCLF)EWNT ACTIVITIES-MlCUSE LONGLEAQ VL 'ESS4AIAIACtIlE A11 DELIVEQ LaLEAD VALVES|XALVES At SIIEOVEItMMO FACIULtIES CLVSIStIloW A N.J J' £50 s o t D

ti - g

1993 ~~~~~1994 595 9-O

MAM~ ~ ~ ~ ~ ~ ~ ~ ~~~~~~~~"1AtNSO OAi.6tStM PETRIOLEU14 AUtliORliTY OF TIIIAILM4I OiL Z iii0~ Pr A.I..Js imim |N ",s,, w"t , | 4A1URAL GAS PAnALLEL PIPEL1E _________- __ |

| I PROJECT HASTEn SCIItAE OULE_ __

ACTIVITY 13 -

1995OE-SCflIPJION A ON 0JJ 0 )?!I 1J J AA5 qILDJUA'IFACILITIES\SCAOA\CO CAIM I llPUt)IASE LMIGLEAO VALVES

O _ _NM&fACcu AND ILIVER LWLEAa VES V-ALV- -S

ESP FSCtLITIES COiCtl lN

CATIWIC PnOT/lC MITIGATION |\||t||\

,ISSt.£ lfIP (AIUllIC PntECIIK&C XtillMttM|||| C__ 81WDDIN PERICWEVALUATE BIOS9011 IETIIG C1fEInW CoCUENTSCONTRACT AVAIODMATIC61C PrOIECT\AC HTGTO)MtLtZE

1£GlftZTIrN PrIrnO

JIMt.3 ~CuSSeUK.U *g.I.I ~PE,TnOLEUJH AUTIOIOTIIY OF MIARLANO Di_MFt .i 'ilC9 . X , , , 4 ,. t. a f_

_ w.* 'I

t.nc us~tii.a hag,otg _0£j/P *uIa,1ft1.e |tt*ISg U'-AyllnAL GA5 PAnALLEL PIPELIHE ____________

l ea MlOJECT CASlEn SCIE0UE I-t

-SO- Annex 5Page 1 of 1

THA1LAND

SECOND GAS TRANSMISSION PROJECT

Project Implementation Organization

PTTProject DPrector

Jarujin UrasyananBechtel Execudve

Mike ThieeBil Dudley

Project Dirlector

Dan Friediman

r Project Controls Ssft

Jolhn CArick *Quality

P. :trwnt Manager Engineerig Maniager C | stosuction Manager

rFDDbII8 Arm Oltshott PPIKi |o CP & AC Mit;gipd _ Oflshom PipdiDC 1"1e Enw Ar Eng,x s Arc EngineerChud Cs paw Chris Lyk Chris Lyle Ccla Diri

*SPIC - t2"klin *Span *Fugro*SlSEngincen

Proftu System~~~~~~~~~ H ydmulics IEnm & Confiraio

Aad&lrHm Neberh9 b Welker

Petroleumn Authority of Thailatid

'Natural Gas Parallel P?ipeline Project

Project Or-ganization Chart

-51- Annex 6Page 1 of 1

THAILAND

SECOND GAS TRANSMISSION PROJECT

Diagranunatic Description of the Project

Natural Gas Parallel Pipeline Facilities Diagram

SCAiDA & Communications System C.IONSURI

t Moaify zsSong SCAOA A Commun*oons System Ot PT iERP, Aayono & flV #. Chonoun iF i.

Aad NoWMIu Lne VaNes

A SCADA SYSTEM-----------. _---------------___-__--__--_---------------______---_v--

QAS TRANSWSSAON SYSTEM

Essun0 Esiiono30' and 24' PiDens a 2ar Ppe4mne a

Bang PalIog (EGAI) Sam Bangs=

BLOCK VALVE D 6 -New Facilities B 8LOCK VALVE # 6a PipOin re.in , Mainline Pmrasurea Saaper Reabivor Regulating Statlon

Now 28" Plpellne,11O km Eatls.w

RAYONG - New Facillties 2S'Ptene

36- Scraper Resiver . Exisue

• Slug Catcher RAYOoNG t U M Ta

• KO. Drum bOGas Receiving Terminal ,• Pressure Contraol Gas Separmtlon Plants Escng

• Pipe anhtaolding -r pinew toRayon DisveuUoi

aUtifitesI4ns.. r

C Compressor Staton* 28' Saper Launcher

Now 36" PlpelIne, 425 km 30 Ppene

ERAWAN [.VAA _1cenpnRie ltform ; 4 C.inul Procaaif

Esianwg jRbr I PlattenveI5 ECP 4 ECPP)24' Pipenen 3 KMANOA (ERP) _uN

ERP- New Facilities ECP- New Facilities• Pressure Flow Control a moaicason of EZU&g PTr

• Pipeline rTe-in Contnu PSn.f

r Scraper Launcher a Cenw System Integemn

• ESO Valve• Ullibdes

* Control Room

Eea9srq 2 PtOeIfm

September 1.* 1993 'rod'Sorg8t PlSontm

-52- Annex 7Page 1 of 1

SECOND GAS TRANSMSSION PROCT

Estimated Schedule of Disbursement(US$ Millon)

IBRD Fiscal Year Estimated Disbursement Pipeline Subsectorand Semester Semester Cumulative Profile

1995December 31, 1994 40.0 40.0 35.0June 30, 1995 35.0 75.0 60.0

1996December 31, 1995 35.0 110.0 70.0June 30, 1996 30.0 140.0 85.0

1997December 31, 1996 15.5 155.5 125.0June 30, 1997 146.0

198December 31, 1997 150.0June 30, 1998 155.5

-53-Annex 8Page 1 of 2

SECOND GAS TRANSMISSION PROJECT

Project Supervision Plan

Bank Supervision Inputs Into Key Activities

1. The staff inputs indicated in the table below is in addition to the regular supervisionneeds at the headquarters for the review of progress reports, procurement actions, correspondence, etc.(paras.3.30 and 3.31 of the text). Accordingly, the total Bank supervision inputs is estimated at 44 staffweeks, of which 12 staff weeks would be at the headquarters and 32 staff weeks in the field.

2. Table A9.1 provides a tentative program of supervision activities to be carried outduring project implementation.

Table A9.1: Bank Supervision Input into Key Activities

Approximate Expected Skill Staff IputDates Activity Requirements (staff wef)

July/Aug 1994 Supervision Mission

Work progress, environmental aspects Project Engineer 8Corporatization Study and training Institutional Specialist

Environmental Specialist

December 1994 Supervision Mission

Work progress, review of Phase II Project Engineer 4of Corporatization Study Institutional Specialist

May 1995 Sunervision Mission

Work progress, finances, training Project Engineer 6and environmental aspects Financial Analyst

Environmental Specialist

December 1995 Supervision Missions (two)

Work progress, finances Project Engineer 10Corporatization Study Financial Analyst(near completion), and Environmental Specialistenvironmental aspects Institutional Specialist

1996 Supervision Mission

Overall performance review, Project Engineer 4finances and PCR. Financial Analyst

-54-

Annex 8Page 2 of 2

Borrowers Contribution to SupervisioL

3. The coordination of the project would be the responsibility of PTT. This would includeproviding inputs to the Corporatization Study, and for training needs, as well as providing informationand reports on status of project implementation, including progress in physical works and otherconditions agreed in the proposed loan.

-55-

AnnexPage 1 of 5

THA1s.AND

SECOND GAS TRANSMISSION PROJECT

PFf HELstorical Fnaial StatemRnts

(Book Value Basis)1988 1989 1990 1991 1992 1993

audited - unaudited -

Reve*Sales 40,559 44,974 56,841 76,120 74,751 84,372

(Gas 14,908 14,702 15,943 20,771 20,195 20,362Oil 25,651 30,272 40,898 55,349 54,557 64,010

Other Revenue 798 769 1,205 1,070 1,648 1,293Total Revemue 41,357 45,743 58,046 77,190 76,399 85,665

Oe ECost of Sales 34,725 39,570 49,426 65,756 63,446 71,288Sellng Expenses 452 480 634 842 850 1,348Adminis ve Expenses 1,121 1,105 2,117 1,714 2,407 3,126Other1xpenses 33 35 31 19 24 66Dqecati 972 1,010 1,059 1,142 1,249 1,377

Tota opatig expenses 37,303 42,200 53,267 69,473 67,976 77,205

Ine Epenses 1,200 1,381 1,286 1,206 1,109 954osses (s) from Pweg a 873 414 408 407 385 303

Toal Non-opeaig ase 2,073 1,795 1,694 1,613 1,494 1,257

Prea Income 1,981 1,748 3,085 6,104 6,929 7,203

Taxs (Remittances) to Goverment 675 565 1,218 3,146 3,688 2,694

Net Income 1,306 1,183 1,867 2,958 3,241 4,509

Operatng Ratio 90% 92% 92% 90% 89% 90%Net Inome/Sales 3% 3% 3% 4% 4% 5%

-56-

Annex 9Page 2 of 5

Fisal Year ending September 30 198 199 19 RR 1 993(Revalued Assets Basis)

RevenueSaes 40,559 44,974 56,841 76,120 74,751 84,372Other Revenue 798 769 1,205 1,070 1,648 1,293

Tota Revenue 41,357 45,743 58,046 77,190 76,399 85,665

Opr Cost of Sales 34,725 39,570 49,426 65,756 63,446 71,288SeUing Expensms 452 480 634 842 850 1,348Adnuisative Euxenses 1,121 1,105 2,117 1,714 2,407 3,126other E_ee 33 35 31 19 24 66Depreciation 1,342 1,558 1,746 1,964 1,249 2,000

Tota operating expnses 37,673 42,748 53,954 70,295 67,976 77,828

teare Expenses 1,200 1,381 1,286 1,206 1,109 954Forgn Exchage gains (loss) 873 414 408 407 385 303

TotW Non-peating expense 2,073 1,795 1,694 1,613 1,494 1,257

prtax Income 1,611 1,200 2,398 5,282 6,929 6,580

Taxes (Remitances) to Goovernme 675 635 1,181 2,135 2,500 2,694

Net Income 936 565 1,217 3,147 4,429 3,886

-57-

Annex 9Page 3 of 5

PrT's Balance Sheet(Book Value Bais)

1988 1989 1990 1991 1992 1993ASSETSCash 137 259 152 4,637 5,300 5,014Short-Term Investments 0 0 0 650 890 103Accounts Receivables - Trade (net) 5,705 6,541 8,336 5,777 6,299 9,268Notes Receivables 1,032 1,200 2,022 1,813 1,803 0Inventories 1,610 1,777 2,067 2,802 2,506 3,674Other Current Assets 3,775 4,584 5,380 3,939 3,402 3,284

Total Current Assets 12,259 14,362 17,956 19,620 20,200 21,343

Lng-Term Investments 2,567 2,983 4,797 4,956 7,794 11,096Prperty, Plant & Equipment (Net) 16,189 15,888 15,061 17,416 16,538 17,301Constuction Work in Progress 475 923 3,254 730 4,356 8,678

Total Fixed Assets 19,231 19,794 23,112 23,102 28,689 37,075

Other Assets 917 311 394 276 415 919

TOTAL ASSETS 32,407 34,466 41,463 42,998 49,303 59,337

LIABILITIES

Curret LiabilitiesBank Overdrafts 689 250 95 80 56 1Accounmts Payable, Trade 2,233 3,134 4,789 3,696 4,304 4,946Other Accounts Payable 620 1,269 3,149 1,827 1,153 463Accued Expenses 2,047 1,427 514 573 1,113 3,103ST Loans 558 464 341 869 1,022 0Other Liabilities 1,344 1,522 3,328 3,401 3,834 5,526

Total Current Liabilites 7,491 8,066 12,216 10,446 11,482 14,039

Long Term LiabilitiesLong Term Loans (net) 16,292 16,320 16,301 15,357 16,184 19,134Otber LT Liabilities 122 11 7 5 103 103

Total Long Term Liabilities 16,413 16,331 16,308 15,362 16,287 19,237

TOTAL LIABILITIES 23,904 24,397 28,524 25,808 27,769 33,276

EQurrYGovenment Contnbution 2,441 2,505 3,439 3,424 3,646 3,291Rtaned Eamnings 9,779 10,758 12,387 16,372 20,797 25,743Revaluation SurplusDeferred Foreign Exchange Gains/Loss (3,717) (3,193) (2,888) (2,606) (2,909) (2,973)

Total Equity 8,503 10,069 12,939 17,191 21,534 26,061

TOTAL LIABILITY & EQUITY 32,407 34,466 41,463 42,998 49,303 59,337

LT Liab/(LT liab+Equity) 74% 71% 69% 60% 56% 56%Current Ratio 1.6 1.8 1.5 1.9 1.8 1.5Days Reeivable 50 51 52 27 30 39Days Inventory 17 16 15 15 1419

-58-

Annex 9Page 4 of 5

Pff's Balance Sheet(Revalued Asset Basis)

1988 1989 i990 1991 1992 1993unaudited

ASSETSCash 137 259 152 4,637 5,300 5,014Short-Term Investments 0 0 0 650 890 103Accounts Receivables - Trade (net) 5,705 6,541 8,336 5.777 6,299 9,268Notes Receivables 1,032 1,200 2,022 1,813 1,803 0Inventories 1,610 1,777 2,067 2,802 2.506 3,674Other Current Assets 3,775 4,584 5,380 3,939 3,402 3,284

Total Current Assets 12,259 :4,362 17,956 19,620 20,200 21,343

Long-Term InvementAs 2,842 3,354 5,131 5,263 8,068 11,707Property, Plant & Equipment (Net) 23,922 26,183 26,671 30,053 29,536 31,106Contruction Work in Progrms 526 1,037 3,480 775 4,509 9,155

Total Fixed Assets 27,290 30,574 35,282 36,091 42,112 51,968

Other Assets 917 311 394 276 415 919

TOTAL ASSETS 40,466 45,247 53,632 55,986 62,727 74,230

UABLIIES

Current LiabilitiesBank Overdraft 689 250 95 80 56. 1Accounts Payable, Trade 2,233 3,134 4,789 3,696 4,304 4,946Other Accouns Payable 620 1,269 3,1491,827 1,153 463Accued Expenses 2,047 1,427 514 573 1,113 3,103ST LoaM 558 464 341 869 1,022 0Other Liabilies 1,344 1,522 3,328 3,401 3,834 5,526

Total Current Liabilities 7,491 7,816 12,121 10,366 11,426 14,038

Long Term LiabilitesLong Tenn Loans (ret) 16,292 16,320 16,301 15,357 16,184 19,134Odher LT Liabilities 122 11 7 5 103 103

Total Long Term Liabilities 16,413 16,331 16,308 15,362 16,287 19,237

EQurryGovernment Contbution 2,441 2,504 3,439 3,624 3,624 3,624Retained Earnings 9,419 9,984 11,202 14,348 18,035 21,999Revaluation Surplus 8,419 11,552 13,445 14,889 16,018 18,305Defrre Foreign Exchange GainsLos (3,717) (3,193) (2,888) (2,606) (2,785) (2,973)

Total Equity 16,562 20,847 25,198 30,255 35,014 40,955

TOTAL LABILITY & EQUITY 40,466 45,247 53,632 55,986 62,727 74,230

Inflatio Rate 10.71% 12.43% 6.95% 6.19% 3.51% 3.80%

-59-

Annex Page 5 of 5

rfn's Sources and Uses of Funds(Book Value Bads1)

1988 1989 .l2 199 1992 J223SOURCE OF FUNDSFrom Operations:Net profit 1,978 1,747 3,080 6,100 7,143 7,203

Add Depreiation 1,189 1,236 1,285 1,442 1,596 1,377Anortizaoion of defefed dhawgs 733 447 442 438 400 303Anortizaion of Leasehold 2 2 2 65

3,900 3,431 4,808 7,982 9,142 8,948ADD: Losses on Disposal f property (195) (9) (8) 57 5 0Tota funds from operations 3,705 3,421 4,800 8,039 9,146 8,948Inease in Capibll/LT loans 0 0 912 0 0 1,009bIncease in surplus fm contibuions 23 63 22 185 23 77Decrease in tention and nrfumdable deposis 0 563 0 130 111 0Income from dsposal of Prperty 4 8 8 5 6 0Other 0 149 1 0 0 0

TOTAL SOURCE OF FUNDS 3,732 4,205 5,743 8,358 9,286 10,034

APPUCATION OF FUNDSIT Iniestments 500 417 1,814 159 2,838 3,302Aequisition of propety, plant and eq 179 333 272 287 S08 6,260Investment in consuction work in p 923 1,040 2,531 1,028 3,939 681Incased in deferred chrges 0 0 0 29 16 0Lsehold acqisition 20 0 0 22 190 0LT loan Rqments 698 390 370 1,083 1,467 1,260Bonus of Directors and employees for the prey 137 145 167 193 216 296Provisions for approrion to the Mioistuy 675 635 1,181 2,135 2,S00 2,694Other 735 109 116 0 0 747

TOTAL FUNDS APPLIED 3,867 3,069 6,450 4,936 11,674 15,240

Incease (decrease) in working capt (135) 1,136 (707) 3,422 (2,388) (5,206)

-60-Annex 10Page 1 of 6

SE. ND GAS T SMSSION PROJECT

Pllf Projected Thdal Statements(Book Value Bads)

1994 1995 1996 1997 1998---projected-----------------

RevenueSales 101.289 116.495 140.766 152,324 169,728Gas 24.733 28.768 39.120 51,977 61.276Oil 76.556 87.728 101.646 100,347 108.451

Other Revenue 1.175 1.193 2.111 3.089 4.172Total Revenue 102.464 117.688 142.877 155,413 173,900

Operating ExpensesCost of Sales 86.234 101.227 118.690 126.828 140.808Selling Expenses 1.345 1.446 1.549 1,656 1.763Administrative Expenses 4.032 3.519 4.344 4.959 5.909Other Expenses 10 10 10 10 10Depreciation 1.708 2.029 3.384 4,003 4,831

Total operating expenses 93.329 108,231 127.977 137,456 153.321

Interest Expenses 1.911 2.751 4.701 5.434 6.127Losses (gains) from Foreign Exchange 267 206 163 163 162

Total Non-operating expense 2.178 2.957 4.864 5.597 6.289

Pretax Income 6.957 6.500 10.036 12.360 14.290

Taxes (Remittances) to Government 2.579 2.341 3.606 3.808 4.393

Net Income 4.378 4,159 6.430 8.552 9.897

Operating Ratio 9iX 922 902 882 882Net Income/Sales 4% 42 5 62 62

-61-Ann 10Page 2 of 6

(Revalued Asset Basls)

Fiscal Year endingSeptember 30 1994 1995 1996 1997 1998

RevenueSales 101.289 116.495 140.766 152.324 169.728Other Revenue 1.175 1.193 2.111 3.039 4.172

Total Revenue 102.464 117.688 142.377 155.413 173,900

Operating ExpensesCost of Sales 86.234 101.227 118.690 126.828 140.808Selling Expenses 1.345 1.446 1.549 1.656 1.763Administrative Expenses 4.032 3.519 4,344 4.959 5.909Other Expenses 10 10 10 10 10Depreciation 2.551 3.089 4.680 5.671 6.993

Total operating expenses 94.172 109.291 129.273 139.124 165.483

Interest Expenses 1.911 2.751 4,701 5.434 6.127Foreign Exchange gains (losses) 267 206 163 163 162

Total Non-operating expense 2.178 2.957 4,864 5.597 6,289

Pretax Income 6.114 5.440 8.740 10.692 12.128

Taxes (Remittances) to Government 2.579 2.341 3.609 3.808 4.393

Net Income 3.535 3,099 5.131 6.884 7.735

-62-Amex 10Page 3 of 6

PTT' ProJected Balance Sheet(Book Value Basis)

1994 1995 1996 1997 1998ASSETSCash 3,212 5.650 9.455 17.723 26.284Short-Term Investr.ents 52 0 0 0 0Accounts Receivables - Trade (net) 11.505 12,514 14.989 16.859 19,042Notes Receivables 0 0 0 0 0Inventories 4.895 5.502 5.926 5.901 6,595Other Current ,sezts 3,332 3,374 4.419 5.411 6.463

Total Current Assets 22,996 27.040 34.789 45.894 58.384

Long-Term Investments 17,243 22,743 27.249 30.483 29.483 changed LProperty. Plant & Equipment (Net) 28.209 51.643 61.741 62.961 73.325 changed pConstruction Work in Progress 13.900 9,716 7.239 10.316 4.055 changed w

Total Fixed Assets 59.352 84,102 96,229 103.760 106.863

Other Assets 899 899 889 879 869

TOTAL ASSETS 83.247 112.041 131,907 150.533 166.116

LIABILITIES

Current LiabilitiesBank Overdrafts 0 0 0 0 0Accounts Payable. Trade 5,538 5,957 7.112 8.420 9.242Other Accounts Payable 1,244 1.504 1.447 635 918Accrued Expenses 2,79 2.341 3.069 3.806 4.393ST Loans 0 0 0 0 0Other Liabilities 10,187 11.132 9.489 8.213 10.933

Total Current Liabilities 19.548 20.934 21.117 21.074 25.486

Long Term Liabilities 30.200 55.920 65.231 75.250 74.627Long Term Loans (net) 35.779 58.320 70.300 76.056 74.817Other LT Liabilities 6 6 6 6 6

Total Long Term Liabilities 35.785 58,326 70.306 76,062 74.823

TOTAL LIABILITIES 55,333 79.260 91.423 97.136 100,309

EQUITYGovernment Contribution 3.291 3.291 3.291 3.291 3.291Retained Earnings 27.329 31.990 39.529 5^.279 64.528Revaluation SurplusDeferred Foreign Exchange Gains/Loss (2,706) (2.500) (2.336) (2.173) (2,012)

Total Equity 27.914 32.781 40,484 53.397 65.807

TOTAL LIABILITY & EQUITY 83.247 112,041 131,907 150.533 166.116

LT Liab/(LT liab+Equity) 665 71% 69% 65% 60%Current Ratio 1.2 1.3 1.6 2.2 2.3Days Receivable 40 38 38 39 39Days Inventory 20 20 18 17 17

-63-Annex 10Page 4 of 6

PTT's Pro.iected Balance Sheet(Revalued Asset Basis)

1994 1995 1996 1997 1998ASSETSCash 3.212 5.650 9.455 17.723 26.284Short-Term Investments 52 0 0 0 0Accounts Receivables - Trade (net) 11.505 12.514 14.989 16.859 19,042Notes Receivables 0 0 0 0 0Inventories 4,895 5.502 5.926 5.901 6.595Other Current Assets 3,332 3,374 4.419 5.411 6,463

Total Current Assets 22.996 27,040 34.789 45.894 58,384

Long-Term Investments 20.444 24.698 29.429 32.599 31.599Property. Plant & Equipment (Net) 43,617 69,244 83.339 88.6.34 103,919Construction Work in Progress 15.068 10,515 7.579 11.11. 4.182

Total Fixed Assets 79,129 104.457 120.347 132.344 139,700

Other Assets 899 899 889 879 869

TOTAL ASSETS 103.024 132,396 156.025 179.117 198,953

LIABILITIES

Current LiabilitiesBank Ove-'draft 0 0 0 0 0Accounts Payable. Trade 5,538 5.957 7.112 8.420 9,242Other Accounts Payable 1.244 1,504 1.447 635 918Accrued Expenses 2,579 2.341 3.069 3,806 4,393ST Loans 0 0 0 0 0Other Liabilities 10,187 11.132 9.489 8,213 10,933

Total Current Liabilities 19,548 20.934 21.117 21.074 25,486

Long Term LiabilitiesLong Term Loans (net) 35,779 58.320 70.300 76.056 74,817Other LT Liabilities 6 6 6 6 6

Total Long Term Liabilities 35,785 58.326 70.306 76.062 74.823

EQUITYGovernment Contribution 3.624 3,624 3.624 3.624 3.624Retained Earnings 24.074 25.982 31.579 42.356 52.515Revaluation Surplus 22.699 26,030 31.735 38.174 44.517Deferred Foreign Exchange Gains/Loss (2.706) (2.500) (2.336) (2.173) (2.012)

Total Equity 47.691 53.136 64,602 81.981 98.644

TOTAL LIABILITY & EQUITY 103,024 132,396 156.025 179.117 198.953

Inflation Rate 5.00X 5.00X 5.00X 5.00X 5.002KIV 3.40X 2.90X 3.00X 2.70X 2.70X

-64-Annex 10Page 5 of 6

PTT's Prolected Cash Flow Statement

1994 1995 1996 1997 1998

CASH FLOWS ASSOCIATED WITH OPERATING ACTIVITIES

Net Income 4.378 4,159 6.430 8.552 9.897Depreciation & Amortization 1,708 2.029 3.384 4.003 4.831Other Deferred Charges 267 206 163 163 162

Free Cash 6,353 6.394 9.977 12.718 14.890

Changes in assets and liabilitiesAccounts Receivable (2.237) (1.009) (2.475) (1.870) (2.183)Inventory (1,221) (607) (424) 25 (694)Accounts Payable 1.373 679 1.098 496 1.105Other, net 4.088 665 (1.960) (1.531) 2.255

Net Cash provided by operating activities 8,356 6.122 6.216 9.838 15.373

CASH FLOW ASSOCIATED WITH INVESTING ACTIVITIES 0 0 0 0 0Net Change in Long Term Investments 6,147 5.500 4.506 3,234 (1,000)Net Additions to Property and Equipment 16,110 19.250 7.611 4.287 4.093Net Other

Net Cash Used in Investing Activities 22.257 24.750 12.117 7,521 3.093

CASH FLOWS ASSOCIATED WITH FINANCING ACTIVITIES

Refinance 0 1.500 500 0 0LT Debt Incurred 13,779 21.953 11.179 8.434 (1.240)Debt Payments 1.680 2,387 1.973 2.483 2.479Other Net 0 0 0 0 0

Net Cash provided (used) in Financing 12,099 21.066 9.706 5.951 (3.719)

Net Inc(Dec) in cash and cash requirements (1,802) 2.438 3.805 8,268 8.561

Cash and Cash Equivalents - Beginning of the Year 5.014 3.212 5.650 9.455 17.723Cash and Cash Equivalents - End of the Year 3,212 5.650 9.455 17.723 26.284

Supplemental cash Flow DisclosureInterest Paid 1,911 2.751 4,701 5,434 6.127Income taxes paid 2.579 2.341 3,606 3.808 4.393

-65-Annex 10Page 6 of 6

PIT's Finaal Projections -Apons

1. PTT's projections are prepared at each Business Unit level based on demand and supply estimation foreach line of business and product and consolidated at the Head Office. They are based on the Base CaseScenario for Gas production and are in current prices.

2. Property. plant and equipment are recorded at cost on the purchasing or acquisition date. Cost ofconstruction work in progress included gains or losses from foreign exchange fluctuations and interest duringconstructic. Demreciation is calculated by using the straight line method over the estimated useful life ofthe asset e following rates:

Asset RateProduct extraction plant 6.678Transmission plant 4.002Gas Plant 6.67XGeneral plant and other property 3.332-20.00XComputers and other 158-12XItems costing more than Baht 30,000 per unit are treated as expense Inthe acquisition year.

3. Domestic inflation during this period has been assumed to be 52 per annum.

4. Taxes and remittances to the Government are expected to remain between 30-352 of net Incomethroughout the projected period. Though projections were prepared on revalued asset basis. for purposesof supervision of the project, all indicators will be based on book value basis.

5. Gains or losses from exoected foreicn exchanae fluctuation arising from operations and repaymentof loans during each year are incorporated in the income for that accounting period. Foreign Exchangegains or losses relating to balance sheet items not payable within that accounting period are amortizedover the life of the item and accumulated In deferred foreign exchange losses/gains item. As ofSeptember 30. 1993, total deferred foreign exchange losses amounted to Baht 2.9 billion.

6. kcounts receivables are projected to range around 40 days of sales throughout the projectedperiod. Acounts pavable are projected to range around of cost oi goods sold.

-66-Annex 11Page 1 of 9

SECOND GAS SMISSION PROJCT

Economic Analyses and Underlying Assumptions

1. This annex discusses the methodology and assumptions used in the economic analyses ofthe proposed project. They involve (a) the value of natural gas to the Thai economy and (b) the costsof delivering it. The latter include assumptions about the level of reserves, future production rate,division of the flow between the existing and proposed pipeline as well as between the Bongkot fieldand Unocal fields (with respect to conrtuaul take-or-pay commitments).

2. Regarding the value of gas, as discussed in paragraph 6.1 of the text, Thailand's fuelchoices are becoming increasingly limited and the fuel available to Thailand on a long-term basis isassumed to be low-sulphur imported coal. Given that gas in Thailand attains its highest economic valuewhen used in a combined cycle power plant, the maximmn value of the gas to the Thai economy isthrefore equal to the cost of the next-best alternative fuel in the power sector (which is low-sulphurimported coal), when adjusted for differential capital, operating and maintenance costs and fuelefficiency. This value - the "netback value" of gas in the power sector - is defined as the cost savingfor the power system that would accrue if gas were substituted for other fuels (such as low-sulphurcoal). Given that this netback value is calculated at the point of delivery to the power plant - and doesnot include the gas supply costs - it also represents the "break-even" price at which the costs andbenefits of using gas in power generation are equalized over the life of the project (compared to thenext-best alternative fuel). If the cost of delivered gas would go higher than its netback value, then theconsumer (the power sector) would switch out of gas to low-sulphur coal. This netback value iscalculated to be US$4.14 per mmbtu and results from the net benefits in the power cost generated usinglow-sulphur coal (US5.16& per kWh) and domestic gas (US3.99t per kWh). Tables 12.6 and 12.7 ofthe annex provide the various assumptions in calculating the above costs.

3. The economic cost of delivered gas (to the power plant gate), includes the gasdevelopment, production, gathering and transmission costs (the capital costs as well as the operating,maitenance and fuel costs), involved in delivering the quantity of the reserves over the life of theproject (20 years). The bases of these costs are discussed in paragraph 6.3 of the text.

4. As discussed in para. 3.12 of the text, the level of reserves used in these analyses isabout 7,850 bcf. This amount was assumed to be distnbuted between the existing and the proposedpipeline in proportion to the remaining economic life of the existing pipeline (12 years), and the fulleconomic life of the new pipeline. The economic rate of return is about 36%.

5. Since the new inspection of the existing pipeline indicated that its condition is sound andthat it could operate well beyond its original economic life (which was 20 years), it could be argued thatthe existing pipeline could transport the reserves over the next 20 years and that the constuction of anew pipeline would represent a misallocation of resources. Therefore, a subsequent analysis wascarried out to determine that, if the existing pipeline transported gas at its maximum safe operatingcapacity of 850 mmcfd over the next 20 years, a full 12 years more than originally calculated (whichwas 20 years), what would be the minimum level of flow required in the new pipeline to attain aneconomic rate of retun of 12%. The analysis shows that the minimum flow is 175 nmcfd.

ECONOMIC ANALYSESUNIT COST OF BANGKOT AND UNOCAL GAS

Bongkol (Base Case) Unocal

Daily Annual Capex Opex Total Daily Ann. Flow Capex Capex Capex Capex Capex Opex Total

Flow Ftow (USS mil) (USS mil) Costs Flow (bcl) Unocal I Unocal It Unocal Ill Unocal IV Total (USS miu) Costs

(mmcld) (mmcfd) (USS mil) (mmcid) (USS mil) (USS mil) (USS mil) (USS mil) (USS mil) (USS mi)

1993 68.8 25.1 399.7 126.2 525.9 745.0 271.9 59.7 52.3 40.9 6.9 159.8 122.1 281.9

1994 196.0 71.5 114.7 63.5 178.2 750.0 273.8 53.5 29.3 162.1 28.3 273.2 123.3 396.5

1995 246.0 89.8 98.5 62.9 161.4 700.0 255.5 42.0 22.0 206.6 43.5 314.1 128.5 442.6

1996 312.5 114.1 48.5 60.4 108.9 850.0 310.3 36.8 46.4 160.0 100.0 343.2 135.5 478.7

1997 350.0 127.8 53.7 58.9 112.6 900.0 328.5 46.3 13.4 159.3 326.4 545.4 136.5 681.9

1998 350.0 127.8 67.2 580 125.2 1100.0 401.5 34.1 30.8 140.0 91.3 296.2 159.5 455.7

1999 350.0 127.8 33.8 55.0 , 88.8 1200.0 438.0 12.9 88.6 73.2 91.3 266.0 158.4 424.4

2000 350.0 127.8 52.3 51.0 .103.3 1200.0 438.0 14.2 78.7 73.5 91.3 257.7 158.4 416.1

2001 350.0 127.8 51.8 48.0 99.8 1200.0 438.0 11.8 47.4 128.3 85.3 272.8 158.4 431.2

2002 350.0 127.8 28.3 46.0 . 74.3 1200.0 438.0 2.0 25.4 93.1 49.6 170.1 158.1 328.2 0'

2003 350.0 127.8 15.8 44.0 59.8 1200.0 438.0 3.4 22.7 88.3 1.0 115.4 157.9 273.3

2004 350.0 127.8 92.0 42.0 134.0 1177.0 429.6 3.6 24.9 59.6 1.0 89.1 156.3 245.4

2005 350.0 127.8 45.5 40.0 85.5 870.0 317.6 16.2 34.6 30.2 1.0 82.0 149.8 231.8

2006 350.0 127.8 23.3 40.0 63.3 718.0 262.1 13.8 18.1 26.3 10.3 68.5 138.9 207.4

2007 350.0 127.8 0.0 40.0 40.0 568.0 207.3 13.8 18.1 26.3 10.3 68.5 129.6 198.1

2008 350.0 127.8 0.0 40.0 40.0 416.0 151.8 13.8 18.1 26.3 10.3 68.5 118.3 186.8

2009 350.0 127.8 0.0 40.0 40.0 276.0 100.7 13.8 18.1 26.3 10.3 68.5 106.8 175.3

2010 250.0 91.3 0.0 40.0 40.0 183.0 66.8 13.8 18.1 26.3 10.3 68.5 96.5 165.0

2011 100.0 36.5 0.0 40.0 40.0 123.0 44.9 13.8 18.1 26.3 10.3 68.5 84.7 153.2

2012 40.0 14.6 0.0 35.0 35.0 77.0 28.1 13.8 18.1 26.3 10.3 68.5 76.5 145.0

2013 0.0 0.0 0.0 0.0 0.0 47.0 17.2 13.8 18.1 26.3 10.3 68.5 66.3 134.8

2014 0.0 0.0 0.0 0.0 0.0 23.0 8.4 13.8 18.1 26.3 10.3 68.5 44.0 112.5

2015 0.0 0.0 0.0 0.0 0.0 9.0 3.3 13.8 18.1 26.3 10.3 68.5 11.0 79.5

2016 0.0 0.0 0.0 0.0 0.0 0.0 0.0 13.8 18.1 26.3 10.3 68.5 0.0 68.5

Total 5763.3 2103.6 1125.1 1030.9 2156 15532.0 5669.2 488.0 715.4 1704.7 1030.6 3938.7 2775.3 6714.0 D

NPV 871.7 765.4 511.2 1276.5 2672.9 255.1 317.7 884.0 550.0 2006.8 1181.3 3188.1 D x

11 Flows In these years do not represent an actual situation, since more gas will be produced.

-68- Annex 11

Page 3 of 9

ECONOMIC ANALYSESECONOMIC RATE OF RETURN - BASE CASE

Year Pipeline Pipeline Cost of Cost of Total Value Gas Net Annual FlowCapex Opex Bongkot Gas Unocal Gas In New Pipeline Benefit New Pipeline

(US$ (US$ mUS) (US$ mU) $ _(US$ mU) (US$ nIT) (US$ mi) (US$ mIA (bcf)

1993 -38.0 0.0 0.0 0.0 0.0 -38.0 0.01994 -245.0 0.0 0.0 0.0 0.0 -245.0 0.01995 -190.0 0.0 0.0 0.0 0.0 -190.0 0.01996 -71.0 -12.2 -41.6 -158.4 333.7 50.5 88.51997 0.0 -16.3 -68.5 -205.9 454.1 163.4 120.51998 0.0 -16.3 -88.0 -348.5 729.3 276.4 193.51999 0.0 -16.3 -97.8 -419.8 866.9 333.0 230.02000 0.0 -16.3 -97.8 -419.8 866.9 333.0 230.02001 0.0 -16.3 -97.8 -419.8 866.9 333.0 230.02002 0.0 -16.3 -97.8 -419.8 866.9 333.0 230.02003 0.0 -16.3 -97.8 -419.8 866.9 333.0 230.02004 0.0 -16.3 -97.8 -401.6 835.3 319.6 221.62005 0.0 -16.3 -176.1 -530.7 1169.6 446.6 310.32006 0.0 -16.3 -205.4 -506.9 1169.6 441.0 310.32007 0.0 -16.3 -225.0 -449.9 1098.1 406.9 291.32008 0.0 -16.3 -225.0 -329.5 888.9 318.1 235.82009 0.0 -16.3 -225.0 -218.6 696.3 236.4 184.72010 0.0 -16.3 -127.2 -144.9 430.7 142.3 114.22011 0.0 -16.3 0.0 -97.4 169.3 55.5 44.92012 0.0 -16.3 0.0 -61.0 106.0 28.6 28.12013 0.0 -16.3 0.0 -37.2 64.7 11.1 17.22014 0.0 -16.3 0.0 -18.2 31.6 0.0 8.42015 0.0 -16.3 0.0 -7.1 12.4 0.0 3.32016 0.0 -16.3 0.0 0.0 0.0 0.0 0.0

Total -544.0 -338.6 -1968.6 -5614.8 12524.1 4088.3 3322.0

NPV -4,.3.27 -103.26 -636.40 -2027.98 4418.50 1225.84 1172.02

IERR 36.30%

1/ Flows In these years do not represent the actual situation, but Indicate the remaining reserves basedon the current reserve level. In reality, the producers have an Incentive to find and produce more gas.

-69-Annex 11Page 4 of 9

ECONOMIC ANALYSESMINIMUM ECONOMIC RATE OF RETURN

Total Gas InYear Pipeline Pipeline Minimum New Pipeline Net

Capex Opex Annual Flow Based on Min Flow Benefit(US$ mi) (US$ mil) (bct (US$ mil) (US$ mil)

1993 -380 0.0 0.0 0.0 -38.01994 -245.0 0.0 0.0 0.0 -245.01995 -190.0 0.0 0.0 0.0 -190.01996 -71.0 -12.2 47.9 71.9 -11.41997 0.0 -16.3 63.9 95.8 79.51998 0.0 -16.3 63.9 95.8 79.51999 0.0 -16.3 63.9 95.8 79.52000 0.0 -16.3 63.9 95.8 79.52001 0.0 -16.3 63.9 95.8 79.52002 0.0 -16.3 63.9 95.8 79.52003 0.0 -16.3 63.9 95.8 79.52004 0.0 -16.3 63.9 95.8 79.52005 0.0 -16.3 63.9 95.8 79.52006 0.0 -16.3 63.9 95.8 79.52007 0.0 -16.3 63.9 95.8 79.52008 0.0 -16.3 63.9 95.8 79.52009 0.0 -16.3 63.9 95.8 79.52010 0.0 -16.3 63.9 95.8 79.52011 0.0 -16.3 63.9 95.8 79.52012 0.0 -16.3 63.9 95.8 79.52013 0.0 -16.3 63.9 95.8 79.52014 0.0 -16.3 63.9 95.8 79.52015 0.0 -16.3 63.9 95.8 79.52016 0.0 -16.3 63.9 95.8 79.5

Total -544.0 -338.6 1325.4 1988.1 1105.5

NPV -428.3 -103.3 404.1 606.2 74.7

IRR 12.19

-70-An= 11Page S of 9

ECONOMIC ANALYSESFINANCIAL RATE OF RETURN - BASE CASE

Total NetYear Capex Opex Benefit Benefil

(USS mlF (U) $ mio (USS mI) (UJS mf)

1993 -40.0 0.0 0.0 -40.01994 -255.0 0.0 0.0 -255.01995 -200.0 0.0 0.0 -200.01996 -73.0 -12.8 60.4 -25.41997 0.0 -17.0 82.2 65.21998 0.0 -17.0 132.0 115.01999 0.0 -17.0 156.9 139.92000 0.0 -17.0 156.9 139.92001 0.0 -17.0 156.9 139.92002 0.0 -17.0 156.9 139.92003 0.0 -17.0 156.9 139.92004 0.0 -17.0 151.2 134.22005 0.0 -17.0 211.7 194.72006 0.0 -17.0 211.7 194.72007 0.0 -17.0 19&8 181.82008 0.0 -17.0 160.9 143.92009 0.0 -17.0 126.1 109.12010 0.0 -17.0 780 61.02011 0.0 *-17.0 30.6 13.62012 0.0 -17.0 19.2 2.22013 0.0 -17.0 11.7 0.02014 0.0 -17.0 5.7 0.02015 0.0 -17.0 2.2 0.02016 0.0 -17.0 0.0 0.0

Total -568.0 '-352.8 2267.3 1394.8

NPV -447.2 -107.6 799.9 250.5

IFFR 16.93

-71-Awls LLPage 6 of 9

ECONOMIC ANALYSESAVERAGE COST OF DOMESTiC GAS

Table 12.5: Bongkot-Erawan Gas Transmission Cost(Constant 1993 US Dollars)

Capital Oper. Total Scen 1Year Cost Cost Cost Flow 1/

(SmIl) ($mil) ($mil) bcflyr

1992 4&00 0 48.00 01993 108.00 0 108.00 01994 44.00 0 44.00 01995 0 6.00 6.00 64.031996 0 6.00 6.00 82.501997 0 6.00 6.00 96.101998 0 6.00 6.00 109.501999 0 6.00 6.00 91.252000 0 6.00 6.00 91.252001 0 6.00 6.00 91.252002 0 6.00 6.00 91.252003 0 6.00 6.00 91.252004 0 6.00 6.00 91.252005 0 6.00 6.00 91.252006 0 6.00 6.00 91.252007 0 6.00 6.00 91.252008 0 6.00 6.00 91.252009 0 6.0C 6.00 91.252010 0 6.00 6.00 91.252011 0 6.00 6.00 91.252012 0 6.00 6.00 91.252013 0 6.00 6.00 91.252014 0 6.00 6.00 91.25

NPV @10%6 165.9S 38.38 204.33 571.73

1/ Based on contractual quantity.

Unit transmission cost - US$0.361mcf

Source: Bank mission estimate.

-72-Annex IIPage 7 of 9

ECONOMIC ANALYSESPOWER COST & NET BACK VALUE - GAS

Table 12.6: Combined Cycle Plant with Natural Gas(Constant 1993 US Dollars)

ASSUMPTIONS:Plant Factor - 70% Capital Cost - $650/kw Life - 20 yearsEfficiency - 44% Operating Cost - 4.0% of Investment cost Construction Time - 3 yearsSize - 600 MW

Capital Power Gas Unit Total Operating Total Oper. Total CapitalYear Cost Generated Consumption Fuel Cost Fuel Cost Cost Cost & Oper. Cost

($mli) (GWhIYear) (BCF/Year) ($/mcl) (Smil) (Smil) (Smil) ($mil)

1994 130.00 0 0 0 0 0 0 130.001995 130.00 0 0 0 0 0 0 130.001996 130.00 0 0 0 0 0 0 130.001997 0 1840.00 14.25 2.45 34.91 15.60 50.51 50.511998 0 2759.00 21.38 2.47 52.90 1 5.60 68.50 68.501999 0 3679.00 28.50 2.50 71.23 15.60 86.83 86.832000 0 3679.00 28.50 2.52 71.94 15.60 87.54 87.542001 0 3679.00 28.50 2.55 72.66 15.60 88.26 88.262002 0 3679.00 28.50 2.57 73.39 15.60 88.99 88.992003 0 3679.00 28.50 2.60 74.12 15.60 89.72 89.722004 0 3679.00 28.50 2.63 74.86 15.60 90.46 90.462005 0 3679.00 28.50 2.65 75.61 15.60 91.21 91.212006 0 3679.00 28.50 2.68 76.37 15.60 91.97 91.972007 0 3679.00 28.50 2.71 77.13 15.60 92.73 92.732008 0 3679.00 28.50 2.73 77.90 15.60 93.50 93.502009 0 3679.00 28.50 2.76 78.68 15.60 94.28 94.282010 0 3679.00 28.50 2.79 79.47 15.60 95.07 95.072011 0 3679.00 28.50 2.82 80.26 15.60 95.86 95.862012 0 3679.00 28.50 2.84 81.06 15.60 96.66 96.662013 0 3679.00 28.50 2.87 81.88 15.60 97.48 97.482014 0 3679.00 28.50 2.90 82.69 15.60 98.29 98.292015 0 3679.00 28.50 2.93 83.52 15.60 99.12 99.122016 0 3679.00 28.50 2.96 84.36 15.60 99.96 99.962016_ 0 I3679.00A 28.50 2.96 _84.3_15.60_9.96_99.9

NPV @10% 323.29 21704.92 168.14 442.39 99.78 542.17 865.46

Power cost - US 3.99 cents/kWh

Source: Bank mission estimate.

-73-Annex 11Page 8 of 9

ECONOMIC ANALYSESPOWER COST & NET BACK VALUE - COAL

Table 12.7: Coal Fired Power PlantLow Sulphur Coal (0.5%). without FGO

(Constant 1993 US Dollars)

ASSUMPTIONS:Plant Factor - 70% Capital Cost - $1076/kw Life - 25 yearsEfficiency - 38% Operating Cost - 3.7% of investment cost Construction Time - 5 yearsSize - 2000 MW

Capital Power Volume of Imp. Coal Fuel Operating Total Oper.Year Cost Generated Coal CIF Cost Cost Cost Total Cost

(S mil) GWhfYear (mul tons) ($/ton) ($ mil) ($ mil) (S mil) (S mI)

1994 430.40 0 0 0 0 0 0 430.401995 430.40 0 0 0 0 0 0 430.401996 430.40 0 0 0 0 0 0 430.401997 430.40 0 0 0 0 0 0 430.401998 430.40 0 0 0 0 0 0 430.401999 0 6132.00 2.09 54.00 112.86 79.62 192.48 192.482000 0 9198.00 3.13 54.27 169.87 79.62 249.49 249.492001 0 12264.00 4.17 54.54 227.43 79.62 307.05 307.052002 0 12264.00 4.17 54.81 228.56 79.62 308.18 308.182003 0 12264.00 4.17 55.09 229.73 79.62 309.35 309.352004 0 12264.00 4.17 ss.36 230.85 79.62 310.47 310.472005 0 12264.00 4.17 55.64 232.02 79.62 311.64 311.642006 0 12264.00 4.17 55.75 232.48 79.62 312.10 312.102007 0 12264.00 4.17 56.03 233.65 79.62 313.27 313.272008 0 12264.00 4.17 56.31 234.81 79.62 314.43 314.432009 0 12264.00 4.17 56.59 235.98 79.62 315.60 315.602010 0 12264.00 4.17 56.87 237.15 79.62 316.77 316.772011 0 12264.00 4.17 57.16 238.36 79.62 317.98 317.982012 0 12264.00 4.17 57.45 239.55 79.62 319.17 319.172013 0 12264.00 4i1i 57.73 240.75 79.62 320.37 320.372014 0 12264.00 4.17 s502 241.95 79.62 321.57 321.572015 0 12264.00 4.17 58.31 243.16 79.62 322.78 322.782016 0 12264.00 4.17 58.60 244.38 79.62 324.00 324.002017 0 12264.00 4.17 58.90 245.60 79.62 325.22 325.222018 0 12264.00 4.17 59.19 246.83 79.62 326.45 326.452019 0 12264.00 4.17 59.49 248.06 79.62 327.68 327.682020 0 12264.00 4.17 59.78 249.30 79.62 328.92 328.922021 0 12264.00 4.17 60.08 250.55 79.62 330.17 330.172022 0 12264.(O 4.17 60.38 251.80 79.62 331.42 331.422023 0 12264.00 4.17 60.69 253.06 79.62 332.68 332.68

NPV @10% 1631.55 64086.77 21.79 1223.64 448.75 1672.39 3303.95

Power cost - US 5.16 cents/kWh

Source: Bank mission estimate.

-74-Annex 11Page 9 of 9

ECONOMIC ANALYSESPOWER COST & NET BACK VALUE - COAL

Table 12.8: Coal Fired Power PlantLow Sulphur Coal (0.5%), with low efficiency FGD

(Constant 1993 US Dollars)

ASSUMPTiONS:Plant Factor - 70% Capital Cost - $11901kw Life - 25 yearsEffticlency - 36% Operating Cost - 3.7% of investment cost Construction lime - 5 yearsSize - 2000 MW

Capital Power Volume of Imp. Coal Fuel Operating Total Oper.Year Cost Generated Coal CIF Cost Cost Cost Total Cost

($ mli) GWhYear (mil tons) ($lion) (S mil) ($ m0) ($ mil) ($ mil)

1994 476.00 0 0 0 0 0 0 476.001995 476.00 0 0 0 0 0 0 476.001996 476.00 0. 0 0 0 0 0 476.001997 476.00 0 0 0 0 0 0 476.001998 476.00 0 0 0 0 0 0 476.001999 0 6132.00 2.20 54.00 118.80 88.06 206.86 206.862000 0 9198.00 3.30 54.27 179.09 88.06 267.15 267.152001 0 12264.00 4.40 54.54 239.98 88.06 328.04 328.042002 0 12264.00 4.40 54.81 241.16 88.06 329.22 329.222003 0 12264.00 4.40 55.09 242.40 88.06 330.46 330.462004 0 12264.00 4.40 55.36 243.58 88.06 331.64 331.642005 0 12264.00 4.40 55.64 244.82 88.06 332.88 332.882006 0 12264.00 4.40 55.75 245.30 88.06 333.36 333.362007 0 12264.00 4.40 56.03 246.53 88.06 334.59 334.592008 0 12264.00 4.40 56.31 247.76 88.06 335.82 335.822009 0 12264.00 4.40 56.59 249.00 88.06 337.06 337.062010 0 12264.00 4.40 56.87 250.23 88.06 338.29 338.292011 0 12264.00 4.40 57.16 251.50 88.06 339.56 339.562012 0 12264.00 4.40 57.45 252.76 88.06 340.82 340.822013 0 12264.00 4:40 57.73 254.03 88.06 342.09 342.092014 0 12264.00 4.40 58.02 255.30 88.06 343.36 343.362015 0 12264.00 4.40 5&31 256.57 88.06 344.63 344.632016 0 12264.00 4.40 58.60 257.85 88.06 345.91 345.912017 0 12264.00 4.40 58.90 259.14 88.06 347.20 347.202018 0 12264.00 4.40 59.19 260.44 88.06 348.50 348.502019 0 12264.00 4.40 59.49 261.74 88.06 349.80 349.802020 0 12264.00 4.40 59.78 263.05 88.06 351.11 351.112021 0 12264.00 4.40 60.08 264.37 88.06 352.43 352.432022 0 12264.00 4.40 60.38 265.69 88.06 353.75 353.752023 0 12264.00 4.40 60.69 267.02 88.06 355.08 355.08

NPV 2)10 1804.41 64086.77 22.99 1290.90 496.32 1787.22 3591.63

Power cost US 5.60 cents/kWh

Source: Bank mission estimate.

-75- Annx 12Page 1 of 1

SECOND GAS SMASNION PRWCT

Selected Docume and Data Available In Project File

1. Certification of gas reserves for Unoca' fields.

2. Gas sales agreement between Unocal and PrT (Agreemes I, , and six amendments toAgreements I and DI).

3. Gas sales-purchase agreement between PIT and EGAT.

4. Environmental Assessment Report.

5. Contract between PT1 and Bechtel for engnring consultay services.

6. Master plan for gas etansmission.

7. Bid documents for offshore pipeline consuction contract.

CHRT

THALAND

SECOND GAS TRANSMISSION PROJECT

Energy Sector Organizations

NEPC

PM 1-IE NUSR SCIaNCE FINANCEMINISTRY TECHNOLOGY MINISTRY

MINISTRY ~MINISTRY

- NEPO - DMR - DEDP - fPO- NESDB - Petoleum - ECCT - Excise Dept.- EGAT Ind. Div. - Revenue Dept.

- PT - BCP

DEFENCE COMMERCE INTERIORMINISTRY MINISTRY MINISTRY

Defence Eriergy - CRD - PWDDept. - Internal Trade - MEA

Dept. - PEA

-77-

TRAILAND

SECOND GAS TRANSMISSION PROJECT

PITT Organization

( erleum Authority of Ilnailand

Deputy Governor

Downstream~~~ Head Busines ,______

V Policyand Plann

President

Natural Gas Business

President

Cental Services Business< ~~President >

PetocemialBusinessGeneral Manager

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MAY 1994

IBRD 25767;CHINA f -0 102 104

. ; . '.^ ~~~~~~~~~~~THAILANDMYANMAR TA N'PEOMPL SECOND GAS TRANSMISSION PROJECT

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MAY 1994