World Bank Document · The report consists of a Project Completion Report (PCR) prepared ......

Document of

The World Bank

FOR OMCUIL USE ONLY

Report No. 5792

PROJECT PERFORMANCE AUDIT REPORT

THAILAND: SECOND NATURAL GAS DEVELOPMENT PROJECT

(LOAN 1773-TH)

June 28, 1985

Operations Evaluation Department

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FOR OMCIL USE ONLY


THAILAND; SECOND NATURAL GAS DEVELOPMENT PROJECT(LOAN 1773-TH)

TABLE OF CONTENTS

Page No.

Preface ..... ..... . . ........................ iBasic Data Sheet ...................... .... iiHighlights ................................. , ............ iv

PROJECT PERFORMANCE AUDIT MEMORANP-i

I. PAST BANK ASSISTANCE TO ENERGY SECTOR ................... 1II. PROJECT RATIONALE .............. ...... .. ..... ....... 2III. GAS EXPLORATION ......................... 6IV. PROJECT OBJECTIVES AND COMPONENTS .................... ... 7V. PROJECT COST AND IMPLEMENTATION ......................... 9VI. GAS RESERVES AND PRODUCTION FORECASTS ................... 13

VII. PROJECT ECONOMICS ....................................... 19VIII. GAS PRICING AND PROJECT BENEFICIARIES ................ ... 24IX. CONCLUSIONS ............................................. 28

Attachment - Comments from the Government ......................... 3;

PROJECT COMPLETION REPORT

I. Introduction ........................................... 33II. Project Preparation and Appraisal ...................... 34

Ill. Implementation ......................................... 35IV. Operating Performance ...... ............................ 41V. Economic Performance ................................... 41VI. Institutional Performance .............................. 44VII. Financial Performance ...... ............................ 45VIII. Performance and Role of the Bank ....................... 49

IX. Conclusions ................ 50

Annexes

1. Comparison of Estimated and Actual Project Costs ..... 6 532. Schedule of Disbursements .............................. 543. Economic Analysis ..................................... 554. Natural Gas Operations Finances ........................ 56

Income Statement ............................ 57Sources and Application of Funds .......... .. ........... 58Balance Sheets ....... .................................. 59Gras Sales Margins ...... .............. .................. 60

5. Consolidated PTT Finances .............................. 61

Map - IBRD 13476R1

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

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THAILAND: SECOND NATURAL GAS DEVELOPMENT PROJECT(LOAN 1773-TH)

PREFACE

This Project Performance Audit Report (PPAR) represents a perfor-mance audit of the Thailand Second Natural Gas Development Project, for whichLoan 1773-TH for US$107 million equivalent was approved on December 11,1979. The loan was fully disbursed by December 31, 1983, when it was closed.

The report consists of a Project Completion Report (PCR) preparedby the Energy Department of the Energy and Industry Staff and a ProjectPerformance Audit Memorandum (PPAM) prepared by the Operations EvaluationDepartment (OED). The borrower contributed to the PCR by supplying necessaryproject data. OED has reviewed the PCR against the Appraisal and President'sReports, the legal documents and the transcript of the Executive Directors'meeting which considered the project. Project files and documents have alsobeen reviewed and discussions have been held with Bank operational staff.Further, an OED mission had discussions with officials of Government depart-ments and agencies and managers of an international oil company in April andOctober 1984.

In the audit's view, the PCR gives, on the whole, a fair account ofthe experience under the project. The PPAM has expanded on a number ofissues, modified the discussion of others and added new ones.

Following standard procedures, OED sent copies of the draft PPARto the Government/borrower for comments. The comments which were receivedhave been reproduced as an Attachment to the PPAM.

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PROJECT PERFORMANCE AUDIT BASIC DATA SHEET


KEY PROJECT DATA

Appraisal Actual orEstimate Current Estimate

Total Project Cost (USS million) 514 423- Underrun (%) -- 18

Loan Amount (US$ million) 107 107- Disbursed -- 107

Date Physical Components Completed 09/01/R1 09/01/81Proportion of Physical Components

Completed by Original Completion Date (Z) 100 100Proportion of Time Overrun (%) -- 0Economic Rate of Return (%) 48 45-50Financial Rate of Return (%) 15 15 /a

Cumulative Estimated and Actual Disbursements(US$ million)

FY79/80 FY80/81 FY81/82 FY82/b3 FY83/84

(i) Appraisal 19.0 83.0 100.0 106.0 107(ii) Actual 0 70.9 96.5 96.5 107

(iii) Actual as X of Appraisal 0 85 96 91 100

OTHER PROJECT DATA

Original Date Actual Date

First Mention in Files n.a.Government's Application 1977Negotiations 09/26/79Board Approval 12/11/79Loan Agreement 02/15/80Effectiveness 05/15/80 05/27/81Closing 12/31/83 12/31/83Borrower and Executing Agency Petroleum Authority of Thailand

(PTT)Fiscal Year of Borrower October I - September 30Follow-up ProjectName Liquified Petroleum GasLoan Number 2184-THAmount (USS million) 90Loan Agreement 08/17/82

/a According to PCR. Calculation not verified by audit.

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MISSION DATA

Month/ No. of Staff- Date ofYear Persons weeks Report

Identification/Preparation /a 76-78 3 17Appraisal 03/79 3 6 11/05/79Supervision 1 05/80 1 1 06/03/80Supervision 2 07/80 3 5 08/15/80Supervision 3 12/80 2 3 01/12/81Supervision 4 07/81 3 4 07/28/81Supervision 5 09/81 2 3 10/26/81Supervision 6 11/82 2 8 11/18/82Completion 01/83 3 3 08/20/84

Total 50

CURRENCY EXCHANGE RATES

Name of Currency (Abbreviation): Baht (B)

Appraisal Year Average (1979) US$1.00 = B 20.3Completion Year Average (1983) US$1.00 = B 23.1

/a Including work related to Natural Gas Development Engineering Project,Loan S10-TH, which was appraised in June 1978.

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HIGHLIGHTS

The project changed the focus of the Bank's energy sector lendingin Thailand. Prior to the project, during a period of 20 years, the Bankprovided financial assistance exclusively for hydro-electric and thermalpower generation and transmission. Starting with the project, the Bankbroadened the assistance to other sources and forms of indigenous energy-gas, gas derivatives and lignite (PPAM, paras. 1-4).

Throughout the sixties and seventies, petroleum products dominatedThailand's total energy supplies, accounting by the end of the seventies forover 70% of the total. Virtually all petroleum products were imported.Because of the developments in international oil markets during the seven-ties, Thailand's energy import dependence became a serious threat to theeconomy. This project, in combination with other projects and reformulatedenergy policies, was to remove or lessen the threat (PPAM, paras. 6-14).

The project became feasible because of off-shore gas explorationinitiated in the late sixties, well before the first oil shock occurred in1973-74. Exploration, a complex, high risk and capital intensive under-taking, was the exclusive domain of international oil companies (IOCs). Inthe mid seventies, exploration led to the discovery of two major tracts ofcommercially attractive fields, which formed the basis for the project (PPAM,paras. 15-18).

The project was the Government's contribution toward actual use ofthe latent gas reserves. It consisted of a marine and land-based gas trans-mission system and included consultants' services for institutional develop-ment of the Petroleum Authoritv of Thailand (PTT), the designated pipelineoperator, and studies of energy policy issues. Field development was theresponsibility of the IOCs. Most of the gas to be delivered under the proj-ect was destined for use in power generation (PPAM, paras. 19, 21, and 23).

Project cost, projected at US$514 million, was financed by theGovernment (US$77 million) and external borrowing (US$437 million). MatchingIOCs' total investments for exploration and development are projected toexceed US$2 billion. The Bank loan of US$107 million was in line with theBank's target of financing 15-20% of oil and gas development projects set outin energy policy papers, but no specific explanation has emerged for deter-mining the precise amount of the loan. The large scope of commitment ofGovernment credit worthiness was explained by the IOCs' reluctance to financemore than field exploration and development. Physical implementation of theproject was completed on schedule and with an 18Z saving in cost. The pipe-line was commissioned in the second half of 1981 and has been in satisfactoryoperation since (PPAM, paras. 24, 25, 28 and 45).

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Certification of adequate gas reserves by independent reservoirconsultants was a condition for loan processing. Between 1978 and 1983,certified gas volumes oscillated widely. In the latest round of assessments,all Gulf gas reserves were substantially revised downwards on account of theexperience with the field which was first developed. That field showed high-ly unusual geological conditions, and it could be assumed that other fieldshad similar characteristics. The entire episode generated doubts about therationale, validity and adequacy of the field evaluations; and it raisedquestions about the Bank's role in their design or review (PPAM, paras.33-36).

Gas production forecasts were loosely tied to the gas reserveevaluations performed by the reservo'r consultants. At appraisal, it wasbelieved that total proven and probable reserves provided an adequate safetymargin for project viability. In the end, the margin of safetv was small,and the reduced margin so far is only partly covered bv a gas productionagreement between an IOC and PTT. The experience demonstrates that adequateattention must be given to gas sales agreements, which as much as adequatezcserves in the ground are necessary for the production of gas (PPAM, paras.17-39).

In the first three years after gas production started (1982-84),gas volumes were substantiallv short of projections. Partly as a res-ilt ofproduction from fields which did not form the basis of the project, aggregateGulf production, however, should, in The coming years, approximate the pro-jections. Natural gas trom the Gu'.f, in conjunction with other indigenousenergy supplies and dema-d--based e;;ergv policies. is now on the threshold ofmaking the country's energy imporc dependence manageable (PPAM, paras. 38-39and 54).

From the outset, the project wes viewed as being econnmicallyhighly attractive and relatively immune to serious risks. The economic rateof return (ERR) projected was aboait 50%. Tle PCR has recalculated the ERR atabout 45%, and the audit estimates the ERR to fali into the 45-50h range.Indications are that the project has come a long wav toward maximizing theinvestment return. The IOC currently producing gas reports that it expectsits financial retuirn on investments to be below 15Z, a result which in itsview is disproportionate to its investment risks and to the project'seconomic benefits to the country. Perceptions of inadequate private sectorreturns could have a bearing on IOCs' future involvement in the Thai energysector and invite Government and Bank attention (PPAM, paras. 42-47).

To promote energy efficiencv, ensure financial viabilitv of thepipeline operator and generate Governmenr revenues, the project included aprovision for delivery of gas to the principal end-user (power generatingutility) at a price close to 90% o' the cost of fiel oi. To enforce theprovision, loan effectiveness was held up bv 1. months. In the end, theprovision was relaxed, and the fueJ oil parity actuallv achit-ved was between70 and 802 (PPAM, paras. 68--91'.

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As a result of the project, PTT's Office of Natural Gas, if not PTTitself, was expected to show an outstanding financial performance. Rates ofreturn on net fixed revalued assets and cash balances projected were, forThai state enterprises, exceptionally high. However, the project containedno special proviston for transforming PTT revenues into treasury revenues.The project, in this regard, may riot have been fully consistent with theapparent objective of generating budget revenmies, and it may not havereinforced financial discipline (PPAM, para. 52).

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PROJECT PERFORMANCE AUDIT MEMORANDUM

THAILAND: SECOND NATURAL GAS DEVELOPMENT PROJECT(LOAN 1773-TB)

I. PAST BANK ASSISTANCE TO ENERGY SECTOR

1. The Second Natural Gas Development Project (pr pared under an engi-neering loan, the -first- gas project) marked the beginning of a second phasein the long-standing Bank support to the Thai energy sector. Under the firstphase, which lasted 20 years from 1957 (the year of the first lending opera-tion) to 1977, financial assistance was exclusively provided for (hydroelec-tric and thermal) power generation and power transmission through loans madeto the Electricity Generating Authority of Thailand (EGAT) and its prede-cessor utilities._/ Under the second phase, starting in 1978, the Bankbecame involved in the development of (non-hydro) indigenous sources ofenergy-gas, gas derivatives and lignite, to address the wider needs of theThai energy sector since the mid-seventies and to fulfill its mandate of morediversified and intensified energy sector assistance to its member countries.

2. Thirteen power project and power subsector loans to EGAT and itspiedecessors for a total of US$673.1 million, and three loans to the Provin-cial Electricity Authority (PEA)2/ for a total of US$130.6 million have sofar been made. The projects were reported to have been satisfactorily imple-mented or are in progress. Another power subsector loan to finance EGAT'sinvestment program is under preparation. Project Performance Audit Reports(PPARs) were issued on three projects (Loans 655-TH of 1970, 790-TH of 1971and 977-TH of 1974). All three projects were evaluated as having met theirmajor stated objectives.

3. Three gas-related projects were financed, for a total loan amountof US$201.9 million: the Natural Gas Development Engineering Project (LoanSOIO-TH of 1978), the project under audit (Loan 1773-TH of 1979) and theLiquified Petroleum Gas Project (Loan 2184-TH of 1982). Loan SOLO-TH pre-pared the project supported under Loan 1773-TH through project management,engineering and financial services, and through training and advisory ser-vices to the entity designated to implement Loan 1773-TH. Loan 2184-THfinanced a gas separation plant to recover LPG, propane and other hydro-carbons from natural gas piped from the Gulf, storage and distribution

I/ EGAT, a state enterprise, is the largest Thai utility generating andsupplying electric power.

2/ PEA, also a state enterprise, is charged with the supply of electricityoutside Bangkok Metropolitan Area. It is engaged primarily in thetransmission of power, buying most of its electricity from EGAT.

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installations for LPG and propane, and studies and technical assistance.Another gas-related project, the Bangchak Oil Refinery Restructuring Project(Loan 2548-TH), was recently approved. Preparation of a project related toon-shore oil field development is in progress.

4. The Bank has supported lignite production through two operations,the Mae Moh Lignite Project (Loan 1852-TH of 1980) and the Second Mae MohLignite Project (Loan 2407-TH) of 1984. Total Bank financing was US$131.1million. EGAT, which operates the Mae Mob mioe, was the borrower in bothcases.

5. Several other recent Bank operations had energy-related components,including the Structural Adjustment Loan (2097-TH of 1982, SAL I), the SecondStructural Adjustment Loan (2256-TB of 1983, SAL II) and the Second Provin-cial Roads Project (Loan 2311-TH of 1983). SAL I included agreements on thedesign of a program of energy conservation, pricing/taxation and development;creation of an institutional framework for energy policy coordination; andthe undertaking of a petroleum pricing study later expanded to cover also gasand lignite (Energy Pricing Study). Under SAL II, the Government undertookto formulate an action program for energy pricing, based on the SAL I pricingstudy, and to institute steps to further the efficiency of energy use inindustry and transport. Loan 2256-TB also dealt with specific aspects ofenergy pricing in transport. Bank assistance to the Thai energy sector hasalso been rendered in the context of the country economic and sector work,and a major undertaking, a formal energy assessment, is currently underway.The Third Structural Adjustment Loan, under preparation, is expected toinclude further provisions for energy policy reforms.

II. PROJECT RATIONALE

The Macro-economic Issue

6. Fuelled by high growth rates of a strongly expanding economy,Thailand's consumption of primary energy3l in the sixties grew at the fastpace of 15-17% p.a. Comercial energy, representing between 80-90% of totalprimary energy, even grew at a slightly higher rate, far ahead of the moreslowly expanding non-commercial energy. The overall pace continued into theseventies up to the first oil shock in 1973/74, when growth temporarily cameto a halt. It bounced back thereafter to about 8-9% p.a. until, during thesecond oil shock in 1979/80, there was once more a brief period of nogrowth. Despite the two periods of contractions, energy supply in theseventies expcnded at an average rate of 7% p.a., marginally ahead of growthin GDP.

3/ Commercial and non-commercial energy combined. Non-commercial energyincludes chercoal, firewood, bagasse (based on sugar cane) and paddyhusk.

7. Throughout the sixties and seventies, petroleum products dominatedtotal energy supply. By the end of the seventies, they accounted for about72Z of total supply, while hydroelectricity provided about 3X of energy,lignite and small quantities of (imported) coal combined also about 3%, andother, mostly non-cocmercial fuels, the remaining 22Z. Again, by the lateseventies, transport consumed some 41X of oil products, followed by electric-ity and water supply with 21X, the manufacturing industry with 18Z, agricul-ture (including fisheries) with 11X, and all other sectors combined, with 9Z.

B. Virtually all petroleum products were imported to Thailand, eitheras crude oil for processing in Thai refineries or as end-use products. Since1973/74, because of the steep increases in (real) prices for petroleum prod-ucts, these imports progressively burdened the Thai economy and weakened itsexternal trading and financial position. By 1980, net oil energy importsamounted to about US$2.5 billion, which was about 30% of total merchandiseimports and 42% of total merchandise exports. They equalled the trade defi-cit and 8% of GDP of that year.

Energy Sector Strategy

9. To limit the exposure to events in the international oil marketsand to counter the high cost of energy supply, the Government, in the lateseventies, developed a two-pronged energy strategy: energy conservation andconstraints on growth in energy demand; and shift of energy supply towarddomestic energy resources. The strategy of energy conservation and con-straining energy demand was, to a large measure, based on the close linkageof domestic energy prices with international oil prices.4/ After littledomestic price adjustments in the mid-seventies for oil products, theGovernment sharply increased the prices in the late seventies. On variousoccasions since, the Government has confirmed the principle of reflectingprice movements of imported energy in the domestic price structure. Acomplementary element of the pricing strategy was a package of regulatorymeasures of energy conservation, particularly in industry and transport. Thedesign of sectoral conservation programs was to be started off with an

4/ Such a linkage was to be incorporated in the project (PPAM, para. 49).

industrial energy audit5/ and to gradually cover other key consumptivesectors.6/

10. The strategy of substitution of imported oil products was based onthe development of all commercial sources of domestic primary energy--hydro-power, lignite and natural gas. Power, industry and transport were the mostimportant sectors targeted for import substitution. Power offered the great-est scope for substitution of oil products because of potentially large-scaleuse of all three sources of indigenous energy. Industry could make wider useof lignite, on which it already based a small fraction of its fuel needs, andshift to natural gas, where feasible. Transport could utilize liquifiedpetroleum gas (LPG), a component of natural gas, to power vehicle engines asa substitute for gasoline and possibly diesel. With some modifications inengines and fuel storage, passenger and smaller freight vehicles could effi-ciently be run on LPG, and there were even prospects for use of LPG in largerutility vehicles.7 /

11. About one-half of the hydroelectric potential assessed at the timewas considered economically feasible. By the late seventies, only about 20%of this potential was installed, leaving considerable scope for furtherexpansion. In the long run, there was also the hydropotential of the inter-national Mekong and Salween Rivers, matching Thailand's entire domestic hydroresources, though political and security considerations precluded its exploi-tation for the foreseeable future. Various plans developed at that time

5/ An industrial energy audit was an item included in the project (PPAM,paras. 21 and 30).

6/ Two studies on related topics, one financed by the Asian DevelopmentBank and the other by Japanese bilateral assistance, are in the finalstages of completion. A study of incentives for energy conservation inindustry, with Bank financing, is scheduled for the near future. Forthe transport sector, the Ministry of Communications, with Bank assis-tance (Sixth Highway Project, Loan 1519-TH) undertook a study on energypolicies which, completed in 1982, forms the basis for a detailed actionprogram currently under preparation. Other studies also had a bearingon energy conservation issues: a Bank-financed lignite pricing study(Mae Moh Lignite Project, Loan 1852-TH), completed in 1983, and anenergy pricing study (Loan 2097-TH), completed in draft final form in1983. Refer also to PCR, para. 3.17.

7/ In recent years, a growing number of smaller vehicles (in particular,taxis) operating in the Bangkok Metropolitan Area on imported LPG, hasconfirmed the feasibility of an LPG-based fuel supply system.

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envisaged doubling or tripling installed hydrocapacity by the lateeighties.8/

12. Thailand's (proven and probable) lignite reserves were, by the endof the seventies, assessed at about 750 million metric tons. The reserves,about one-half of them economically recoverable, were upgraded from only 200million tons a few years earlier. Production had more than doubled from1977-78 to 1979-80 and was projected to at least quadruple by the earlynineties.9/ The largest deposits are at Mae Moh in the North. Other sig-nificant deposits are at Krabi in the South, and there are small deposits invarious other locations. The Mae Moh and Krabi deposits are mined by EGATfor use in power generation. The other mines are operated by private indus-trial companies which use the lignite as a source of fuel.10/

13. Thailand's confirmed gas reserves, as evaluated in the late seven-ties, were by Thai energy standards of formidable dimensions. The fields,all off-shore in the Gulf of Thailand, were (in 1979) assessed at 7-6 tril-lion cubic feet (tcf) of economically recoverable reserves, of which _.9 tcfwere proven and 4.7 tcf were probable (PPAM, para. 33). All fields combinedwere conservatively estimated to produce some 500-600 million cubic feet perdayL/ (MKCFD) over some 20 years, or equivalent quantities for otherperiods (PPAM, para. 38).

8/ Current plans aim at an 80% utilization of the economically feasiblehydro-potential by about the mid-nineties.

9/ Production was 0.6 million tons per year (tpy) in 1977-78, and 1.3-1.4million tpy in 1979-80. Under investments undertaken since 1980 withBank assistance, current (1983) mine output is about 1.8 million tpy,and with other Bank assisted investments in progress (para. 4), 1986output is expected to be about 5.0 million tpy. Current long-term plansenvisage total production to reach about 12 million tpy in the earlynineties, a twenty-fold increase over the 1977-78 levels.

10/ In 1982, non-EGAT mines produced some 0.15 million tons, about 9% of thecountry total.

11/ Quantities standardized at calorific value of 1,000 British ThermalUnits (BTU) per cubic foot.

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14. The energy sector strategy, shaped in the late seventies,12/ wasprojected to produce these global results: restraint of energy demand to agrowth rate approximating that of GDP, in the eighties; and supply of primaryenergy from indigenous resources in the order of 55-65% of total needs, byaround 1990. Among the comuercial energy sources, hydropower was to reach asupply share in 1990 of some 7%, up from 3Z in 1980; lignite, some 10%, upalso from 3Z; and natural gas, 18-25Z, up from zero percent. The projectionswere based on production of some 500 MMCFD of gas. The supply scenarios madeit explicit that natural gas had the potentially largest impact on oil importsubstitution, in view of the smaller resource base of hydropower and lignite,and that any serious setback in gas production would be an equally serioussetback for energy import substitution.

III. GAS EXPLORATION

15. The project was based on gas exploration initiated some ten yearsearlier, well before the 1973/74 oil shock forced a global rethinking ofenergy policies and raised rewards for development of indigenous energy. Theexploration was greatly helped by improvements in off-shore drilling tech-niques and the 1972 passage of Thai legislation under which the legal andfiscal rights and obligations of concessionaires were established. A tech-nologically highly complex, risky and capital intensive undertaking, explora-tion was the exclusive domain of international oil companies (IOCs),13/which included well known names in the industry.

16. Early exploration was onshore. With the prospect of new legisla-tion, exploration interests focused on off-shore areas, the Gulf of Thailandand the Andaman Sea, and the first concessions for those areas were grantedin the late sixties. Actual off-shore exploration was concentrated in theGulf, with only minor activities in the Andaman Sea. Exploration in theAndaman Sea was finally discontinued and the concessions were relinquished bymid-seventy after prospects for finds had diminished. Exploration in theGulf spanned over the entire seventies, with a marked intensity in 1974 and1975. In the mid seventies, it led to the discovery of two major tracts ofgas fields by two concessionaires, Union Oil (in partnership with South EastAsia Petroleum Exploration Company) and Texas Pacific (in partnership withCanadian Superior Oil Company and Highland, Inc.).

12/ The Fifth Five-Year Development Plan (1982-86) reiterated the Govern-ment's resolve to restructure the energy demand and supply, and itrecast and formalized the quantitative sector targets. Under this plan,total energy consumption was to be limited to 4.6Z p.a. during the planperiod, a figure below the target growth rate of GDP; and the share ofoil products consumption of total (primary) energy consumption was setat 46% by the end of the plan period (down from over 70% in 1980).

13/ Various formulas for Thai capital participation in exploration are beingexplored.

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17. Union Oil discovered its first commercial quantities of gas in theso-called 'A Structure, a field also known under the name of Erawan.Located some 425 km south of Sattahip port on the Eastern Seaboard, and some150 km off the coast of southern Thailand, the field covers an area of about25 x 5 km. The other fields, which Union Oil subsequently discovered, wereBaanpot to the south of Erawan and Kaphong, Platong, Pladong and Satun to itsnorth, all of them (including Erawan) forming an area of some 180 x 60 km.Texas Pacific made its discoveries in a field known as -B' Structure, some170 km southeast from Erawan and some 200 km off the southern peninsula.Both these Union Oil and Texas Pacific fields formed the basis for the SecondNatural Gas Pipeline Project.

18. The first concessions for on-shore exploration were also grantedand relinquished by the early seventies, after several wells drilled weredry. In the late seventies, interest in on-shore exploration was rekindled,and new concessions were issued to several firms. isso, one of them, hasmore recently struck gas in the Korat Basin in the Northeast, and expecta-tions are that there are commercially significant gas reserves.14/

IV. PROJECT OBJECTIVES AND COMPONENTS

19. The project was the Government's contribution toward production,transport and utilization of Gulf gas. It entailed Government financing oflarge investments for the gas pipeline system and a Government commitment topurchase, market and utilize the gas. Having already financed gas explora-tion and being prepared to finance field development, IOCs were reluctant toalso finance the transmission system. To the Government, the project was ahigh-yielding and relatively risk-free venture to transform latent and

14/ In addition, Shell struck oil in the upper central plains. The field,Sirikit, came into production in 1983. It currently yields about 20,000barrels of oil per day (bpd), and output is expected to remain at aboutthis level. The oil field has raised hopes for more substantial oildiscoveries.

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confirmed energy resources into tangible and quickly maturing economicbenefits.15/

20. The Bank played several roles under the project. It assisted inarranging external financing for the public investments, which in view oftight domestic resources was mandatory. It helped organize the efficientinstallation and management of the gas transport and distribution system, andit endorsed the Government's Gulf gas development plans, project investmentsand agreements. Jointly with other external project sponsors, it alsoprovided the private sector with cover against conceivable, though in no wayimminent non-commercial risks.

21. The project focused on the provision and phasing-in of the gastransport and distribution system. Other main areas of attention were insti-tutional development of the executing agency and designated operator of thepipeline, the Petroleum Authority of Thailand (PTT), and studies of selectedenergy sector issues. The transport and distributioi system consisted of amarine pipeline (about 425 km) from the Erawan field to shore, a landbasedpipeline (about i70 km) to two EGAT power plants in Bangkok, and on-shoreterminal and operating facilities, including a communication center. Insti-tutional development of PTT was to be achieved primarily through a program ofstaff training in a broad range of gas-related skills, including pipelineoperations and accounting/finance. The sectoral issues to be studied, alsowith consultants' assistance, included gas utilization, refinery expansionand energy conservation, the latter topic covering all of the following: anenergy audit, an investment program for energy savings, policies for energydemand management a.nd future investments in energy including non-conventionalsources.16/

22. The marine pipeline was dimensioned to carry about 500 MMCFD of gasunder free flow conditions and up to 700 MMCFD, if compressors (not includedin the project) were added. Pipeline capacity was based on projected extrac-tion of gas from the Erawan field ("A Structure, Union Oil), the B

15/ The SAR and President's Report did not include an explicit statement ofproject objectives. Some objectives may not have needed much elabora-tion, and others were implicitly covered in various parts of thereports. The lack of such statement, nonetheless, renders the taskdifficult to evaluate project progress and success. Explicit, struc-tured, coherent and operationally relevant objectives, which are amena-ble to monitoring, should be routinely made part of project documents.

16/ Scope of energy conservation studies in accordance with SAR, para. 2.08(Project Description) and Minutes of Understanding, September 26, 1979,para. 15. In fact, the Loan Agreement (Schedule 2, Description of theProject, Part E: Studies) referred only to an energy audit of majorindustries.

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Structure (Texas Pacific) and other, at the time yet uaconfirmed, eas struc-tures.17 / A pipeline with a smaller diameter dedicated to the projectedErawan production only would have resulted in savings of some 10% of totalproject cost, but would have required construction of a second pipeline forthe Texas Pacific gas, had it come on stream while Erawan was at its pro-jected peak. A pipeline with a larger diameter was apparently rejectedbecause a throughput exceeding 700 MMCFD (with compressors) was consideredunlikely.

23. A cornerstone of the project was the existence of a gas salesagreement between Union Oil and PTT, under which, starting by September 1981,gas from Erawan would be delivered in annual quantities of 200 MMCFD in thefirst year of production (1982) and, subject to annual confirmation, 250MMCFD thereafter. The contracted gas volumes were tied to the estimated sizeof Erawan's economically recoverable reserves and expected to be sustainedfor about 20 years. The sales agreement was signed in 1978. It was contin-gent upon certification of a minimum of 1.0 tcf of proven recoverablereserves in the Erawan field, a condition which was met several months priorto loan approval.18 / The Union Oil-PTT contract included a take-or-payprovision, under which PTT would be heavily penalized19 / if it did not takedelivery of the gas. PTT expected to cover its own contractual risks througha take-or-pay gas sales agreement with EGAT (for quantities broadly matchingthose of the Union Oil-PTT contract), which was not yet in force when theloan was approved, but made a condition of loan effectiveness.20 /

V. PROJECT COST AND IMPLEMENTATION

24. Total project cost, including physical and price contingencies andinterest during construction, were estimated at appraisal at about US$514million. They were to be financed by a Government contrioution (US$77million), export credits by the United States, Japan and European countries

17/ The pipeline connecting the -B Structure with the Erawan pipeline wasnot included in the project, but expected to be laid after the TexasPacific gas had been contracted.

18/ SAR, para. 2.03. The amounts certified were 1.1 tcf of proven and 0.4tcf of probable reserves.

19/ SAR, para. 2.15. Penalty in the order of USS0.5 million per day in 1982based on 200 MMCFD.

20/ Despite the lack of a binding agreement between PTT and EGAT when theloan was made, it was expected that EGAT would be agreeable to takingtimely delivery of the gas (PPAM, para. 49-51).

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(US$180 million), loans from commercial banking sources (US$150 million) andthe Bank loan (US$107 million). The Bank loan was primarily to finance theoff- and on-shore pipelaying contracts, and it was to refinance the loan(US$4.9 million) arranged under the Natural Gas Development EngineeringProject (Loan S010-TH). No clear rationale has emerged to support the pre-cise amount of the Bank loan.21/

25. Actual total project costs were about US$423 million, which isUS$91 million or 18% below the SAR estimates. Partly offset by higher expen-ditures for materials, equipment, project engineering and project management,the principal savings achieved were in the pipelaying contracts. The othersavings were in taxes and import duties, freight and other pre-constructionand installation charges. The PCR credits keen competition under prevailingmarket conditions, which were apparently not anticipated, for the substantialcost savings in pipelaying. Other explanations suggested in the PCR22/ forthe cost underrun are good project management and the adherence to the orig-inal project schedule, although, of course, the original cost estimate wasunlikely to have anticipated poor project management and the estimate wasbased on the original schedule which was actually achieved.

26. At appraisal, the cost for project engineering and management wereestimated at about US$23 million (including contingencies), based on estimat-ed 5,000 man-months, unit rates of USS7,100-8,600 per man-month for expatri-ate personnel and US$1,900 for Thai engineering staff, and a profit fee- ofUSS4 million. Actual total costs were about US$43 million, an increase ofUSS20 million or 87%. Bank supervision reports and the PCR23/ make onlyterse references to the causes for the stiff overrun--higher than anticipatedstaff input, resulting in part from inadequate communication between the con-sultants and their client, and rates higher than the Bank had experiencedunder similar projects.24/ This raises the question, whether there was a

21/ Bank staff state that 'the aim of the [project] financing was to maxi-mize export credits, to use commercial finance where export credits arenot possible and where bidding procedures are unacceptable to the Bank,and to target the Bank loan at about 20%'. Why this particular targetof Bank participation was chosen is exactly the point the audit israising.

22/ PCR, para. 3.13.

23/ PCR, para. 3.14.

24/ Actual man-months and man-month rates have not been recorded.

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less costly way to overcome communication problems and whether qualifiedconsultants with lower fees could have been selected.25 /

27. The savings in total project cost affected mainly US-procured goodsand services, and the share of export credits of total financing was accord-ingly reduced the most, from US$180 million, as estimated at appraisal, toabout US$125 million. There were also savings under the Bank loan which weresubsequently reallocated to another project item. Except for the Bank loan,which was fully disbursed, all other sources of financing were drawn down ata reduced rate. PTT internally generated cash, which was not expected atappraisal, also contributed to project financing. The first disbursementfrom the Bank loan was held up for 12 months, until the last of three condi-tions of effectiveness, conclusion of a satisfactory gas sales contractbetween PTT and EGAT, was met (PPAM, para. 54). Final disbursement was com-pleted on schedule.

28. The physical components of the project were completed on scheduleand according to specifications. The system was commissioned in Soptember1981, when the first gas was delivered, and it has been in satisfactory oper-ation since. Under its own financing, EGAT converted several thermal unitsat South Bangkok power station to gas and fitted the Bang Pakong station(also near Bangkok) with combined cycle units. Two cement companies built an80-km long pipeline which connects their plants with PTT's pipeline to theEGAT power stations. The connector, dimensioned at about 95 MMCFD (withoutuse of compressors) and available to other industries located nearby, wasbuilt at a cost of about US$60 million and brought into operation in 1983. A43-km long ADB-financed pipeline (including on-shore compression), linkingUnion Oil's Platong field to the main marine pipeline (from Erawan), wascompleted in 1984, with a budget of US$135 million.

29. A training program covering "a11 aspects of PTT's petroleumbusiness' was part of the Loan Agreement's project description. Two types oftraining programs were implemented under the project: overseas training forupper and middle management, and on-the-job training of staff in PTT's Officeof Natural Gas (ONG), later merged into PTT's Natural Gas Operations (alsoONG). The latter training was provided in the context of operational assis-tance rendered under various consultancy contracts. Bank reporting onimplementing the training component was sketchy. A supervision mission inlate 198126/ reportce the institution by PTT of proper manpower planningand training for all its activities, and the PCR states that from aninstitutional perspective, the Bank required and assisted in establishing

25/ Bank staff explain that they considered the fees unreasonably high forthis kind of work and so advised the Government. The Government appar-ently disagreed and the Bank did not finance the contract. Also, staffnote that slow decision-making (on the Government's side) contributed tothe high cost overrun.

26/ Supervision Report, October 27, 1981.

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appropriate technical, financial and operational training programs .27/ Itwould have been desirable that the Bank's requirements and assistance, in thecontext of the project under audit, would have manifested themselves inadequate documentation, detailing training programs, targets, and achieve-ments.2 8/ This might have also facilitated an assessment of PTT's institu-tional development in gas to date. Queries addressed to the audit missionleft the impression that there is interest in such an assessment.

30. According to the Loan Agreement, three sector studies were to beundertaken: a gas utilization study, a refinery expansion study and anenergy audit of major industries. The project contributed its share to theglut of foreign-financed studies, which in recent years has characterized theenergy sector and which Government planners profess to have difficulty todeal with. The Gas Utilization Study was to identify potential and optimaluses of gas to the year 2000 and to assess the associated investmentneeds.2 9/ The commissioning of the study after, rather than before, commit-ment and delivery of gas to end users (notably EGAT) appeared justified atthe time. Long-term gas production of the Gulf was expected to greatlyexceed initial production under the project, and the use of the gas inaccordance with the study's findings was therefore not much in jeopardy. TheEnergy Pricing Study (PPAM, para. 5) confirmed that the use of gas as a sub-stitute for fuel oil in power generation is of high priority. The Gas Utili-zation Study by consultants was packaged in two phases. Phase I was intendedfor identification of the most attractive investments in gas. Phase II wasto study the identified _nvestments in detail. An interim report for PhaseT, identifying LPG, certain petrochemicals and ammonia/urea as being ofhighest priority, was completed in mid-1981. The final report was submittedin early 1983. The Energy Pricing Study covered some of the same groundagain.

31. The Refinery Expansion Study by consultants was satisfactorilycompleted in 1981. A main objective was the identification of measures forcorrecting the supply and demand imbalances for petroleum products. Thefindings were incorporated into the design of the Bangchak Oil RefineryRestructuring Project (Loan 2548-TH) under which the refinery configurationof Thailand will be changed.

32. The Energy Audit of Major Industries was not undertaken, but theproject description in the Loan Agreement was not amended. Several studieswith similar focus are being or will be undertaken outside the context ofthis project (PPAM, para. 9, footnote 6).

27/ PCR, para. 8.01.

28/ Bank staff state that this project's training program was properly docu-mented.

29/ Minutes of Understanding, Attachment 5.

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VI. GAS RESERVES AND PRODUCTION FORECASTS

33. Since inception of the Second Natural Gas Development Project,estimates of the Gulf's gas reserves underwent unexpected, confusing and onoccasion alarming changes. In 1979, when Loan 1773-TH was made, the Gulf'seconomically recoverable proven and probable reserves were confidently andconservatively-30/ assessed at 7.6 tcf. The assessments, referring to UnionOil's Erawan and Texas Pacific "B fields, were performed by independentreservoir consultants. Erawan's share of the 7.6 tcf was 1.8 tcf (1.6 tcfproven and 0.2 tcf probable), against 1.0 tcf tentatively certified in 1978(PPAM, para. 23). In early 1982, when Loan 2184-TH was made, optimism andexpectations about Gulf gas climaxed, and the Gulf's economically recoverableproven and probable reserves were upgraded from 7.6 to 20 tcf. This time,the assessments, now also referring to other (than Erawan) Union Oil gasfields (with 9.2 tcf proven and probable out of the total of 20 tcf), were inpart performed by the same independent reservoir consultants, and in part byPTT and the IOCs. In 1982, gas production from Erawan started, but was imme-diately and drastically short of targets. In response, a reassessment ofErawan by the same consultants was commissioned, which in mid-1983 produced adowngrading of that field from 1.8 to 0.6 tcf.31 / On the experience withErawan, industry observers substantially revised their estimates of totalGulf gas reserves downward, and Bank staff went as far as provisionallyestimating the reserves earlier certified at 20 tcf to be only about 4.5tcf.32 / However, no reserve estimate has been produced since which appearsreliable and on which various analysts and observers can agree. Sincemid-1984, as a result of an accelerated drilling program by Union Oil, Erawangas production has finally come close to original projections, and expecta-tions are that this production can be sustained over an extended period.This would indicate that, after all, Erawan's economically recoverablereserves are above the 0.6 tcf as established in the latest certification33/and that the long-term outlook for Gulf gas is not as bleak as could beassumed in mid-1983.

34. The downgrading of Erawan, which triggered a downward revision ofother fields, had an impact on the concessionaires, the Government, the Bankand the reservoir consultants themselves. It generated doubts about theadequacy of the field evaluations, caused uncertainty about the future ofThailand's energy sector and complicated sector policies. Some uncertaintylingers on and continues to complicate management of the energy sector.

30/ SAR, para. 2.35.

311 Bank staff report that there was a contractual obligation to use theseconsultants and that there was also a mid-1982 independent reservoirstudy on behalf of PTT.

32/ Memorandum dated July 13, 1983. Composition nf the 4.5 tcf: Erawan,0.6 tcf; Texas Pacific, 1.2 tcf; other Union Oil fields, 2.7 tcf.

33/ According to Union Oil.

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35. Bank staff, which used the 1979-82 evaluations at face value in twolending operations (Loans 1773-TH and 2184-TH), and industry sources explainthat the reservoir consultants followed accepted evaluation procedures, andthat highly unusual geological conditions (faulting and fragmentation offields) were responsible for the ill-fated assessments.34 / These sourcesalso explain that only huge budgets for time-consuming gas field appraisalswould have produced the data to give advance notice of the true characteris-tics of the fields and that such budgets and procedures are normally ruledout for off-shore gas. This, of course, means that the chosen gas verifica-tion method had considerable risk of error and that available procedures forreducing the risk are costly and lengthy. It follows that the terms provenand probable reserves have significant variability of meaning depending onthe context.

36. The Bank played a fairly passive role in at least the earlier fieldevaluations relevant for the two appraisals (Loans 1773-TH and 2184-TH).Based on available information, the audit concludes that insufficient atten-tion was paid to the format, potential limitations and interpretation of thereserve evaluations. The terms of reference did not lead to a meaningfuldiscussion of substance and risks of such evaluations, and the Bank did notundertake a formal review of the evaluations upon completion.35/ Despite abrief warning, that fields may not always live up to expectations,3 0/ theappraisal neither elaborated on assessment risks nor corrected the impressionthat classification of reserves as proven- constitutes a categorical proof'of reserves. The reservoir study, certifying proven reserves as proved to a

34/ PCR, para. 3.05, and Bank documents.

35/ According to Bank staff, the Bank participated in the drafting of TORs.However, the audit was unable to obtain copies of the TORs. (Also, nopre-1983 reserve assessment report by consultants could be found in anyof the Bank's document centers.) Bank staff advise that for some time,energy sector record-keeping was not fully satisfactory. In the view ofBank staff, the completed reserve assessments, including the 1979 Erawanassessment financed under Loan SOIO-TH, did not require a formal Bankreview, as the evaluations were performed to industry standards byreputable consultants.

36/ SAR, para. 2.35.

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high degree of certainty for commercial production"37/, did not demonstratethe economics of gas recovery specific to the Gulf of Thailand or thelocations in question,38/ nor shed light on the notion of certainty, and theBank neither challenged this procedure in advance or later or corrected it insome form or another. A more active and informed Bank role in the design andreview of reserve evaluations would be desirable, whenever possible, infuture natural gas operations.39/

37. The Bank's attitude towards the earlier evaluations was consistentwith its assumption that total certified proven and probable reserves (7.6tcf, of which 1.8 tcf for Erawan and 5.8 tcf for Texas Pacific) provided anadequate safety margin for project viability, as they were about five timesthe volume reportedly needed to make the project economic. This assumptiongreatly underestimated the assessments' inherent margin of error. The fieldsassessed at appraisal at 7.6 tcf were subsequently rated at only 1.8 tcf (ofwhich 0.6 tcf for Erawan and 1.2 tcf for Texas Pacific), though this figureis in dispute and by no means universally accepted, and of these 1.8 tcf only0.6 tcf (Erawan) are so far covered by a production contract. In the end, itmay have been the other Union Oil fields, which had not been formallyincorporated into the appraisal's 7.6 tcf safety pool (PPAM, pars. 40), which

37? -Estimated Reserves and Deliverability of 'A' Structure Field, Gulf ofThailand, as of March 1, 1979", page 8. In the follow-up report on thesame field entitled 'Estimated Gas Reserves for Erawan Field, Gulf ofThailand, as of December 31, 1982", dated July 15, 1983, references tothe degree of certainty (or probability) were dropped. According to the'Manual of Oil and Gas Terms", Fourth Edition 1976, page 468, reservesdenoted as proven are probably on the conservative side-. The 1983downgrading of reserves is therefore even more surprising. According tothe American Gas Association's publication -Reserves of Crude Oil,Natural Gas Liquids and Natural Gas in the United States and Canada andUnited States Productive Capacity", Volume 28, 1974, page 103, reservesare "considered proved that have demonstrated the ability to produce byeither actual production or conclusive formation test'. It could bequestioned, whether the 1979-82 assessments met the test for classifyingreserves as proven .

38/ Such factors as gas well-head prices, drilling programs and cost andfinancial rates of return on exploration and development expenditures,were not explicitly incorporated into the assessments, even though allof them and not only the physical presence of gas, determine commercialvolumes of gas.

39/ Bank staff state that the "basis of the reservoir studies" for the Gulffields was "entirely normal" and the Bank review of evaluationsentirely normal and satisfactory". Nonetheless, Bank staff alsoacknowledge that lessons were learned from the earlier Erawan experienceand that they put them to use thereafter. The audit reiterates that thepractices, which Bank staff calls "normal", are indeed good candidatesfor review and possibly overhaul.

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provided the safety margin. If, at appraisal, total proven and probablereserves (for Erawan and Texas Pacific) had been 1.8 tcf rather than 7.6 tcf,or if it had been anticipated, that in the project's first five to ten yearsthere would be no Texas Pacific contract, the project would likely have beendelayed. It is apparent, that much care is needed to ensure that a margin ofsafety is not illusory.

38. The Bank's gas production forecasts were loosely tied to the con-sultants' reserve evaluations, though with incorporation of a further safetymargin, a low implicit gas recovery factor.40 / In 1979, under Loan 1773-TH,the Bank estimated total Gulf production to rise (from about 200 MMCFD in1982) to an annual plateau of about 500/600 MMCFD in 1987-1990, and itimplied that no less than this volume, indicating an "intermediate' produc-tion level, would be sustained to the year 2000.41/ In 1982, under Loan2184-TH, the Bank revised the estimates for total 1990 Gulf production upwardfrom about 500/600 MMCFD to close to 800 MMCFD, and it even suggested thatthe Gulf fields under consideration could ultimately sustain an annual pro-duction of over 3,000 MMCFD.42/

39. Actual 1982 Gulf production (from Erawan) was 130 MMCFD, against200 MMCFD projected, and the 1984 production (from Erawan and Baanpot), wasalso about 200 MMCFD, against 400 MMCFD projected for the year. Despitethese production results being well below projections and the low 1983 Gulfreserve estimates, gas analysts until recently expected total Gulf production

40/ For an assumed 7.6 tcf of recoverable gas and production over 20 years,the recovery factor would have been only 50%. Conversely, given arecovery factor of 100X for proven reserves, as apparently assumed inthe SAR (paras. 1.06 and 2.03), there would have been a factor of leesthan 20% for prob^ble reserves.

41/ Total Gulf and individual field production volumes, which were projectedin the SAR, were not fully consistent (SAR, paras. 2.03-2.07, Annex 1.01and Annex 3.02), nor is the PCR (paras. 5.01-5.02) fully correct instating that the SAR's estimate for the total 1990 Gulf production was500 MMCFD. While the economic and financial analyses used 500 MMCFD for1990, presumably to conform to pipeline capacity under free flow condi-tions, detailed production estimates given in other parts of the SARwere about 600 MMCFD. The 500 MMCFD were made up of 250 MMCFD from eachErawan and Texas Pacific. The 600 MMCFD consisted of about 250 MMCFDfor Erawan, about 200 MMCFD for Texas Pacific and about 150 for not yetidentified fields (presumably also of Union Oil).

42/ Liquified Petroleum Gas Project, President's Report, para. 25 and SAR,para. 1.07. Given such volumes of gas, some industry analysts hadvisions at the time of gas exports and large-scale downstream invest-ments in gas-based industries which would transform the Eastern Seaboardinto the industrial power house of Thailand. These visions subsequentlyvanished, though lately, hopes have again been expressed for gas exportsafter 1990.

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to gradually reach some 400-600 MMCFD by 1990 and some 500-800 HMCFD by cheyear 2000,43/ results broadly framed by the two appraisal's projections,though the make-up of these figures could be considered as worrisome: with-out the not yet contracted Texas Pacific and other not yet identified fields,which were part of the reestimated totals, the residual Gulf production (fromidentified Union Oil fields) would be only 250-400 MMCFD in 1990 and 150-200MMCFD in the year 2000. Since the very recent surge in Erawan production,and on the strength of Union Oil's accelerated drilling program, which willextend into the next fiscal year, Union Oil's total production from presentlycontracted fields (PPAM, para. 40) can now be expected to reach some 500MMCFD by 1985 and to remain sustainable at this level until about the mid-nineties. New already identified Union Oil fields, if timely brought onstream (under a new contract), could by that time make up for the subsequentproduction decline from Union Oil's presently contracted fields and maintaina production level of some 500 MMCFD to the year 2000. Depending on avail-able pipeline capacity, production agreements and gas market, this numbercould conceivably be topped off by production from Texas Pacific and othernot-yet-identified Gulf fields.44 / While aggregate production from theseveral fields would hence be sufficient to match the appraisal forecasts,production only from the fields assessed at appraisal and considered as thebasis for the project (Erawan and Texas Pacific) would have been greatlybelow the forecasts for those fields. Thus, the final production outcome ofthe project is positive, but albeit through cicumstances different from thoseassumed at appraisal. In similar future circumstances, a more comprehensiveanalysis of the factors bearing on production seems desirable. In particu-lar, more attention might be given in future to gas sales agreements betweenconcessionaires and the Government, which as much as adequate reserves in theground, are a necessary condition for the production of gas.45 /

43/ This is the range suggested in the Energy Pricing Study, Stage 1,Vol. 2.

44/ Prospects for on-shore gas deliveries in the late eighties from theKorat Basin in the Northeast have also lately improved. Informationabout the scope of commercial quantities is yet inconclusive, but thereserves are expected to be large enough to significantly affect overallgas supplies. Present production on-shore is about 30-40 MMCFD andbeing used for electricity generation at an up-country EGAT power plant.

45/ Bank staff consider that not much else could be done by the Bank forbringing about the desired gas sales agreements other than through vari-ous post-appraisal interventions by supervision missions, both with Thaiauthorities and reservoir consultants. In the view of the operationaldivision in the Bank responsible for the project, the IOC in questionwas unwilling to come to terms with the Thai Government at a priceacceptable to the Government. If this be so, there still remains thequestion why the IOC maintained or maintains such a posture, whether theposture could have been anticipated at appraisal, and whether a differ-ent project design could have resulted in a different posture.

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40. Two gas contracts are currently in force, both with Union Oil---t:,efirst, signed in 1978, for Erawan gas, and the second, signed in 1982, forgas from Kaphong, Platong, Pladong, Satun and Baanpot. The first contractwas negotiated against the background of a certified volume of economicallyrecoverable gas4 / and at the time expected fairly low production cost, withthe full field development costs and risks carried by the oil company. Thesecond contract, which was also negotiated before the full extent of theErawan situation became apparent, was in substance and format tailored afterthe first.47 / Negotiations between Government and Texas Pacific were heldwith interruptions since 1978, though differences on some issues were nar-rowed. Among the earlier sticking points was the price of gas. Since theexperience with Erawan, the volume of reserves and the gas recovery cost havebecome main issues in negotiations. In light of uncertainties about the vol-umes of recoverable reserves, more recent Government-Texas Pacific negotia-tions explored retroactive sharing of exploration cost and the sharing of gasfield development cost and risk. With future Union Oil gas likely to claimfull existing transmission capacity, temporary limitations on Thailand'sabsorptive capacity for gas48/ and still unresolved questions about the vol-ume of economically recoverable reserves, a near-term break-through on TexasPacific gas does not appear to be in the offing, although it is difficult tomake a firm assessment at this time.

41. The on-the-whole slow and in part unsuccessful gas contrac- negoti-ations were a source of frustration for all parties to the Gulf gas develop-ment. The Bank influenced the timing, if not content, of the first gas con-tract by linking it with project financing under Loan 1773-TH, but did notappear to exercise the same influence over the second (Union Oil) contractand particularly the negotiations with Texas Pacific.49/ Bank staff haveadvised OED that they attempted, on various occasions, to accelerate the paceand shape the outcome of the negotiations held after 1978, though the Bankwas not a direct party to them. The Bank's role in these negotiations is notentirely clear from the documents available to the audit. Governmentofficials, in comments to the audit mission, expressed confidence in the

46/ As noted above (PPAM, para. 23), the certified proven reserves were 1.1tcf. This certification which was a condition of effectiveness for theUnion Oil-PTT contract and cleared the way for Loan 1773-TH, was laterrevised, first upwards and thereafter downwards.

47/ Observers are now puzzled that Union Oil was agreeable to signing thesecond contract in the face of developing production problems under thefirst contract.

48/ Thailand is agreeable to accepting Union Oil's proposed increased pro-duction over current levels only after having made arrangements for saleof the surplus fuel oil, a result of the present refinery configuration.

49/ Bank staff state that they did, however, influence the second Union Oilcontract and the negotiations with Texas Pacific although, of course,there is still no Texas Pacific contract.

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Government's own handling of the co.L.act negotiations. In any case, theGovernment has quickly asserted itself as its own independent decision makerin natural gas development.50/

VII. PROJECT ECONOMICS

42. From the outset, the project was expected to be immensely profit-able for the country, and serious risks to the economic viability were per-ceived as fairly minor. The economic rate of return (ERR) on (public sector)investments, calculated in the SAR, was in the neighborhood of 50%, which notonly by itself but in relation to the level of investment (US$514 millionprojected) was an extraordinarily high figure. Public sector returns of thisorder are uncommon for even low levels of investments.

43. The principal parameters, from which the ERR was derived, were thegas production volumes, the economic value of gas,51/ the investmentcost5Z/ and the net gas supply cost (the well-head cost net of income taxes,royalties and gas condensate). Gas production, as noted above, has fallenshort of projections for the first three years, but can now be expected to beon target. The economic value of gas and the (net) supply cost were appar-ently5 3/ underestimated, as established by the Energy Pricing Study, which

50/ The Government obtained professional guidance in negotiating tacticsfrom consultants financed under this project. A study of gae purchasingstrategies by the Government was also included in Loan 2184-TH. Thisstudy has made no progress yet and is reported as pending. SupervisionReport, Loan 2184-TH, January 9, 1984. The Government is aware of crit-ical comments made in the international press about the time taken forreaching agreements with IOCs. Based on expe-ience gained, Governmentofficials are confident that the time needed in future negotiations willbe less than in the earlier ones and that the international communitywill understand the circumstances under which the past events unfolded.

51/ The economic value of gas was the cost of alternative energy supply.

52/ Pipeline system operating costs are relatively small in the overall costequation.

53/ The PCR provides information on the value of gas and the supply costonly in current terms, without information on the implicit rates ofprice inflation in the SAR estimates and PCR reestimates respectively,thus obscuring a comparison between SAR and PCR in constant terms.

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recalculated (for 1983 in 1983 prices) these parameters.54/ Gas was under-valued even though the value of gas was, incorrectly in the audit's views,equated with the full opportunity costs of imported fuel oil (an energyalternative to gas), rather than with the lower opportunity cost of a mix offuel oil and lignite.55/ The investment costs were, as also noted earlier,overestimated. On balance, the overall structure of benefits and cost, asprojected in the SAR, has remained fairly undisturbed by the parameters'changes.56 /

44. Primarily because of slow initial gas production, economic benefitsare so far lagging far behind the SAR projections. The project's economicimpact is therefore still weak, and the foreign exchange savings have so farbeen modest. In the long run, over the life of the investments and the gasreserves, the audit expects the economic return to be about 45-50%57/ which

54/ The SAR, for example, estimated the economic value of gas for 1983, in1983 prices, at US$4.OO/MMBTU; the well-head cost at US$1.60/MMBTU; thenet supply cost at US$1.00/MMBTU; and the margin of economic value overthe supply cost, accordingly, at USS3.OO/MMBTU. All these values wererecalculated in the Energy Pricing Study, which estimates the economicvalue of gas for the same reference years at USS5.00/MMBTU, if derivedfrom the fuel oil comparator, and USS4.OO/MMBTU, if derived from thelignite comparator; the net supply cost, at USS1.70/MMBTU (for Union Oilgas); and the margin of economic value over the supply cost, accord-ingly, at between USS3.30/MMBTU (based on fuel oil comparator) andUSS2.30/MMBTU (based on lignite comparator), with a mid-point ofUSS2.80/MMBTU. In contrast to the Energy Pricing Study, the PCR inpara. 5.02 quotes the economic value of gas in current terms. The eco-nomic value of gas was calculated as the "net-back' of gas in the speci-fied applications (substitution for fuel oil or lignite, respectively).The net-back of gas is the value (or cost) of gas for which a gas-basedenergy supply has the same cost and energy output characteristics as thefuel oil or lignite-based supply. The study's net supply costs areactually net of the cost of tthc pipeline system. The quoted US$1.70/MMBTU are, therefore, a conservative estimate of the net supply cost.

55/ On the assumptions that thie gas produced would (i) be used primarily inthe power sector and (ii) substitute exclusively for fuel oil, theappraisal equated the value of gas with the opportunity cost of importedfuel oil. While the first assumption was fully valid, the second wasvalid only in part: without expected access to gas, EGAT might haveaccelerated the shift to lower-priced fuels (in particular lignite andimported coal), rather than to remain strongly exposed to internationaloil markets.

56/ Under- and over-estimates partly cancelled each other.

57/ Gas production assumptions: actual gas production 1982-84; 500 MMCFDthroughout 1985-2000. The assumptions in the PCR (para. 5.02) are, insome years, slightly below the audit's assumptions.

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is the range set by the PCR (about 45%) and the appraisal (about 50%).58/Sensitivity analyses show that the rates of return would remain high under avariety of unfavorable project assumptions and that only lasting catastrophicevents (such as lengthy interruptions of gas transmission) could seriouslyjeopardize them. The ERR, for example, would not fall below 40%, if the peakpipeline throughput was only 300 MMCFD (rather than 500 MMCFD), and ifthroughput was discontinued by the mid-nineties, falling from an assumedceiling of as low as 300 MMCFD in 1990.59/ Further, the ERR would not fallbelow 20Z, if the net gas supply cost (through an increase in gas purchasecost, for example) was as much as doubled, or not below 30%, if ligniteexclusively was the relevant gas comparator.

45. The project's economic viability is reportedly in sharp contrast tothe financial rates of return (FRR) currently expected on the IOCs' invest-ments. No return has yet materialized for Texas Pacific, and the long-termfinancial rate of return for Union Oil, according to its own projections,supposedly will not even reach 15%60/: this return is to a large measuregoverned by the cost of developing th_e gas reserves, which are substantiallyabove the level anticipated when the first and second gas contracts werenegotiated.61 / Total Union Oil investments for the first and second con-

58/ Streams of economic benefits and costs, on which economic returns arecalculated, should be given in project documents in constant terms withan explicit statement of the base year, to conform to normal practice.In case of the project under audit, both the SAR and PCR give thestreams in current terms only. Constant (monetary) values should begiven irrespective of whether there are also reasons to present currentvalues.

59/ Such a low throughput would only be conceivable if the Union Oil firstand second contract fields were less productive than currently expectedand no third Union Oil contract materialized and negotiations for TexasPacific gas failed. Such a combination of events is most unlikely.Evacuation of Gulf gai to Surat Thani in the South to feed an EGAT powerstation is also under consideration, but only if there is ample supplyof Gulf gas. The Surat Thani pipeline, which EGAT would be prepared tofinance, would only be dimensioned at 120 MMCFD and thus, in any case,not carry more than one-fourth of the Erawan pipeline's design capacity.

60/ The method of calculating the financial rate of return could not bereviewed by the audit. According to Bank staff, Union Oil's financialrate of return expected in 1978 was "embarrassingly high", even thoughthe company kept its project economics -secret". The recalculatedreturn was released shortly before the opening of discussions on thethird Union Oil contract. All this does not alter the fact that UnionOil states that the return, as projected at present, is unsatisfactory.

61/ The issue of retention of funds payable by PTT, brought ahout by UnionOil's inability to deliver agreed volumes of gas, has recently beenresolved (PCR, paras. 3.07 and 7.02).

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tract fields may reach some US$1.5 billion over the life of the reserves62/as compared to some US$420 million of investment expenditures for the gasdelivery system financed by the public sector.63/ The company states thatthe financial results are unsatisfactory, and it contends that they are dis-proportionate to its risks and expected country-economic benefits and poten-tially harmful to the country objective of energy independence.

46. Given the comfortably high ERRs under even pessimistic projectassumptions, safeguards against non-viability were never much of an issue.The more pertinent issue was, whether the project would be designed andmanaged to fully use its economic potential. In the narrow sense of theinvestment analysis, Thailand appears to have been very successful. UnionOil gas from the first and second contracts is projected to fully use pipe-line capacity for years to come, and the gas transaction price, negotiatedbefore the full extent of development cost became apparent, is low. In asectoral sense, which is not fully captured by the project's economic analy-sis, the question is, whether the project's maximization of benefits is inthe country's long-term interests. Perceptions of inadequate and unfairlylow financial returns could dampen private sector interest in Thai gas ven-tures. The Bank, apparently, has kept a low profile on the issue.64 /However, IOCs' rewards are an issue which should receive close Bank as well

62/ Based on information provided by Union Oil. By end 1984, over one-halfof this amount may have been spent. As the first and second contractfields will not be sufficient to feed the pipeline continuously tocapacity, total private sector investments related to the project mayultimately exceed US$2 billion. According to Government sources, UnionOil may have invested already USS1.3 billion to date.

63/ Including the ADB-financed pipeline (PPAM, para. 28), public sectorinvestments would be about US$555 million. Public sector downstreaminvestments, such as LPG plants, raise of course substantially thepublic sector's financial commitments related to gas.

64/ The PCR (para. 3.10), In reference to Union Oil, calls the project acommercial success. The audit was informed by officials of the companythat Union Oil does not agree with such a conclusion.

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as Government attention in their mutual efforts to enlist private sectorassistance for gas exploration and development.65 /

47. The audit has noted the dichotomy in project control arrangementsfor containing project cost and ensuring the generation of project benefits.Project costs were the subject of rigorous and proven management techniques.The infrastructure design, construction and procurement were entrusted tointernationally experienced firms, consistent with Bank guidelines to promoteefficiency, and the Bank monitored the adequacy of implementation arrange-ments. Completion on schedule was made imperative through the take-or-payprovision (though one could argue that PTT was put into a very tightposition). In contrast, provisions for generating and sustaining benefitswere neither as rigid nor as comprehensive. The project did not set condi-tions clearly designed to produce new field development agreements, nor didit monitor progress by defined milestones to ensure that gas would be pro-duced when and in the quantities needed.66 / Only the gas supply contractfor Erawan became an integral part of the project, but not the cont:-act forTexas Pacific, for which nonetheless in the economic analysis benefits were

65/ Bank staff state that nowadays, Bank attention is being given to IOC'srewards, including in the Bank's (still ongoing) Energy Assessment forThailand, and that the issue of IOC rewards was the subject of projectsupervision missions and new project preparation missions. In the con-text of the project under review, the audit could not clarify in whatway the Bank dealt with this project in the past and how Bank concernwith the issue of the IOC rewards was documented.--According to Govern-ment sources,, a reexamination of laws and regulations pertaining toexploration and development of hydrocarbons is underway to ensure thatthey are fair and realistic in the current environment and provideincentives to investors consistent with national interests. Particularattention is being given to established pricing policies, whose absenceto date, in its judgment, has slowed negotiations with several oil orgas companies with interests in Thailand.

66/ Bank staff report that the Government refused the concept of definedmilestones on the grounds that the Petroleum Law made informationabout field development secret. The audit notes that not all elementsof an IOC's field development plans may be subject to the secrecy provi-sion of the Thai Petroleum Law and that in important cases of otherGovernment-Bank lending agreements, amendments to laws by the legisla-ture have been made. The audit mission in 1984 had no difficultyobtaining thorough briefings by Union Oil about details of its futurefield development plans.

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calculated.67/ The reliance on -self-generating benefits seems to bepaying off under this project, after some initial struggle, but may not beappropriate for similar future operations.

VIII. GAS PRICING AND PROJECT BENEFICIARIES

48. Pricing of gas under the PTT-EGAT sales contract and, implicitly,designation of project beneficiaries were important project issues. Whiletaxes and royalties payable by the oil companies, because of the modes ofpayment, would directly accrue to the treasury, most benefits would be chan-neled to or through PTT and EGAT. Making gas available to EGAT at a pricebelow that of the chosen fuel comparator (fuel oil), would make the powersector a project beneficiary. Making gas available to EGAT at a price equalto the comparator would make PTT the sole beneficiary until the treasurywould claim its share of the gas revenues.68 /

49. To promote energy efficiency, ensure financial soundness of theborrower (PTT) and generate Government revenues, the Bank, during projectpreparation and negotiations, argued forcefully for closely linking the PTT-EGAT gas transfer price to the chosen comparator (fuel oil). Showing for itspart little enthusiasm for a new fuel whose financial cost would be about ashigh as those of the alternative (supposedly fuel oil), EGAT aimed at a gastransfer price which was noticeably below the price of the (fuel oil) compar-ator. At project negotiations, the Thai delegation reported69/ that PTT andEGAT had reached agreement- on a (1978) gas price, which was about 90% ofthe (1978) price of fuel oil, and it agreed to propose to the Government thesame pricing formula in future PTT-EGAT transactions. The delegation arguedthat the gas price should provide a modest incentive to use gas rather thanfuel oil by setting the gas price slightly below the world fuel oil orice.The calculation of the gas price requires several possibly contentious

67/ According to the SAR (para. 3.10), the project's net present value (at10% discount rate, 1978 base year) was US$1,800-1,900 million, if allprojected Union Oil (Erawan) and Texas Pacific gas was taken intoaccount; and US$1,250 million, if Texas Pacific gas was excluded.Accordingly, the production agreement for Erawan gas protected anestimated two-thirds of the project's total net present value(US$1,800-1,900 million). Of course, there was the subsequent shortfallin Erawan gas, which will substantially reduce that field's actualcontribution to the net present value. Because contract negotiationswent slowly, Texas Pacific was delinked from the project after theDecision Meeting: project processing was not supposed to be held upuntil a gas production agreement had been reached.

68/ It was understood that the treasury would, in due time, claim part ofthe benefits after they had accrued to PTT.

69/ Minutes of Understanding, para. 9.

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assumptions such as the uses to which each fuel will be put, the cost of con-version from one fuel to the other and the desired level of fuel security.The undertaking of the Thai delegation satisfied the Bank which prematurelyconcluded in the President's Report, that the PTT-EGAT sales agreement wouldset the gas price at a level close to 90X of the international fuelprices.70! Nonetheless, to safeguard the conclusion, negotiation of alegally binding PTT-EGAT contract (satisfactory to the Bank) was made a con-dition of loan effectiveness.

50. Negotiations between PTT and EGAT were protracted primarily becauseof the issue of the fuel oil price parity and resulted in delayed loan effec-tiveness and interim financing of project investme.rrs at high cost71 /.Ironically, the PTT-EGAT gas sales contract, which was finally signed inearly 1981, made no explicit reference to the 90% fuel oil parity but con-tained indirect linkage with international (Singapore) fuel oil. The Bankraised no objections to the contract terms and implicitly sanctioned theabsence of the parity clause stipulated earlier. Under the Liquified Petro-leum Gas Project (1982), this time being fully consistent with its mostrecent stance, the Bank agreed to a provision, under which natural gas was tobe priced substantially in accordance with the 1981 PTT-EGAT contract. Theissue of a numerically specific parity was not revived again under the twoSALs (1982 and 1983), though both operations, in non-committing language,reiterated the need for appropriate energy pricing to promote energy conser-vation and mobilize resources.

51. The actual fuel oil parity of gas in 1981 and 1982 has not beenreported. Indications are, it could have been 80% or below. In 1983, it wasabout 732. In 1984, it may have been about the same.72 / Bank staff explainthat the issue of a close fuel oil-gas price parity has not faded, as itseemingly has, but was somewhat kept in abeyance pending the outcome of afollow-up study to the Energy Pricing Study. The follow-up study, now nearcompletion, reviewed the appropriateness of a specific pricing parity and is

70/ President's Report, para. 61. The report incorrectly stated as a "fact"that features such as a periodic price adjustment provision to ensurethat the price of gas to EGAT is maintained at a level close to 90Z ofthe international fuel price-, -are incorporated into the PTT-EGATsales agreement.--The 90% (rather than a 100%) parity was explained withreference to the 90% parity of 1978, which apparently took account ofEGAT's costs of converting power plants to gas (Minutes of Under-standing, para. 9).

71/ PCR, paras. 3.15 and 8.03. (The delay in effectiveness and disbursementwas 12 months and not 15 months, as suggested in the PCR.)

72/ According to the PCR, Annex 4 and the Supervision Report for Loan 2184-TH, January 9, 1984, Annex 7, the 1983 PTT-EGAT transfer price was 1983-US$3.65/MMBTU. According to the Energy Pricing Study, the comparablefuel oil price could have been close to US$5.00/MMBTU (PPAM, footnote54).

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reported as reconfirming the need, for years to come, for pricing EGAT gas atthe full opportunity cost of fuel oil. Despite falling short on the statedpricing parity objective, Bank staff express satisfaction at the gas pricinglevels actually achieved so far, as the levels attained could have been evenlower. In their view, even though the Bank had firm grounds for aiming at a90% parity, there was merit in restudying the issue in light of more recentdevelopments. The audit has the impression that the Bank's position on gaspricing was ambiguous, and the audit has not found the basis for such aposture. A well-reasoned, clear and consistent position would enhance theeffectiveness of the Government-Bank energy policy dialogue.73/

52. While the project set out to minimize potential financial benefitsto EGAT (and electricity users), it was designed to make PTT's Office ofNatural Gas (ONG), if not PTT itself, within a short time financially power-ful. Matching the enormously high economic return on the public sectorinvestment, ONG's rates of return on net fixed revalued assets were projectedto rise from 9% in 1982 to 152 in 1984, 24% in 1990, 43% in 1995 and 187% in2000.74/ Cash balances would develop in a similar fashion. ONG/PTT's finan-cial fortunes were even more remarkable, as the project contained no specificprovision for transforming ONG revenues into treasury revenues. Rates ofreturn and cash balances, as projected in the SAR, are for Thai state enter-prises extraordinarily high and unheard of, and they were even greatly under-stated.751 In particular when providing essential public services (power,water and transport), such enterprises are subject to tight Governmentcontrols, and the companies are frequently under a profit and financingsqueeze. Several incur chronic losses. While the objective of ONG's finan-cial prosperity may have seemed desirable to assure its financial health tosafeguard financing of future natural gas investments and to avoid the

73/ Bank staff now emphasize that the actual PTT-EGAT gas price, in theirview, will not fall below 70% of the equivalent fuel oil price, based ontheir reading of the PTT-EGAT pricing agreement. Assuming this readingis correct, the question remains, of course, about the justification forclaiming an agreed 90% parity in the President's Report. Bank staffalso informed the audit that in the Government's view, the Bank shouldnot have insisted at all on the 90Z parity, which to the Government was* counter-produictive".

74/ SAR, Annex 5.03.

75/ Even though Loan 1773-TH highlighted a 90% gas-fuel oil parity, whichwas supposedly agreed at negotiations (PPAM, para. 49), the financialanalyses for ONG were based on a constant 67% parity throughout1982-2000 (SAR, Annex 3.02, Annex 5.02 and para. 3.07). The choice ofthe 67% parity was unexplained. If the 90% parity had been incorporatedinto the SAR's financial analysis, ONG's rates of return on assets andcash balances would have by far exceeded the already very high resultsactually projected. Also, the (real as opposed to nominal) financialrate of return for ONG would have been well above the 15% given in theSAR (para. 5.04).

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chronic financial problems of other public sector enterprises, it couldpotentially breed excessive investments and inefficient operations, and itwas seemingly inconsistent with the Government's budget situation and thefiscal objective of the PTT-EGAT gas pricing structure. There have been sadinstances of financial problems with public sector hydrocarbon enterprises inseveral other countries. An explicit fiscal instrument for genaerating trea-sury revenues, rather than reliance on future ad-hoc fiscal arrangements,could have been a desirable project feature.76 / Primarily on account ofinitially poor gas production, the arrival of ONG/PTT's financial prosperityhas been delayed by several years, and little concern about a financiallyexcessively endowed ONG/PTT is justified at present. On the contrary, PTTcurrentl5 faces a situation of tight liquidity and unsatisfactory profit-ability. 7/

761 Bank staff advised the audit that the issue of transfer of funds wasaddressed in the Liquified Petroleum Project (Loan 2184-TH). Bank staffare of the opinion that no special fiscal provision was needed underLoan 1773-TH because the PTT Act requires that all [PTTJ profits betransferred to the Thai Treasury-. Technically, Bank staff appear to beincorrect as the PTT Act of B.E. 2521 (A.D. 1978, published in theGovernment Gazette, Volume 95, Part 152, dated December 28, 1978),refers only to that PTT revenue balance as being payable as -Staterevenue-, which remains after deduction for operating expenses andvarious commitments as appropriate, e.g., ...reserve funds... andinvestments...". The creation and use of reserve funds are subject tothe approval of the fIT Board of Directors. The PTT investment budgetrequires approval by the Council of Ministers. What this means, inpractice, is, for example, illustrated in the Office of the AuditorGeneral's Report on the Petroleum Authority of Thailand as of September30, 1983. In that report, the FY83 net profits of PTT were given asabout Baht 1,066 million, while revenues transferred to the treasurywere about B107 million. It would, however, be correct to say that theGovernment, through the PTT Board of Directors (consisting of high-ranking Government officials) and the Council of Ministers exercisescontrol over the utilization of PTT net profits. In this light, thepractical question of importance therefore would be, whether the consid-erations of fiscal revenues and financial discipline are better servedthrough the initial transfer of all or substantial parts of net profitsto the treasury, followed subsequently by suitable arrangements forfinancing future PTT activities, or through initial retention by PTT ofthose parts of the net profits deemed necessary for PTT and the subse-quent, if any, payments of residual funds to the treasury as 'Staterevenues-.

77/ PCR, Chapter VII and Supervision Reports for Loans 1773-TH and 2184-TH.

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IX. CONCLUSIONS

53. The project was conceived as a major building block in the strategyto shore up the economy against harmful developments in the international oilmarkets. It basically had a two-pronged approach. Its main strategic com-ponent was the substitution of external energy supplies (oil) through domes-tic supplies (gas); and the other component was containment of growth in(domestic) demand for energy (electricity) through linking domestic gas tointernational oil prices. The project further served as a vehicle for devel-oping institutional expertise in natural gas (through PTT staff training) andrationalizing various sector policies.

54. The projqct estimates of specific gas production volumes have notyet been achieved. However, natural gas from the Gulf is now on the thres-hold of living up to expectations, and in combination with other indigenousenergy supplies (lignite and on-shore gas) and demand-based policies, hasmoved the country close to a manageable energy-import dependence.78! Insti-tutional expertise in gas has been broadened, to some extent, through theproject's formal training programs, and presumably to an even greater extentthrough the sheer exposure to the project and follow-up operations. Energysector policies were also developed under the project, or where the projectleft off, through substitute arrangements.

55. Experience under the project emphasizes the long lead time inrestructuring energy supplies and the need to take long-term energy perspec-tives. Gulf gas exploration, preceding the project, spanned over a period ofsome ten years, and project preparation and implementation, which by anystandard were speedy, took some additional four to, five years. A further twoto three years will have passed until gas production has become significant.Responding to a potential economic emergency taking shape in the late seven-ties, the project was only feasible because of the gas exploration, which wasinitiated well before the 1973/74 oil events forced a rethinking of energypolicies.

56. The project was built on a marriage of public and private sectorinterests. The public sector's main contributions to the production of gaswere the fiscal and regulatory frameworks for gas exploration and develop-ment, the transmission system and market outlets for gas. The private sectorcommitted its technological know-how and it will, on current projections,subscribe to the bulk (about four-fifths) of the long-term capital require-ments for on-shore delivery of gas, which could ultimately reach some US$2.5billion. The scope of the Government's financial commitment under the pro-ject, in conjunction with downstream investments (such as LPG plants), was inearlier Bank discussions viewed with concern because of other sectors' justi-fied claims on the country's scarce financial resources. However, it wasrationalized in light of the IOCs' reluctance to increase their exposure.

78/ The Bank's ongoing Energy Assessment is expected to provide quantitativeenergy supply-demand scenarios.

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The argument has also been made that Government ownership of the transmissionsystem would enhance the Government's negotiating position with the IOCs. Atthe Government's option, the system would, in principle, be available for gasfrom any field, which may not be the case if individual IOCs controlled it.

57. The project has confirmed the general wisdom that development ofindigenous natural gas can be economically most rewarding. The potential foreconomic gain is, of course, in particular high, if gas, as it was here thecase, is to replace high-priced oil products. Despite possible snags, someof which have occurred, it would have been difficult to end up with an unfea-sible project, technically defined as a project with a rate of return belowthe opportunity cost of capital.

58. Given the project's low propensity for economic failure, thechallenge was rather to fully use its economic potential. Considering theproject context only, the project appears to perform very well: gas produc-tion, after initial shortfalls, is likely to use up existing transmissioncapacity, and the gas well-head cost under existing contracts are favorableto Thailand. In the broader context of Thailand's oil and gas sector, theconclusion is less obvious. Union Oil, the project's only gas producer atpresent, argues that its investments may end up relatively unrewarding, andthis could dampen the private oil and gas sector's interest in Thailand.PTT, though gearing up for acquiring expertise in gas exploration and devel-opment, is far from stepping into the IOCs' shoes. Capital for explorationand field development could be costly, if not unavailable, if mobilized bythe public sector.

59. After a 20 years' focus on electric power, the Bank, with thisproject, broadened its involvement in Thailand's energy sector. Bank financ-Ing, by providing informal cover against non-commercial risks, helped set thestage for private sector funding of gas development, it provided the back-ground for the Bank's operational assistance to the Government, and it openednew doors for Government-Bank dialogue on energy policies. The Bank alsoestablished good relations with Union Oil, a necessary condition for aneffective Bank-private sector cooperation in Thai energy development. Wheth-er the full scope of Bank financing, US$107 million, was needed to accomplishall this, is debatable. Operational assistance was fruitful in the contextof implementation of the physical infrastructure. Well established proce-dures for implementing large civil works proved effective in controlling costand meeting a tight schedule. Operational assistance in sizing up gasreserves was not fully effective. On this experience, the Bank may wish toreview procedures for designing and evaluating reserve assessments. Fore-casting for gas production could also be improved and sustained generation ofproject benefits could be enhanced, under new lending operations, throughincreased attention to gas production agreements. Conditions bearing on pro-duction agreements could be reviewed in more depth at appraisal, if notshaped under the project. A related issue is the framework of public andprivate sector relations. Here, the Bank could more explicitly define a pro-ject's function and the role the Bank intends to play. A number of lessonshas also been learned from the project about improvements in presenting

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information in project documents. A main lesson, now being recognized incurrent Bank practice, is to routinely discuss project objectives in the SARand the President's Report. In its campaign for economically correct energyprices, the Bank succumbed to the exigencies of project implementation. Lessambiguity in the Bank's position could make a Government-Bank policy dialoguemore effective.

ATTACHMENT- 31 -

COMMENTS FROM THE GOVERNMEZCZC DIST 0886 RCA 4006OEDODREF: TCP FCA

01341 03-11 1047A ESTTLX 71248423 248423 WORLDBANKBT

1-107065G070 03/11/85ICS IPMIIHA IISS

PMS WASHINGTON DCWUB6071 TUR062 DSX249 TNX 055 BKTN200126

OFFICE OF THE PRIME MINISTER 48/44 11 1430

MR. YUKINORI WATANABEDIRECTOR, OPERATIONS EVALUATION DEPARTMENT, THE WORLD BANK,1818 H STREET N.W. WASHINGTON 20433 U.S.A.

WE FOUND YOUR PROJECT PERFORMANCE AUDIT REPORT ON THAILAND

SECOND NATURAL GAS DEVELOPMENT PROJECT (LOAN 1773-TH)

SATISFACTORY AND HAVE NO FURTHER COMMENTS.

PHISIT PAKKASEMCOL 1818 20433 1773

,I-'

1l

U4

~Aj

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PROJECT COMPLETION REPORT


I. Introduction

1.01 The rise in crude oil prices in 1973 prompted the Government ofThailand to stimulate petroleum exploration, particularly in the offshoreareas. During 1975-76, two important natural gas discoveries resulted, bothin the Gulf of Thailand. Union Oil Company found gas in what was then knownas the "A" structure (now called the Erawan Gas Field), located in the centralportion of the Gulf about 425 km south of the mainland. About the same time,Texas Pacific Oil Company struck gas, 170 km southeast of the Union Oildiscovery in what is called the "B" structure. Both discoveries were believedto have tapped reservoirs of sufficient size to be commercially exploitable,and discussions were begun on marketing the gas. However, seriousnegotiations were, from the very beginning, limited to the Union Oil discoverybecause it was recognized that the initial phase of natural gas development inthe Gulf would inevitably have to be based on the nearest source of supply,the Erawan field.

1.02 The Bank's involvement in Thailand's natural gas sector goes back tomid-1976 when an energy mission visited the country to assess thepossibilities of developing the offshore gas discoveries. It turned out thatthe Government was very interested in Bank assistance for the preparation andfinancing of such a project, and as a result, a close working relationshipdeveloped. Major results of the Bank's involvement were a market andfeasibility study, the hiring of a consultant to assist in gas sales contractnegotiations, and the establishment of a national gas company, the Natural GasOrganization of Thailand (NGOT) in March, 1977.

1.03 By late 1977, it became apparent from enco-araging drilling results inthe Union Oil and Texas Pacific areas that there were commercial-size gasreservoirs in the Gulf. It was also obvious that a project to develop andutilize the gas was a matter of urgency in view of the country's dependence onimported oil. The Government consequently requested a Bank loan of $4.9million to finance the various preliminary activities essential to thepreparation of a natural gas development project. The engineering loan (S10-TR) was negotiated in February, 1978, but Board presentation was delayed untilJuly 11, 1978 because Union Oil and NGOT did not meet until then a Bankcondition requiring their prior agreement on a sales contract. The loanbecame effective on September 25, 1978 and provided for projoct design andengineering, preliminary implementation services, financial managementadvisors, gas reserves appraisal, consultant services and training. Thisprepared the -day in 1979 for a follow-up loan (Loan 1773-TH) which refinancedthe earlier engineering loan and helped finance the pipeline and otherfacilities needed to transport, treat and market the natural gas from theErawan field. Loan 1773 was approved on December 11, 1979 but did not becomeeffective until March 27, 1981 when the Electricity Generating Authority ofThailand (EGAT) signed a contract to purchase the Erawan gas, a condition ofloan effectiveness. The delay in effectiveness resulted from protractednegotiations over the price EGAT would pay for the gas.

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1.04 This report is based on reports and documents in the Bank's files andon the findings of a Bank mission that visited Thailand in January 1983 and oninformation furnished by the Borrower. It covers the initial engineeringproject (Loan S-10-TH) and the follow-up development project (Loan 1773-TH).

II. Project Preparation and Appraisal

2.01 A condition of the gas sales contract was that a minimum of 1.0trillion (million million) cubic feet (tcf) of proven recoverable reserveswould be established and certified by an independent reservoir evaluationbefore the agreement became operative. This required Union Oil to drill fourmore appraisal wells, in addition to three already drilled and, on this basis,an independent reservoir consultant's estimate of 1.1 tcf of proven and 0.4tcf probable was accepted by both parties as the legal reserves of thefield. Union Oil subsequently drilled an additional two appraisal wells onthe flanks of the Erawan structure; this raised the estimated proven reservesto 1.58 tcf. At the same time Union was drilling and discovering a number ofgas bearing structures which substantially strengthened project confidence.The Erawan gas sales contract allowed both parties 36 months, after acceptanceof the gas reserves estimate, to prepare their respective facilities forproducing, transporting and marketing the gas. However, an earlier date ofSeptember 15, 1981 was subsequently agreed on as the date when gas sales wouldbegin.

2.02 Preparation work on the project proceeded in parallel with furtherappraisal drilling and reservoir evaluation in Erawan and elsewhere, andproject appraisal took place during March, 1979. On July 15, 1979, thePetroleum Authority of Thailand (PTT), established December 28, 1978, tookover NGOT and Its entire staff. This necessitated a post-appraisal and causedBoard presentation to be delayed until December 11, 1979. The project wasdefined to include the following principa. .:omponents:

(a) a 34-inch offshore buried pipeline from Union Oil's productionplatform to landfall, approximately 425 km long;

(b) a 34-inch onshore pipeline from landfall to a terminal a shortdistance inland, and a 28-inch buried pipeline, approximately170km, to the EGAT power stations at Bang Pakong and SouthBangkok;

(c) infrastructure, comprising metering, hydrocarbon dewpointcontrol, communications, supervisory control, telemetry,maintenance and office staff support facilities at the terminaland an operations' center at Chon Burl; and

(d) technical assistance, project management, consultancy, trainingand studies.

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III. Implementation

Background

3.01 PTT was responsible for implementing the project, primarily throughits Office of Natural Gas (ONG). For its engineering consultant PTT appointedone of the major US engineering firms whose assignment included engineering,project and construction management, training and start-up. Because of thesize and complexity of the project and PTT's inexperience, the modus operandifor carrying out the project placed responsibility for initiating andexecuting project implementation activities on the engineering consultant andthe normal client supervisory and approval responsibilities on PTT.

3.02 The gas sales agreement with Union Oil included take or payprovisions which could have amounted to US$500,000 per day if PTT was notprepared to take delivery on the contract date. This made it crucial tocomplete the project in time to allow "running-in" operations to begin bySeptember 1, 1981 and to start contract sales on September 15, 1981. Thecompletion schedule was met but it took great effort to do so. Sufficienttime was allowed in the schedule to complete construction and commissioningat, what was then thought to be, an acceptable pace. However, all the slackin the schedule was eventually lost because of the procurement procedure whichhad resulted in slow decision and approval action by PTT and its board. Itultimately became necessary to resort to crash program tactics to finish theproject on schedule. The fact that the project was completed on time speakswell for all those connected with its implementation, especially theengineering consultant who bore the brunt of the responsibility for expeditingand keeping critical activities on schedule.

3.03 The construction phase proceeded smoothly except for problemsnormally encountered on a project of this nature. Two of the more seriouswere connected with the installation of the pipeline. On the offshoreportion, several leaks were discovered in a section of the pipeline alreadyunderwater, and on the land portion which traverses a rice paddy area,difficulty was experienced in maintaining the pipe at the proper burialdepth. Neither of these problems was sufficiently serious to threaten theproject schedule.

3.04 Union Oil's development program also proceeded according to planduring the installation of offshore structures and drilling operations, butran into serious problems from then on. The first gas delivery started onschedule with 15 weils completed. However, Union Oil soon discovered thatseveral wells were showing unusually steep pressure declines and could notmaintain the required flow rates. The situation became further exacerbated bythe failure of the dual completion packers due to higher bottom holetemperatures than had been anticipated. Despite the replacement of thepackers with ones suitable for the temperature and other efforts to increaseproduction, the rate for FY82 only averaged about 120 MMCFD. According to thesales contract, the daily contract quantity (DCQ) should have been increasedto 250 MMCFD in July 1982. However, the contract stipulates that Union Oil'sgas delivery obligation is limited to 1/6,000 of the field's recoverablereserves, and it was on this point that Union Oil based its claim that the DCQagreed to in the sales contract could not be sustained.

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Gas Reserves and Deliveries

3.05 Development drilling and three dimensional seismic data accumulatedsince the reserves evaluation suggest that the original estimate 1 ight beoverly optimistic. The fault blocks appear to be more numerous - thanexpected and there is evidence that the producing zone consists of manydifferent reservoirs separated by water bearing strata. Individual sandsappear to have different gas/water contacts with many lateraldiscontinuities. Union oil, on June 1, 1982, submitted a report to PTTdowngrading the remaining proven and probable reserves of Erawan to 0.489 and0.197 tcf, respectively, with a corresponding reduction in DCQ to 82-114MMCFD. On the other hand, an independent reservoir study on behalf of PTT inAugust 1982 estimated remaining proven reserves at 1.353 tcf with anequivalent DCQ of 225 MMCFD.

3.06 In view of the conflicting reserve estimates, and in accordance withthe gas purchase agreement, PTT and Union Oil commissioned the consultant whoestablished the original legal reserves to carry out a reevaluation based onall data existing on December 31, 1982. The results were reported on July 15,1983 and showed the following reserve estimates:

Dan Reserves a/as of Deeer 31, 1982

A. Proved Develped Reserves

ND. of Qmjlative P e UltilmteReseryoirs Pcoducticn Reserves RecDvery

Reserve Deteinatic e thod) Cbs Liqud Gas I;lquid Gs Liquid

Prod. Reservoirs (MateralBalance) 31 21.6 1.2 61.6 2.6 83.2 3.8

Prod. Reseoirs (Rate/Thme) 9 19.0 0.5 16.7 0.9 35.7 1.4Pmd. Reservctrs (Depleted) 55 17.2 0.8 - - 17.2 0.8

Sub-total 95 57.8 2.5 78.3 3.5 136.1 6.0

No-Prod. Reservoirs (Vol.) 1CO - - 127.3 4.8 127.3 4.8

Total Developed 195 57.8 2.5 205.6 8.3 263. 10.8

B. Ikveloped Beserves

48 Icc. @ 7.6 bcf and309,000 Bbls - - 365.0 i4.8 365.0 14.8

Total A + B 57.8 2.5 570.6 23.1 628.4 25.6

a/ Gas measured in billion cu. ft. (bcf) @ 14.7 psia and 60° F;1.0 bef = 0.001 tcf (trilliao cu. ft.) Liquid (Condensate)masured in millions of US Barrels (BhLs).

1/ And consequently containing smaller patches of gas per well.

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These results supported Union Oil's claim that gas reserves and thecorresponding delivery rates should be reduced from the levels originallyagreed to. PTT refused to accept the revised reserves claiming that theevaluation was incomplete because an appropriate analysis was not made of thedevelopment and production costs to Union Oil in determining the maximumreserves which could be recovered at the contract price. Such a detailedeconomic analysis was not carried out. However, the consultants could onlybase the evaluation on data and instructions received from the client, in thiscase PTT and Union Oil jointly. Without specific instructions to dootherwise, the consultant interpreted the data and arrived at the reservesestimate in accordance with standard practices in the industry and Union Oil'sdevelopment program. Given the revised representation of the reservoir'sproduction zones by the 3-D seismic survey and the production history, thedowngrading of the original recoverable reserves appears to be technicallyjustified.

3.07 During the ensuing dispute over reserves and delivery shortfalls, PTTwithheld approximately 20X of the contract price, based on the reduced priceit would have paid for the higher sales volumes it should have beenreceiving. In June, 1984 a settlement was reached and the contract amended toreflect the existing reservoir performance (see para. 7.02 for furtherdetails).

3.08 In the meantime, Union Oil has continued to develop the Erawanfield. By end 1983, 63 wells from 7 platforms were in production, and byearly 1984 the 8th platform was installed for additional drilling. During1983 Union Oil was able to maintain an average production rate of about 140MMCFD of Erawan gas by puttir.g new wells into production and by addingcompression when reservoir pressure decline made free flow impossible.Production has stabilized and should be sustainable for several years untilafter the main supplies from the next contract come on stream.

3.09 The performance of Erawan field raises the question of whether a moreconservative approach should have been taken in evaluating the field'sproduction capacity and economically recoverable reserves. In fact, everymeasure was taken to do so except extended production testing (para. 3.18).

Achievement of Objectives

3.10 PTT achieved its main objective of completing the project in time andwithin the budget, to fulfill its contract commitments, and similarly UnionOil completed the production facilities to deliver the contract gas. Propersteps were taken to minimize risk. The reservoir did not live up toexpectations, and as a result gas supplies from the field had to be scaleddown to about two-thirds of the original goal. Nevertheless, the project hasproved to be a commercial and economic success, even for Union Oil whosedevelopment and production costs greatly exceed original estimates. A secondsales contract was entered into by PTT and Union Oil in May 1982 for the

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supply of 150 MMCFD of gas from five fielda/ in the neighborhood of Erawanwith provisions to increase the supply to 200-300 MMCFD in 1986 and 400 MMCFDin 1987, depending on reservoir performance. A contract amendment was signedin April 1983 advancing production from Baanpot (one of the five neighboringfields). Gas delivery from this field started on October 31, 1983 at the rateof 12 MMCFD and reached 20 MMCFD by end 1983 and is expected to reach 40-50MMCFD, the maximum expected rate, by mid-1984. With the new Union Oilsupplies coming on stream, PTT can expl7t by mid-1985 gas deliveries in therange of the pipeline design capacity__

3.11 At project appraisal it was envisaged that 250 MMCFD of gas would besupplied by Union Oil and 250 MMCFD from the Texas Pacific (TP) field about170 km southeast of Union Oil's central production platform. The Platong andKaphong fields had been established and a number of other discoveries made.It was projeLted at the time that TP gas would be available by late 1983.However, so far TP has been unsuccessful in negotiating a sales contract withPTT, and other attempts to market the gas, such as through a joint venturewith the Government or LNG export ventures, have also met with no success. Atlast report (February 1984) TP was negotiating a gas price with the newlycreated Committee for Negotiations on Petroleum Joint Ventures and Pricingheaded by a minister fr"m the prime minister's office. At the same time, bothparties recognize the cisadvantage of the existing form of contract and areactively considering "n alternative approach suggested by the Bank. Bothsides have given priority to reaching an early conclusion.

Project Costs and Financing

3.12 The project cost is US$423 million ($76 million local and $347million foreign) including interest during construction. Union Oil'sestimated expenditures were about $300 million, but by end 1983 the companyspent an additional US$300 million for platforms, wells and workovers notoriginally anticipated. In addition, Union Oil will have to make asubstantial investment to produce the remaining recoverable reserves fromErawan and to develop the neighboring five fields under contract.

3.13 Annex I compares the appraisal cost estimate with actual costs.There was a substantial underrun of $91 million, about 18% of the original$514 million total estimated cost. The main contributions to the underrunwere made by contracts, freight, taxes and import duties and the unusedcontingency funds, the latter amounting to $64 million (70%) of theunderrun. One of the main causes for the underrun was the fact that the threemajor pipeline contract costs were substantially below estimates as a resultof prevailing market conditions and keen competition for these contracts. Ashare of the underrun can probably also be credited to good project managementand to finishing the project on schedule.

1/ Platong, Pladang, North Pladong, Satun and Baanpot. A sixth field,Kaphong, would be used if a production permit were granted.

2/ Pipeline throughput can be expanded to about 700 MMCFD through theaddition of compressor stations.

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3.14 The cost of project engineering and management services exceeded theestimate by $22 million, about 100l. Unanticipated heavy staffing ofexpatriate manpower to keep the project on schedule accounts for some of theoverrun. In addition, the consultant's fees, although consistent with thosecharged its other clients, were much higher than the Bank expected fromexperience with similar project assignments.

3.15 A summary of the project financing is set out below:

CurrentCurrent Estimate/

Appraisal Estimate Appraisal (%)

IBRD 107 107 100Export Credits 180 125 69Commercial Banks 150 125 83Government 77 51 66Internal Cash - 15

Total 514 423 82

Export credits (U.S., Japan) funded a significantly smaller proportion of theproject costs than the appraisal estimate. In addition to cost underrun, thiswas mainly because the goods and services procured from the U.S. fell short ofexpectations, resulting in reduced drawdown ($41 million) from the U.S.Export-Import Bank which had committed to extend a $75 million crt t for theproject. Delayed effectiveness of IBRD loan and U.S. Export Creditnecessitated bridge financings from commercial banks during the projectconstruction period. Notwithstanding a project cost underrun, the IBRD loanwas fully utilized. This was the result of a reallocation of Bank loan in1981 to cover an additional item, namely pipe coating, in order to helpalleviate PTT's liquidity problem then. ONG's funds flow during the projectconstruction period is further discussed in para. 7.04. The unexpectedcontribution of PTT's internal cash helped to retire the bridge financing inFY82. The Government has not yet paid its equity contribution equivalent tothe import duties and taxes. PTT submitted a formal request for this inJanuary 1984. This issue has been raised by the Bank with the Ministry ofFinance and will be followed up by supervision missions under the LPG project(para. 7.09).

Disbursements

3.16 Annex 2 presents the actual Bank disbursement against the loan alongwith the original disbursement schedule. The 15-month delay in disbursementwas due to late compliance with a condition of effectiveness in the LoanAgreement, namely the conclusion of a satisfactory gas sales agreement betweenPTT and EGAT. Once it started, disbursement closely followed the originalschedule which can be considered to represent a typical profile for this typeof project.

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Use and Performance of Consultants

3.17 PTT and its predecessor, NGOT, made extensive use of consultants inpreparing and implementing the project. All together PTT employed 13different consultants to assist in various aspects of project implementation,training and studies. The project also included provisions for carrying outenergy convervation studies covering such aspects as an energy audit, aninvestment program for energy savings, policies for energy demand managementand future investments in energy conservation, including non-conventionalsources. GOT subsequently arranged other financing for these relatedactivities. At the time of preparing this report the following studies wereeither completed or in progress: ti) an energy audit by the National EnergyAdministration (NEA) and the Asian Development Bank; (ii) an energyconversation (industrial incentives) study by NEA agreed upon under the Bank'sSecond Structural Adjustment Loan; and (iii) a transport energy conservationstudy by the Ministry of Communications. An energy conservation centerfinanced by private industry and also agreed upon under the Bank's SAL was inprogress of being established. The Bank has been following these studies and,except for late execution, finds them satisfactory.

3.18 According to PTT and Bank staff observations all consultantspprformed their assignment in a generally satisfactory manner, but asexplained in para. 3.06, PTT was not entirely satisfied with the reservoirreevaluation it commissioned jointly with Union Oil. The performance ofErawan field raises the question of whether a more conservative approachshould have been taken in evaluating the field's production capacity andeconomically recoverable reserves. In fact, every measure was taken to do soexcept extended production testing. With onshore gas reserves a certainnumber of the wells could have been subjected to an extended production test,but expense normally rules this out for offshore operations. For example, righire and operating expenses at the time of the drilling were probably in the$40,000-60,000 per day range. At $50,000 per day to test six wells (not alarge number considering the size and nature of the field) for 30 days eachwould cost $9 million. In these circumstances reliance had to be placed on awider judgement, namely, such considerations as the fact that: (i) at thetime of appraisal four gas fields had been proven along with some additionaldiscoveries and all of these could be served by the pipeline; (ii) anexperienced oil company was willing to commit over $300 million, (iii) one ofthe most experienced reservoir consultant was engaged for the field evaluationand initial economically recoverable reserves were based on the consultant'sfield development plan and cost; and (iv) all gas users would have dual firingcapability in case there should be a problem with gas supply. Moreover, theproven and probable reserves estimated at the time were about five times thelevel needed to make the project economic.

Procurement and Performance of Contractors

3.19 Project procurement comprised 15 contracts for services and ibrks and28 contracts for the purchase of materials and equipment. Except for normalclaim adjustments on completion of a contract, PTT reports no undue problemswith contractor performance, and none have been observed by Bank staff whohave supervised the project.

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IV. Operating Performance

4.01 PMT reported that all its equipment and facilities were operatingsatisfactorily. An inspection of the project area showed excellenthousekeeping and care of equipment. All project facilities were operatedentirely by PTT personnel who were alert and knowledgeable and gave everyindication of being well trained. As a precautionary measure, PTT appointedtwo firms to assist during the initial operating stages: one to provideassistance with maintenance procedures and preparation of plans for futuremaintenance of the pipeline and the other as s indby assistance in the eventof an operating failure and as a source of practical knowledge to supplementthe experience of PTT's personnel.

4.02 PTT is operating the facilities with a strong emphasis on safety.Entry into operating areas is restricted to authorized persons, and "nosmoking" and "hard-hat" regulations are strictly enforced. There issatisfactory provision for fire detection and fire fighting and personnel aretrained in emergency procedures.

4.03 The only operating problem of any significance occurred in August1982 when a sudden pressure drop developed in the offshore portion of thepipeline as a result of condensate build-up. This condition was due to thefact that at the existing low flow rates the gas had insufficient velocity toentrain and sweep along the condensate forming in the pipeline. Because ofthe large accumulated volume, the pipeline had to be shut down before thecondensate could be removed. Since then, frequent pigging (every three weeks)has allowed continuous operation. As pipeline throughput increases condensateaccumulation will become less and less a problem, particularly since all gassupplies except from Erawan will be required to have a hydrocarbon dewpointsufficiently low to prevent condensation in the pipeline. To ensurecontinuous gas flow at all possible operating conditions, consideration isbeing given to the installation of a back-up slug catcher as part of theLiquefied Petroleum Gas Project (Loan 2184-TH).

V. Economic Performance

Benefit Streams

5.01 Project economics and finance were appraised both on alreadycontracted supplies and assuming reasonably prompt completion of ongoingnegotiations. In addition, the benefits of gas supply from existing contractsonly were considered in order to estimate the intermediate position of theproject return. At the time of project appraisal, the only contract inexistence was gas supply from Union's Erawan field. PTT has since thenconcluded a further contract with Union Oil for gas supply from a group offive other fields. The current estimate of total gas production from existingcontracts with Union exceeds the appraisal estimate. However, most of the gasfrom the additional fields will not come on stream until 1985, one year laterthan assumed at appraisal. Furthermore, the negotiations between PTT andTexas Pacific (TP) for a gas sales contract, already identified at the time ofappraisal, are still incomplete, and the current estimate of gas supply fromTP is seven years behind the appraisal forecast. As a result, currentestimate of gas production falls short of the appraisal estimate for the firstnine years of the pipeline operations (1982-90), but is expected to reach the

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appraisal estimate of 500 MMCFD in 1991. However, the life of Erawan field iscurrently estimated to be shorter than the appraisal estimate. As a result,from 1995 onward, gas supply is expected to be from Union second contract andTP only, and would again fall below the free flow capacity of the pipeling(500 MMCFD). In estimating the value of natural gas in Thailand for thequantities under consideration, fuel oil is the relevant comparator. Whilethe international price of fuel oil was higher than the appraisal forecast inFY82, the price of oil has since fallen and the current estimate of gas valueis lower than anticipated over the period FYs83-88. From FY89 onward, thecurrent estimate of gas value is expected to be higher than the appraisalestimate, reflecting higher real growth of fuel oil prices.

5.02 Comparisons between the appraisal and cYrrent estimates of gasproduction and value are summarized as follows:1.

FY82 FY84 FY86 FY88 FY90 FY92Production (MMCFD)

Appraisal - Main case

Union 200 250 250 250 250 250TP - 150 200 250 250 250

Total 2r00 400 450 500 500 500

Current Estimate

Union 120 200 495 465 385 385TP - - - - - 115

Total 120 200 495 465 385 500

Gas Value ($/MMBTU)(In current terms)

Appraisal 3.8 4.3 5.0 5.7 6.5 7.4Current Estimate 4.3 3.9 4.4 5.6 6.8 8.3

Cost Streams

5.03 Actual project costs of $331 million (excluding taxes and importduties) represents a 21Z underrun against the appraisal estimate of $417million. However, the current estimate of the costs of gas is higher than theappraisal forecast for gas from Erawan; which, to some extent, reflects higherinflation. On the other hand, based on the assumption that TP gas cost is thesame as that of Union second contract, the current estimate of TP gas cost islower than the appraisal estimate. The cost of gas is summarized below.

1/ The gas volumes shown have different calorific (Btu) content for Union andTP. The SAR adjusted to a standard 1,000 Btu/cu ft value.

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(in current terms)FY82 FY84 FY86 FY88 FY90 FY92

Gas Cost ($/MMBTU)

Erawan

Appraisal 1.6 1.8 2.0 2.3 2.6 3.0Current estimate 2.5 2.5 2.5 2.8 3.1 3.4

Second Union Contract

Appraisal - - - - - -

Current estimate - - 2.4 3.0 3.3 3.5

Texas Pacific

Appraisal - 2.1 2.4 2.8 3.2 3.6Current estimate - - - - 3.4 3.5

Economic Rate of Return

5.04 The detailed economic analysis based on gas supply from both UnionOil and Texas Pacific is presented in Annex 3. Comparisons between appraisaland current estimates are sUmmarized below:

Appraisal Current Estimate

Economic rate of return (Z) inreal terms

Union alone 53 44

Union & Texas Pacific 48 44

Net Present Value ($ million)at 10% discount

Union alone 1,250 1,029

Union & Texas Pacific 1.800 1,214

5.05 Notwithstanding a project cost underrun, the current estimates of theeconomic rate of return and the net present value of the project are lowerthan the appraisal forecast. This is mainly because of the lower marginbetween the value and cost of gas, and the benefits foregone by gas supplyshortfall during the initial years of pipeline operations. Nevertheless, thecurrent estimate of the project return remains attractive.

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VI. Institutional Performance

Background

6.01 The Petroleum Authority of Thailand (PTT) is a state enterpriseestablished in December, 1978 to engage in and promote the petroleumbusiness. It is under the jtrrisdiction of the Ministry of Industry. Atpresent, PTT operates as a single legal entity with no subsidiaries. It hasthree major operational units, namely the natural gas operations (ONG), oilmarketing operations (ODS) and refinery.

6.02 Implementation of the project was transferred to PTT when it tookover the Natural Gas Organization of Thailand (NGOT) in July 1979. ONG wasresponsible for the construction of the natural gas pipeline and is nowcharged with its operation. It will also be responsible for implementing andoperating the gas separation plant (Loan 2184-TH). The major part of the oilmarketing operations were transferred from the Oil Fuel Organization (OFO) toPTT in September, 1979, and the balance transferred from the SummitCorporation in early 1981. The Bangchak refinery was formerly leased to theSummit Corporation and taken back by the Government in early 1981. Bangchakis owned and operated by the Ministry of Defense. PTT is responsible for theacquisition of oil, distribution of petroleum products and financialmanagement of the refinery. Bangchak has separate books of accounts and itsfinancial statements are not consolidated with PTT, but the PTT role withBangchak has a significant effect on PTT's financial situation. Under a jointventure agreement for the expansion of TORC refinery, PTT holds 49Z of theshares of the IYJRC refinery. In addition, PTT will hold 25% of the shares ina joint venture agreement with Shell to develop the Sirikit Oilfield.

Organization and Management

6.03 PTT's Board of Directors is appointed by the Council of Ministers.The Board is made up of senior members of the Civil Service and includes achairman and eleven other directors. The Governor of PTT, who is its chiefexecutive officer, is a Director and Secretary of the Board. PTT also has anexecutive committee chaired by a member of the main Board. In view of therapid growth in its activities, PTT underwent a major reorganization in mid-1981. Under the Governor, there are now six Deputy Governors responsible forTechnical and Planning, Natural Gas Operations, Marketing, Logistics andRefining, Finance and Administration, and Special Affairs. In addition, thereare two Assistant Governors in charge of Finance and Refining.

Staffing and Training

6.04 PTT has at present a staff of about 2,700, of which some 400 areunder the Natural Gas Operations. PTT's top management is experienced inbusiness and management but has only limited experience in the petroleumindustry. The middle management is generally young, keen and well educatedbut in many cases with relatively little experience. Under the provisions ofthe project, theoretical and on-the-job training has been given for thenatural gas operations and in accounting and finance. In addition, trainingis planned for the operation of the gas separation plant and LPG distribution,as provided under the LPG project. Apart from specific instances associatedwith new projects, PTT's future needs are practical, on-the-job experiencesrather than making much use of further training courses.

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Management Information System

6.05 During the initial phase of project implementation, there appeared tobe inadequacy in the accounting system at ONG (formerly NGOT) particularlywith respect to documentation of payments. In addition, the accounting systemat ODS (formerly OFO) was weak, especially In regards to accounts receivable,billing and the control system.

6.06 Under the provisions of the project, competent financial consultantswere engaged to assist PTT in the maintenance of its accounts and in internalauditing. Specifically, the consultants assisted ONG to strengthen itsaccounting system, design a management information system as well as abudgetary control system, taking account of the expanding activities ofnatural gas operations. In addition, the consultants assisted ODS tostrengthen its accounting and control system and undertake verification offixed assets at ODS. Furthermore, the necessary staff training was providedwith the assistance of consultants. As a result, there has heen a markedimprovement in PTT's management reporting system. With respect to internalcontrol, the consultants have, until recently undertaken the internal auditingof PTT as an interim step until the company can build up its own staff toperform the task. However, the service of the consultants was discontinued in1983 when PTT decided that it could implement the management reporting systemon its own. Since the internal audit function at PTT has not as yet beenstaffed, internal auditing is no longer undertaken as a part of its internalcontrol. This is not in compliance with the loan condition provided under theLiquefied Petroleum Gas (LPG) project. The issue has been raised with PTTmanagement, which has assured the Bank that is actively seeking suitableconsultants. This will be followed up by future supervision missions for theLPG Project.

VII. Financial Performance

7.01 At the time of appraisal, the imminent transfer of OFO was undecidedand the transfer of Bangchak refinery was even further into the future. Noreview of OFO, as a military establishment, was feasible and for prc-ticalpurposes, the appraisal only took account of ONG's financial forecast.Accordingly, the comparison between appraisal and actual performance has beenlimited to ONG only. ONG's comparative income statements, funds flowstatements and baluLce sheets are presented in Annex 4.

Revenue Position

7.02 As PTT's gas purchase/sales contracts with Union Oil and EGAT providefor a lower price of gas when volume increases, the gas supply shortfall hasled PTT into a dispute with both Union Oil and EGAT regarding the purchase/sales price of gas. During FYs 83 and 84, PTT made payment on about 80% ofUnion Oil's invoiced amount. The dispute over the gas supply shortfall wassettled between Union Oil and PTT in June 1984. According to the agreement onthe settlement, PTT would make cash payment to the concessionaires (Union Oil/Seapec) in the amount of Baht 654 million (US$28 million), representing 40% ofthe disputed amount (US$61.0 million) plus interest. In addition, in order toprovide the concessionaires with an incentive to produce more gas from theErawan field, PTT will provide an "incentive gas price" for all gas volumesproduced in excess of 54,750 MMCF (150 MMCFD) in any contract year. In

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effect, this would mean that instead of four tiers of gas prices which woulddecrease with increased volume under the original contract, the settlementcalls for the price of gas to remain flat after an average of 150 MCFD hasbeen reached. After reaching an agreement with Union Oil on the settlement,PTT has started to negotiate with EGAT on the same issue. The renegotiationbetween PTT and EGAT on the gas sales/purchase contract (which is providedunder the present contract terms) will not start until after an agreement hasbeen reached between the two state enterprises on the gas shortfall dispute.

7.03 Notwithstanding the gas supply shortfall, ONG's operating income inFY82 was in line with the appraisal estimate. For its first year ofoperation, ONG reported income before interest of $46 million, as comparedagainst the appraisal estimate of $42 million. The negative impact of gassupply shortfall was essentially offset by the higher selling price of gas andthe profits from condensate sales which were not known and consequently notincluded in the appraisal estimate. However, ONG's income after interest of$5 million was significantly less than the appraisal estimate of $8 million onaccount of higher than anticipated interest rates which in turn led to higherinterest expense. Nonetheless, ONG's operating ratio of 0.81 which was closeto the appraisal estimate of 0.78. ONG's return on revalued net fixed assetsof 12% was slightly higher than the appraisal forecast of 9% mainly becausethe project cost underrun has resulted in a significantly lower asset basethan anticipated.

7.04 ONG's profitability in FY83 fell considerably below the appraisalforecast mainly because of the marked shortfall (45%) in gas supply.Operating income before interest expense was $51 million as compared againstthe appraisal estimate of $77 million. However,actual interest expense of $28million compared favorably with the appraisal estimate of $48 mil±ionprimarily as a result of the lower financing need. After the inclusion offoreign exchange loss ($8 million), ONG reported net income of $15 million ascompared against the forecasted $29 million in FY83. Its operating ratio of0.83 was considerably higher than expected (0.70), and its return on revaluednet fixed assets was 13% as compared against the appraisal estimate of 15%.

7.05 On a DCF basis, the financial rate of return over the life of theproject is currently estimated to be the same as the appraisal estimate of 15%(in real terms). The adverse impact of gas supply shortfall is offset by theproject cost underrun and higher profit margin than anticipated (Annex 4).

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Funds Flow

7.06 ONG's funds flow over FYs79-83 are summarized as follows:

FYs 79-83 (In US$ million)

Appraisal Z Actual Z

Internal Cash generation 174 26 139 26Loans /a 412 62 358 66Government Contributions 77 12 2 -Other Liabilities - 44 8

Total Sources 663 100 545 100

Capital expenditures 482 73 373 69Debt Service 112 18 136 25Changes in Working Capital 69 9 (34) (6)

Total Uses 663 100 543 100

/a Includes long-term loan and net short-term loan.

7.07 ONG's total financing requirements over the last five years weresubstantially below the appraisal estimate as a result of the cost savings ofthe pipeline project. However, borrowings and other liabilities financed aconsiderably higher proportion of the total requirement than anticipatedmainly due to the marked shortfall in Government contributions to cover taxesand import duties. Nonetheless, ONG's cash flow position was not adverselyaffected since no payment had been made on the taxes. On the other hand,delayed effectiveness of the loans from the World Bank and delayed and reduceddrawdowns from the U.S. Export-Import Bank necessitated the occurrence ofsubstantial short-term bridge financings at prevailing high interest rates inFYs 80 and 81. ONG's debt service in FY82 was significantly higher than theappraisal forecast, reflecting substantially higher interest expense andearlier loan repayment than anticipated. As a result, even though ONG'sinternal cash generation in FY82 was in line with the appraisal estimate, itsdebt service coverage of 1.3 times in the same year fell short of the expected2.0 times. In FY83 ONG's internal cash generation was considerably below theappraisal estimate mainly as a result of the marked shortfall in gas supply.Even though its debt service was slightly below the appraisal forecast, itsdebt service converage of 1.9 times was lower than the expected 2.3 times.

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Financial Position

7.08 The balance sheets of ONG as of 9/30/83 are compared as follows:

(In US$ Million)

Appraisal X Actual %

Net revalued fixed assets 509 86 403 79Current assets 82 14 106 21

Total Assets 591 100 509 100

E.quity 176 30 61 12Long-term debt 402 68 368 72Current liabilities/a 13 2 80 16

Total Liabilities & Equity 591 100 509 100

Current ratio 6.09 1.32Debt/equity ratio 70/30 86/14

/a Includes taxes and import duties payable of $51 million on actual balancesheet

7.09 ONG's current ratio and debt/equity ratio were significantly weakerthan the appraisal estimate mainly as a result of the delayed Governmentcontributions noted above. Had there been no such delay, ONG's current ratiowould have been 3.7 and debt/equity ratio would been decreased to 77/23 by theend of FY83.

Financial Covenants

7.10 In light of the fact that it was impractical to incorporateconventional financial covenants for a consolidated PTT at the time ofappraisal, the company was requested to adopt a statement of corporate andfinancial objectives with the view towards sound financial performance. TheLoan Agreement requires that:

(i) PTT would maintain separate accounts for each of its majoractivities, including ONG;

(ii) no long-term debt would be incurred by O14G without prioragreement by the Bank unless a debt service coverage of 1.2times would be achieved for 1982 through 1985 and 1.5 timesthereafter;

(iii) surplus funds from gas operations would only be applied forother purposes after ensuring sufficient funds for requirementsof ONG;

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(iv) PTT would earn a reasonable rate of return on the capitalinvested;

(v) PTT would ensure sufficient cash flows to each of itsoperational unit to enable it to meet its operating andmaintenance costs and debt service needs;

(vi) PTT would ensure that its internal cash generation could coverits debt service by a margin comparable to that for industrygenerally and cover capital expenditures to the extent they needto be financed from Income; and

(vii) PTT would prepare, on an annual basis, a five year corporateplan including, among others, its investment program, a forecastof its profitability, the projected balance sheets and fundsflow.

7.11 Actual performance of consolidated PTT are summarized in Annex 5.PTT has complied with all of the covenants summarized above. However, whilePTT has compiled with (v) which requires adequate coverage of debt service onlong-term debt, its internal cash generation was insufficient to coverinterest expense on short-term loan in FY81. As noted in Annex 5, PTT'sliquidity position improved significantly in FYs 82 and 83 and debt service onboth long and short term loans were adequately covered. PTT's financialperformance will continue to be monitored closely under the LPG Project nowunder implementation.

7.12 The Guarantee Agreement provides that the Government would make anequity contribution to cover the cost of land and right Lf way as well asimport taxes and duties of the project. As noted above, such contributionsfrom the Government are still pending.

VIII. Performance and Role of the Bank

8.01 From its first involvement in mid-1976 to completion of the SecondGas Development Project, the Bank made significant contributions to thedevelopment of Thailand's natural gas resources and the institutional capacityto deal with this new energy source. The Bank's supportive role wasespecially important in light of the country's inexperience with this newenergy resource; it included such diverse functions as: (i) serving as asource of impartial advice in technical, financial and institutional matters;(ii) expediting the decision making process; (iii) identifying essentialproject and sector studies and technical assistance; and (iv) preparing termsof reference of consultants, and providing guidance in their evaluation. TheBank's efforts were particularly effective in bringing about an earlylaunching of the development project through assistance in setting up anatural gas utility (NGOT), engaging technical and legal advisers in contractnegotiations with the foreign oil companies and undertaking timely preparationand implementation activities critical to the success of a project of thismagnitude and complexity. From an institutional perspective, the Bankrequired and assisted in establishing appropriate technical, financial andoperational training programs. While there is still room for improvement,these programs have provided PTT with a competent staff capable ofindependently carrying on its natural gas operations. Studies and related

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sector work set the stage for the Bank's participation in the third project,the LPG Plant Project approved in June 1982, through which it has continuedIts supportive role.

8.02 The Bank was originally called in by the Government to provideunbiased advice on how to proceed with the gos purchase and the project. Noalternative source of advice acceptable to Thai authorities was identifiedduring the project (i.e., although the Government was satisfied with virtuallyall consultants In relation to specific project tasks, they were not satisfiedthat any of the consultants could give competent and impartial advice on thebroader issues). In light of the above, the question remains as to whetherthe Bank needed to finance 25% of the project cost to achieve the variousobjectives. With benefit of hindsight, we believe the extent of parti-cipation, was appropriate. An important part of the task was to ensure thatthe management decisions were taken in time for the project to be completedfor the commencement of deliveries. Further, to ensure efficient procurementthe Bank had to exert strong influence on procurement decisions a number oftimes during the project. Both of these required a weighty participation, andthe Bank's position as the largest single financier was important for thisrole.

8.03 Relations with PTT (and its predecessor, NGOT) have been goodthroughout the Bank's involvement in these two lending operations. PTTconfirms that complying with Bank requirements on procurement and projectsupervision have not been a source of problems. However, both PTT and theMinistry of Finance are critical of the Bank for making conclusion of a gassales agreement with EGAT a condition of loan effectiveness (para 1.03). Thiscondition of the loan delayed disbursement by 15 months and made it necessaryfor PTT to arrange short term bridge financing for over US$70 million at atime when interest rates were at near all-time-high levels. PTT maintainsthat the condition provided no penalty to EGAT (which caused the delay), andthat it had to suffer a substant'al financial loss through no fault of itsown. The point is a valid one, and from hindsight it appears that a fairerand more effective approach would have been to put a comparable covenant inthe EGAT loan agreement for the Bang Pakong power plant project.

IX. Conclusions

9.01 The project was a success. It was completed on schedule with asubstantial cost underrun, and it constitutes Thailand's first step indeveloping an indigenous energy supply. So far, anticipated gas volumes havenot been realized, but the economic rate of return nevertheless remains veryattractive. Further benefits will follow as additional gas supplies alreadyunder contract are connected to the project facilities.

9.02 Also successful was the Bank's institution building role whichspanned the period from the time when there was not even a natural gasorganization to the present successful operating entity.

9.03 Bank processing of Loan S-10-TH was linked to a gas sales agreementbetween NGOT and Union Oil (para. 1.03). Government officials and othersinvolved in the negotiations felt that this gave a bargaining advantage toUnion Oil. That is to say, Union Oil, by knowing that a Bank loan would notbe forthcoming until a contract was signed, could afford to stall while the

- 51 -

pressure to make concessions was on NGOT. This reasoning overlooks the factthat it would have been a poor bargaining tactic for either party to commitmoney to the enterprise before an agreement was reached. In fact, thecondition was an important factor in concluding the agreement. However, thisdoes demonstrate that care must be taken in setting Bank lending conditions insimilar situations where they may influence ongoing negotiations.

9.04 Although the project remains economically sound, the shortfall in gassupply demonstrates the geological risk associated with all petroleumexploration and development, no matter how favorable the prospects appear.This risk was recognized at appraisal and as discussed in this report foundacceptable because sufficient steps were Laken to mitigate the economicimplications and also because the field's estimated proven and probablereserves were five times the actual quantity required to make the projecteconomic in addition to the sizeable additional gas deposits known to be inthe area. The project demonstrates that a much more comprehensive - andexpensive - appraisal of the field would have been necessary to avoid possiblefinancial and economic loss if there had been only one source of gas.

9.05 There have been suggestions that the take-or-pay conditions of thegas sales contract between PTT and Union Oil are somewhat one-sided in thatPTT is required to compensate Union Oil for contract deliveries (or portionsthereof) it fails to accept, whereas the contract is not fully explicit in thecosts and penalties Union Oil is subject to for not making the contractdeliveries. However, such a conclusion is not valid when full acccunt istaken of how other contractual and legal provisions affected Union Oil andsuch considerations as the fact that:

(a) the risk to PTT was acceptable. PTT helped set the contractdelivery date which allowed ample time to prepare for thedeliveries, and EGAT provided a ready market. The Union Erawangas supply represented only a fraction of the likely demand;

(b) the take-or-pay provision was felt to be the only practicalmeans for ensuring that the PTT facilities could be installed ontime, and it was later demonstrated that th.! many delaysencountered during implementation would not have been overcomewithout this contractual imperative;

(c) Union Oil has already been penalized by the reservoir'sinability to deliver the expected gas production both throughthe initial deduction of 20% of its revenues and through thelower gas volumes. The gas supply contract provides for asubstantial work coumitment by Union toward remedying theproblem, and it will take a larger investment than previouslyanticipated to produce a smaller quantity of gas; and

(d) the gas price finally agreed to by both sides reflected theterms and conditions of the contract. Considering the time andhard bargaining it took to reach an agreement, it can beconcluded that both sides probably got the best deal eithercould expect.

- 5- --.

,,7tZZ$ 'S 0 >: rS3- ;a /Iv,, /14

- 53 -

TUAILAND

SECOND NATURAL GAS DEVELOPMENT PROJECT

COMPARISON OF ESTiMATED AND ACTUAL PROJECT COSTS

APPSAIS*L ESTATM ACTUAL COSrsl.@tal FE Total LoCal P11 Tota 1AOc FE Total Local Pt Total

In 1aht Mllitton In V5S Ijilions - in Raist- itilogo - Tn -dSiTqueno

Laud and Right-of-ay s0 - s0 4.0 4.0 64.' - 64.9 1.1 - 3.1

-catorLAl Nad !Squlpnt

Lis plp' - 1.600 1,800 - 90.0 90.0 - 1.792.0 1.792.0 - 67.5 67.5Cathodic protection - 40 40 - 2.0 2.0 - 23.5 23.5 - 1.1 1.1-nlvw sad f*ttlta - 172 172 - 8.8 8.4 - 67.5 67.5 - 4.2 4.2Da ,v4nt ctntrol - 44 64 - 3.2 1.2 1.8 16. 3 322.1 0.2 19.0 15.2latnratn ctura tOO 192 292 5.0 9.6 14.4 266.8 I30N. 419.7 12.2 *.6 1i1.6Spo Prts - 4 14 - 0.7 0.7 13.2 - 13.2 0.4 - 0.6

Subtotal 1o0 2.282 2.382 5.0 314.1 11t.1 265.8 2.372.2 2,456.0 13.0 114.4 127.4

Coatraet-

ipoe costing 444 680 1,124 22.2 34.0 56.2 - 790.2 790.2 - 31.4 16.4Oftsbore pipe 1eystZ 320 1.400 1.920 14.0 80.0 94.0 - 1.591.? 1,911.2 - N6.7 169.7Osbhore ptpa laylg 240 200 440 12.0 30.0 22.0 - 426.1 424.R - 19.7 19.7

Subtotal 1.004 2.40 3.U44 50.2 124.0 174.2 - 1.106.2 3.103.2 - 147.6 147.3

Otbhr Coeta

Indirect projaet costs 120 s0 170 6.0 2.5 A.5 31.2 - 31.2 1.5 - 1.5NobIlIzatio a"d dr obiliattoa 32 s0 112 1.6 4.0 S.6 - -*reIgbt 58 140 211 2.9 6.0 111.9 - - _ __ __ _TMam and TIort Dutie 1.300 - 1.300 63.0 - 65.0 1.052.0 - 1.052.0 50.9 50.9O0wr. ar 52 - 52 2.4 -- 2.4 37.1 5.4 42.7 1.9 0.3 2.2Start-np expanse 20 AO 40 1.0 2.0 3.0 122.7 - 122.7 5.3 - 3.3

Subtotal 1.582 330 1.912 79.1 16.3 95.6 1.243.0 5.4 1.246.4 5.6 0.3 99.9

Prolet Eenearag muasd"Mamauset Services

Project ninearteg managesent -- 80 s0 -- 4.0 4.0 -Eslanerilg lan - it 96 - 4.9 4.9 - 9 910.1 910.1 4 42.7 42.7Conetractine aupervision 64 156 240 4.2 7.6 12.0 -

Subtotal 64 334 418 4.2 16.7 20.9 9 910.1 910.1 -- 42.7 42.7

Consulting and Tra1inin

Tralatag 6 10 16 0.1 O.S O.R - - - -Adwisota sereces 2 10 12 0.1 0.5 0.6 o.R 7.1 7.9 0.1 0.3 0.4TechniCEl Aastlatanc and Studt-e 2 4U 4U 0.1 2.1 2.4 0.6 16.7 17.1 0.1 n.7 0.6

Subtotal 10 46 76 0.5 1.3 3.0 1.4 23.6 25.2 0.2 1.n 1.7

Total Base Casto 2.860 5.492 6.112 I43.0 274.6 417.6 1.545.1 f.410.0 A 1.15. n 15.9 311. 7 362.1

Fhsitcal Co1tlngenep 290 346 638 14.5 27.4 4*.- -- -- -- -- -Prtce Ccntlagenc 330 120 450 16.5 6.0 22.5

Total Project Costo 3.480 4J160 9,640 174.0 306.0 482.0 1. 35.1 4,419.9 a±fil! S.9e 306.2 362.1

Isterest Durti, Construction

- a'-fle ncd __ 140 140 - 7.0 7.0 - 32.3 32.3 - 1.4 1.4- Other 53 500 - 25.0 23.0 - 647.1 647.1 39-.3 39.3

Total Finalacg tagunired 3.480 *.800 10.280 174.0 ;.0.0 514.0 3,595.1 7.2e.91 O*.p6.4 75.9 346.9 422.2

LU Actual cnta hawe boen adjuted to exclude foreign e bchea lsos of 9IG s11Ims (762 milltos _bctal.

Deceber 1983

- 54 -

ANNEX 2

TRAILAND

Second Natural Can Development ProjectSchedule of Disbursements

(In US$ '000)

IBRD Fiscal Yearand Quarter Appralsal Actual Actual/Appraisal (x)

1979/80

March 31, 1980 4,900 -June 30, 1980 19,000 - -

1980/81

September 30, 1980 38,000 - -December 31, 1981 53,000 - -March 31, 1981 68,000 - -June 30, 1981 83,000 70,910 85

1981/82

September 30, 1981 97,000 83,970 87December 31, 1981 98,000 96,450 98March 31, 1982 99,000 96,450 97June 30, 1982 100,000 96,450 96

1982/83

September 30, 1982 101,000 96,450 95December 31, 1982 103,000 96,450 94March 31, 1983 105,000 96,450 92June 30, 1983 106,000 96,450 91

1983/84

September 30, 1983 107,000 101,500 95December 31, 1983 107,000 107,000 100

Closing Date: 12/31/83

February 1984

THAILAND

SECOND NATURAL GAS DEVELOPYENT PROJECT

ECONOMIC ANALYSIS(In USS Million)

__ar ________ Appi, teal soCurrent EstimatgYear BeuefitsLI Captta1 Co.ts,, Operating Costs-, Net henetits Benefits Capital Costs Operating Costo Net Benefits

1978 -1979 - 5 (1) (4) _ 6 (6)1980 - 202 (35) (167) _ 190 _ (190)1981 - 354 (32) (322) _ 122 - (122)1982 304 48 146 110 259 12 123 1241983 469 7 ISO 312 267 11 150 1061984 714 - 233 481 382 50 IS3 1391985 773 - 323 450 691 48 327 3161986 913 - 319 594 924 102 427 3g5

1987 1113 - 375 738 1033 170 475 3891988 1214 - 417 797 1175 68 537 5701989 1295 _ 446 849 1362 613 7491990 1369 - 478 891 1447 648 7991991 1450 - 512 938 1531 684 8471992 1541 - 548 993 1626 - 739 8881993 1644 - 586 1058 1746 - 797 9491994 1757 - 626 1131 1866 - 856 10141995 1878 - 670 1208 1985 - 457 0i711996 2007 - 717 1290 2129 - 937 11921997 2145 - 767 1378 2272 - 1007 12641998 2291 - 821 1470 2440 - IO2 13581999 2449 - 878 1571 2607 - 1156 15l2000 2613 - 940 1673 2798 - 1230 1568

Economic Rate of return 48X 45t

1/ Includes value of gas, Income taxes and royalties paid by gas suppliers.27 Includes capital expenditures for pipelines and conversion costs of boilers37 Includes gas purchase costs, pipeline operation cots and increase in minimum vorking capital requirements.

- 56 -

ANNEX 4Page 1 of 5

THAILANDSecond Natural Gas Development Project

Natural Gas Operations Finances

For purposes of comparison with the Staff Appraisal Report (SAR), thefollowing adjustments have been made to ONG's actual financial statements:

1. Fixed assets and related depreciation which were reported onhistorical cost basis have been revalued at the same rate (7% p.a.)as that applied in the SAR from 1981 onward;

2. interest during construction which were capitalized have beenadjusted to be written off as an operational expense during the yearof occurrence;

3. current portion of long-term debt which were reported under short-term loan has been reclassified as long-term debt;

4. accrued expenses have been reclassified as accounts payable; and

5. accounts payable to head office have been reclassified as short-termloan.

THAILANDPTT


Income Statements(In US$ Million.-)

For Year Ended September 30 1979 1980 1981 1932 1Q1ApprctrAppralppralmal Actuel ApprInial Actual AppraiNsl Actuel Appraisal Actual Appraisal Actual

Production

Gas (MHCFD) - 200 20.00 2.0 140o0n

Condensate (million bbl) -- -- -- -- -- - - 1.10 - 2.5Natural Gasoline (000 tons) -- -- -- -- -- -- -- 19.10 -134

Prices

Ges ($/HATU) -- -- -- -- -- - 2. 2 3.66 2.70 3. h

Condenoate (S/bbl) -- -- -- - 3.00 - 35.00

Natural Gasoline ($/ton) -- -- -- -- - 242.00 20S.00

Costs

Cam ($/HGBTU) -- -- -- -- -- -- 1.60 2.49 1.57 2.61

Condensate ($/bb) -- -- -- -- -- -- - 33.00 - 30.00

Revenues

Gas - -- -- -- 192.79 182.31 253.20 212.23Condensate - 50.53 -5.90

Natural Casoline - - 4.67 - 7.00

Total Revenues -- -- - - -- - 192.79 233.01 253.20 3"5.13

Expenseee

Gas Coats -- -- -- -- -- 122.12 12nf.47 149.37 i1S.nnCo'dansate Coats -- -- -- -- - - - 44.14 - 74.30

Natural Oabolf7a Costs - -- -- -- -- -- -- 0.32 - n.47D prectatton - -- -- -~- - - - 22.30 2M.33 2A.25 71.A3

Operating & Admin. Costa 2.50 6.S7 2.60 6.34

Total Expens -- -- -- - 10.72 192.33 130.72 254.42

Income Before Interest - -- -- -- - -- 42.07 45.63 77.4 50.71

laterest 3.02 0.20 6.78 2.39 22.42 37.97 34.13 40.84 48.01 27.75

Incone After Interest (3.02) (0.20) (6.76) (2.39) (22.42) (37.97) 7.94 4.79 29.47 22.96

Voreign Ezchange Gain (Lose) -- -- -- -- - - 11.66 - (8.00)

Net lncome (3.02) (0.20) (6.76) (2.39) (22.42) (37.97) 7.94 16.45 29.47 14.6 .

Operating Ratlo - __ __ _ _ _ 0.76 O.l 0.70 0.63

V1 On revalued assets basis.

THAILAND

PTT


Sources & p atlone of Funds

Mf S illions)

For Year Ended September 30 1979 1980 1981 1982 1983Appraisal Actual Appraisal Actual AppraLtel Actual Appraisal Actual Appraisal Actual

Sources

Net Incoge Befora Intereat -- -- 42.n7 45.63 77.48 50.71Adds Depreciation - - 26.10 20.38 28.25 21.31

Internal Cash Generation - - -- - -- _ 68.17 66.0l 105.71 75.52

World bank Drawdavn 4.90 3.61 33.10 0.59 s9.00 7e.56 4.00 17.04 6.00 5.05lxin lank Drawdown - -- 69.00 83.12 103.0n 1.13 R.nn 39.2A - -Comercial Loan Drawdova 1.12 - 16.24 50.Eq 33.49 50.91 24.0 - -

Short-term Loan -- 5.00 - 35.00 - MA.0O - - -

Subtotal 6.02 8.61 113.34 168.80 245.49 149.60 36. 0 56.24 111.73 77.57

Increases in Government Contributions 1.10 0.50 38.90 1.32 37.00 - - -- - -Increases in Other Liabilities - _ - - - _ - 14.10 - 29.93

TOTAL SOURCES 7.12 9.11 157.24 170.12 282.49 149.60 104.26 136.35 111.73 107.50

Applications

Capital Uxpenditures 4.90 4.30 179.10 206.71 276.00 142.02 16.00 13.64 6.00 8.50Long-term Loan Repayment - - - - 4.90 - 10.31 10.41 11.54

Short-tarm Loan Rapayment - -- -- -- -- -- 30.21 -Interest 3.02 0.20 6.78 2.39 22.42 37.97 34.13 40.84. 35.32 27.73

Total Debt Service 3.02 0.20 6.78 2.39 22.42 42.87 34.13 81.36 45.73 39.29

Increase in Deferred Charges - 0.10 - 0.40 - 0.61 - (0.22) - -Changes in Working Capital (0.80) 4.01 (28.64) (39.38) (15.93) (35.90) 54.13 41.57 60.00 59.71

Total Application.s 7.12 9.11 157.24 170.12 282.49 149.60 104.26 116.35 111.73 107.50 t

Debt Service Coverage,/ - -- - -- - -- 2.00 1.29 2.31 1.35

0

1or long-term debt only.

THAILANMPTr


Palance Sheets(Ifn Us$ millions)

An of September 30 1979 1980 I1RI 1002 1983Appraisal Actual Appraleal Actual Appraisal Actual Appralsal Actual Appraisnl Actual

Assets

Gross Fixed Aaests, Revalued 4.40 4.80 184.00 211.50 473.no 368.24 s22.00 407.51 565.00 444.54Leses Ace Depreciation - - (26.10) (20.3A) (56.18) (42.19)

Not Revalued Fixed Aseetc 4.40 4.80 184.00 211.50 473.00 363.24 495.90 387.13 508.A2 402.35

Deterred Charges - 0.10 -- 0. 50 1.11 - 0).3g - 0.67

Current Assete

Cash 5.37 3 16.2 -- 6.7 5.7 0.58 61.07 39.09Accounts Receivable -- -- -- --- - 15.h5 36.91 21.22 40.74Other Current Assets -- 0.09 -- .68 -- 5.28 - 3.13 - 26.07

Total Current Assets _ 5.46 - 25.50 - 12.15 21.63 40.62 82.29 105.94

Total Assets 4.90 10.36 14.00 237.50 473.00 38I.5n 517.53 42A.64 591.11 508.96

Liabilities & Equlty

Capital 1.10 1.69 40.00 3.0l 77.0n 2.70 77.00 2.73 77.0n 2.74Revaluation Reserves -- -- - - 13.00 14.81 46.0n 40.29 81.17 68.1%Retained Earnings (3.02) (1.10) (9.801 (3.49) (32.22) (41.46) (24.2A) (25.01) 17.04 (1l.04)

Total Equity (1.92) 0.59 30.2n (0.48) 57.78 (21.e5) 44.72 M8.M1 176.05 60.84

Longrters Debt 6.02 3.61 124.36 137.41 360.95 26q.73 405.e5 329.26 401.57 319.74leserve for Cca Coat Adjustment -- -- -- - -- - - - 4A.16

Current Liabilities

Short-term Debt -- 5.00 -- 40.00 - 58.no - 16.2S -Accounts Payablae/ 0.81 1.16 29.44 60.57 *5.37 78.22 12.87 65.12 13.52 80.22

Total Current LiabilItles 0.81 6.16 29.44 100.57 45.37 136.22 12.87 81.37 13.52 80.22

Total Liabilities 6.83 9.77 153.80 237.98 415.22 405.45 418.82 410.63 415.05 444.12

Total Liabilities 4 Equity 4.91 10.56 184.00 237.50 473.00 381.50 517.53 428.64 .591.10 50a.96

Debt/Equity Ratio 1.47 0.86 0.80 1.00 0.86 1.10 M.G0 0.95 0.70 0.86Current Ratio -- -- -- -- -- -- 1.68 0.50 6.09 1.32Return ou Average Net Assets (2) -- -- -- -- -- - R.68 12.0R 15.42 12.60

I/ Actual state.entu include tares and import dutlea payable

THAfLAND


Gas Sales Margin(in US$/MMBTU)

Appraisal Current EstimateSelling Price Average Cost Gross Margin Selling Price Average Cost Gross Margin

1982 2.5 1.6 0.9 3.7 2.5 1.21983 2.7 1.6 1.1 3.7 2.6 1.11984 2.9 1.8 1.1 3.7 2.5 1.21985 3.1 1.9 1.2 4.1 2.6 1.51986 3.3 2.1 1.2 4.3 2.8 1.51987 3.5 2.3 1.2 4.5 3.1 1.41988 3.8 2.5 1.3 4.7 3.4 1.31989 4.1 2.6 1.5 4.9 3.6 1.31990 4.3 2.8 1.5 5.1 3.9 1.21991 4.6 3.0 1.6 5.5 4.2 1.3 o1992 5.0 3.2 1.8 5.9 4.6 1.31993 5.3 3.4 1.9 6.4 4.9 1.51994 5.7 3.7 2.0 6.9 5.3 1.61995 6.1 3.9 2.2 7.5 5.7 1.81996 6.5 4.2 2.3 8.1 6.? 1.91997 7.0 4.5 2.5 8.7 6.7 2.01998 7.5 4.8 2.7 9.4 7.1 2.31999 8.0 5.2 2.8 10.2 7.7 2.52000 8.5 5.5 3.0 11.0 8.3 2.7

1/ Based on gas supply from both Union Oil and Texas Pacific.

o

- 61 - ANNEX 5Page 1 of 2

THAILAND

Second Natural Gas Development Project

Consolidated PTT Finances

PTT's consolidated finances over the last four years are summarizedbelow:

(in million US$)

FY1980 FY1981 FY1982 FY1983-------------…-audited…---------------

Revenues 1165 1199 1364 1559Net Income 28 (41) 41 46

Current Assets 406 664 595 540Total Assets 653 1107 1048 1042Current Liabilities 411 782 440 426Long-term debt 160 288 545 513Total Equity 82 37 63 102

Operating Ratio 0.96 0.99 0.93 0.95Current Ratio 0.99 0.85 1.35 1.27Receivables Turnover (days) 88 95 77 39Debt/Equity Ratio 66/34 92/8 90/10 83/17Total Liabilities/Equity Ratio 87/13 98/2 94/6 90/10

Consolidated PTT's finances were dominated by ODS before pipelineoperations started in FY82. As the above table shows, PTT reported net incomeof $28 million in FY80. However, its liquidity position was weak. This wasmainly due to delayed payments by EGAT, by far the largest customer of PTT.In addition, ODS' inadequate billing and control system prevented effectivemanagement of accounts receivable.

In FY81 EGAT began to make timely payment to PTT and ODS' accountingsystem was strengthened with the assistance of consultants. Nonetheless,delayed payments by the Oil Stabilization Fund and delayed effectiveness oftwo long-term loans for the pipeline project necessitated the occurrence ofsubstantial bridge financing at prevailing high interest rates. In addition,funding of the Bangchak refinery represented a major drain on PTT's cashposition and a short-term loan in the order of $300 million was drawndown tomeet Bangchak's working capital requirements. PTT's operating income of $9million was insufficient to cover an Interest expense of $30 million and,after foreign exchange loss of $21 million, the company posted a net loss of$42 million in FY81.

PTT's finances improved considerably in FY82 and 83. In particular,its liquidity position was strengthened, as reflected by a current ratio of1.3-1.4 against 0.85 in FY81.

ANNEX 5- 62 - Page Z of 2

This was mainly due to the following:

(a) In accordance with the action plan to alleviate PTT-s short-termliquidity problems, PTT sought co-mercial financing of $200 million,interest and principal on which would be paid by the Government. Ofthis amount, $125 million would represent payment of the Oil Fundsindebtedness to PTT, while the balance would represent equityinjection into PTT. In addition, the Government allowed PTT toconsolidate the inventory of ODS and Bangehak refinery for purposesof compliance with the regulation for crude and products reserves,thereby lowering the level of required inventory for overall PTT.

(b) The Oil Stabilization Fund made timely payments to PTT.

(c) Long-term loans for the pipeline project became effective andsubstantial bridge financing was retired.

(d) ODS' profitability was improved.

Notwithstanding a 6Z drop in sales revenues, ODS reported a sharpincrease in operating income of $41 million in FY82 as compared against $9million in FY81. This was mainly as a result of a change in product mix, withan increased share of gasoline which is the single most profitable product.Interest expense was decreased by 37% to $20 million, resulting in a netincome of $21 million. Together w4th a net income of $20 million from ONG,consolidated PTT-s net income totalled $41 zi.llion in FY82. ConsolidatedPTVs net income continued to increase to $48 million in FY83, with $27million and $21 million from ODS and ONG respectively.

I bRD 13476 RI- !t~~~~~~~Ak~~~~~~ too. ~~~~~~NOVEMBER 1979

THAILAND.W Saroburt, PROPOSED PIPELINE ROUTES

V 4 N. =El Kanchon'buri i

Pokhon PaitomO 8nko Dag a

V . Ratchoburi0 A * Oil -

i- l -i l SomutSanSirom° 0 ° Dry Holes

p .. f 5 amut ; - Proposed Pipeline%

Phrhbr0 (,us F,eldsArea of nPietcha-ur( - -Iierflarional Boundaries

or ALAW YIA ,Ii.*'i.

rNDONESA '' hi7 | ( aDEMOCRATIC

3 KP. chwp ° | \ KAMPUC-+IEA 1-

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0~~~~~~~~~ _. SHSARED BYSorealkhla O , WrAL AND MALAYSIA

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O 20 40 60 X 10e0 120 140 160

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World Bank Document · The report consists of a Project Completion Report (PCR) prepared ......

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