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 I Is deemet m h l d asumary hewd bY eedieb OmYI 1wdaafmamc of tlbelr0-- &dmlb 1"mf =V sont& be _ba ortWld _sk _{wwhao FOR OMCIL USE ONLY PROJECT PERFORMANCE AUDIT REPORT THAILAND; SECOND NATURAL GAS DEVELOPMENT PROJECT (LOAN 1773-TH) TABLE OF CONTENTS Page No. Preface ..... ..... . . ........................ i Basic Data Sheet ...................... .... ii Highlights ................................. , ............ iv PROJECT PERFORMANCE AUDIT MEMORANP-i I. PAST BANK ASSISTANCE TO ENERGY SECTOR ................... 1 II. PROJECT RATIONALE .............. ...... .. ..... ....... 2 III. GAS EXPLORATION ......................... 6 IV. PROJECT OBJECTIVES AND COMPONENTS .................... ... 7 V. PROJECT COST AND IMPLEMENTATION ......................... 9 VI. GAS RESERVES AND PRODUCTION FORECASTS ................... 13 VII. PROJECT ECONOMICS ....................................... 19 VIII. GAS PRICING AND PROJECT BENEFICIARIES ................ ... 24 IX. CONCLUSIONS ............................................. 28 Attachment - Comments from the Government ......................... 3; PROJECT COMPLETION REPORT I. Introduction ........................................... 33 II. Project Preparation and Appraisal ...................... 34 Ill. Implementation ......................................... 35 IV. Operating Performance ...... ............................ 41 V. Economic Performance ................................... 41 VI. Institutional Performance .............................. 44 VII. Financial Performance ...... ............................ 45 VIII. Performance and Role of the Bank ....................... 49 IX. Conclusions ................ 50 Annexes 1. Comparison of Estimated and Actual Project Costs .....6 53 2. Schedule of Disbursements .............................. 54 3. Economic Analysis ..................................... 55 4. Natural Gas Operations Finances ........................ 56 Income Statement ............................ 57 Sources and Application of Funds .......... .. ........... 58 Balance Sheets ....... .................................. 59 Gras 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 of their offial duties. Its contents may not otherwise be disclosed without World Bank authorization. - i - PROJECT PERFORMANCE AUDIT REPORT 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 which Loan 1773-TH for US$107 million equivalent was approved on December 11, 1979. The loan was fully disbursed by December 31, 1983, when it was closed. The report consists of a Project Completion Report (PCR) prepared by the Energy Department of the Energy and Industry Staff and a Project Performance Audit Memorandum (PPAM) prepared by the Operations Evaluation Department (OED). The borrower contributed to the PCR by supplying necessary project data. OED has reviewed the PCR against the Appraisal and President's Reports, the legal documents and the transcript of the Executive Directors' meeting which considered the project. Project files and documents have also been reviewed and discussions have been held with Bank operational staff. Further, an OED mission had discussions with officials of Government depart- ments and agencies and managers of an international oil company in April and October 1984. In the audit's view, the PCR gives, on the whole, a fair account of the experience under the project. The PPAM has expanded on a number of issues, modified the discussion of others and added new ones. Following standard procedures, OED sent copies of the draft PPAR to the Government/borrower for comments. The comments which were received have been reproduced as an Attachment to the PPAM. - li - PROJECT PERFORMANCE AUDIT BASIC DATA SHEET THAILAND: SECOND NATURAL GAS DEVELOPMENT PROJECT (LOAN 1773-TH) KEY PROJECT DATA Appraisal Actual or Estimate Current Estimate Total Project Cost (USS million) 514 423 - Underrun (%) -- 18 Loan Amount (US$ million) 107 107 - Disbursed -- 107 Date Physical Components Completed 09/01/R1 09/01/81 Proportion of Physical Components Completed by Original Completion Date (Z) 100 100 Proportion of Time Overrun (%) -- 0 Economic Rate of Return (%) 48 45-50 Financial 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 1977 Negotiations 09/26/79 Board Approval 12/11/79 Loan Agreement 02/15/80 Effectiveness 05/15/80 05/27/81 Closing 12/31/83 12/31/83 Borrower and Executing Agency Petroleum Authority of Thailand (PTT) Fiscal Year of Borrower October I - September 30 Follow-up Project Name Liquified Petroleum Gas Loan Number 2184-TH Amount (USS million) 90 Loan Agreement 08/17/82 /a According to PCR. Calculation not verified by audit. - iii - MISSION DATA Month/ No. of Staff- Date of Year Persons weeks Report Identification/Preparation /a 76-78 3 17 Appraisal 03/79 3 6 11/05/79 Supervision 1 05/80 1 1 06/03/80 Supervision 2 07/80 3 5 08/15/80 Supervision 3 12/80 2 3 01/12/81 Supervision 4 07/81 3 4 07/28/81 Supervision 5 09/81 2 3 10/26/81 Supervision 6 11/82 2 8 11/18/82 Completion 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 20.3 Completion 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. - iv - PROJECT PERFORMANCE AUDIT REPORT THAILAND: SECOND NATURAL GAS DEVELOPMENT PROJECT (LOAN 1773-TH) HIGHLIGHTS The project changed the focus of the Bank's energy sector lending in Thailand. Prior to the project, during a period of 20 years, the Bank provided financial assistance exclusively for hydro-electric and thermal power generation and transmission. Starting with the project, the Bank broadened 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 dominated Thailand's total energy supplies, accounting by the end of the seventies for over 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 the economy. This project, in combination with other projects and reformulated energy policies, was to remove or lessen the threat (PPAM, paras. 6-14). The project became feasible because of off-shore gas exploration initiated in the late sixties, well before the first oil shock occurred in 1973-74. Exploration, a complex, high risk and capital intensive under- taking, was the exclusive domain of international oil companies (IOCs). In the mid seventies, exploration led to the discovery of two major tracts of commercially attractive fields, which formed the basis for the project (PPAM, paras. 15-18). The project was the Government's contribution toward actual use of the 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 pipeline operator, and studies of energy policy issues. Field development was the responsibility 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 the Government (US$77 million) and external borrowing (US$437 million). Matching IOCs' total investments for exploration and development are projected to exceed US$2 billion. The Bank loan of US$107 million was in line with the Bank's target of financing 15-20% of oil and gas development projects set out in energy policy papers, but no specific explanation has emerged for deter- mining the precise amount of the loan. The large scope of commitment of Government credit worthiness was explained by the IOCs' reluctance to finance more than field exploration and development. Physical implementation of the project 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 satisfactory operation since (PPAM, paras. 24, 25, 28 and 45). -v - Certification of adequate gas reserves by independent reservoir consultants 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 the experience with the field which was first developed. That field showed high- ly unusual geological conditions, and it could be assumed that other fields had similar characteristics. The entire episode generated doubts about the rationale, validity and adequacy of the field evaluations; and it raised questions about the Bank's role in their design or review (PPAM, paras. 33-36). Gas production forecasts were loosely tied to the gas reserve evaluations performed by the reservo'r consultants. At appraisal, it was believed that total proven and probable reserves provided an adequate safety margin 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 production agreement between an IOC and PTT. The experience demonstrates that adequate attention must be given to gas sales agreements, which as much as adequate zcserves 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 of production from fields which did not form the basis of the project, aggregate Gulf production, however, should, in The coming years, approximate the pro- jections. Natural gas trom the Gu'.f, in conjunction with other indigenous energy supplies and dema-d--based e;;ergv policies. is now on the threshold of making the country's energy imporc dependence manageable (PPAM, paras. 38-39 and 54). From the outset, the project wes viewed as being econnmically highly attractive and relatively immune to serious risks. The economic rate of return (ERR) projected was aboait 50%. Tle PCR has recalculated the ERR at about 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 the investment return. The IOC currently producing gas reports that it expects its financial retuirn on investments to be below 15Z, a result which in its view is disproportionate to its investment risks and to the project's economic benefits to the country. Perceptions of inadequate private sector returns could have a bearing on IOCs' future involvement in the Thai energy sector and invite Government and Bank attention (PPAM, paras. 42-47). To promote energy efficiencv, ensure financial viabilitv of the pipeline operator and generate Governmenr revenues, the project included a provision for delivery of gas to the principal end-user (power generating utility) at a price close to 90% o' the cost of fiel oi. To enforce the provision, loan effectiveness was held up bv 1. months. In the end, the provision was relaxed, and the fueJ oil parity actuallv achit-ved was between 70 and 802 (PPAM, paras. 68--91'. - vi - As a result of the project, PTT's Office of Natural Gas, if not PTT itself, was expected to show an outstanding financial performance. Rates of return on net fixed revalued assets and cash balances projected were, for Thai state enterprises, exceptionally high. However, the project contained no special proviston for transforming PTT revenues into treasury revenues. The project, in this regard, may riot have been fully consistent with the apparent objective of generating budget revenmies, and it may not have reinforced financial discipline (PPAM, para. 52). - 1 - 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 phase in the long-standing Bank support to the Thai energy sector. Under the first phase, 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 made to the Electricity Generating Authority of Thailand (EGAT) and its prede- cessor utilities._/ Under the second phase, starting in 1978, the Bank became involved in the development of (non-hydro) indigenous sources of energy-gas, gas derivatives and lignite, to address the wider needs of the Thai energy sector since the mid-seventies and to fulfill its mandate of more diversified and intensified energy sector assistance to its member countries. 2. Thirteen power project and power subsector loans to EGAT and its piedecessors 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 so far been made. The projects were reported to have been satisfactorily imple- mented or are in progress. Another power subsector loan to finance EGAT's investment program is under preparation. Project Performance Audit Reports (PPARs) were issued on three projects (Loans 655-TH of 1970, 790-TH of 1971 and 977-TH of 1974). All three projects were evaluated as having met their major stated objectives. 3. Three gas-related projects were financed, for a total loan amount of US$201.9 million: the Natural Gas Development Engineering Project (Loan SOIO-TH of 1978), the project under audit (Loan 1773-TH of 1979) and the Liquified 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-TH financed 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 and supplying electric power. 2/ PEA, also a state enterprise, is charged with the supply of electricity outside Bangkok Metropolitan Area. It is engaged primarily in the transmission of power, buying most of its electricity from EGAT. - 2 - 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 to on-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 Moh Lignite Project (Loan 2407-TH) of 1984. Total Bank financing was US$131.1 million. EGAT, which operates the Mae Mob mioe, was the borrower in both cases. 5. Several other recent Bank operations had energy-related components, including the Structural Adjustment Loan (2097-TH of 1982, SAL I), the Second Structural 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 the design of a program of energy conservation, pricing/taxation and development; creation of an institutional framework for energy policy coordination; and the undertaking of a petroleum pricing study later expanded to cover also gas and lignite (Energy Pricing Study). Under SAL II, the Government undertook to formulate an action program for energy pricing, based on the SAL I pricing study, and to institute steps to further the efficiency of energy use in industry and transport. Loan 2256-TB also dealt with specific aspects of energy pricing in transport. Bank assistance to the Thai energy sector has also 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 to include 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 fast pace of 15-17% p.a. Comercial energy, representing between 80-90% of total primary energy, even grew at a slightly higher rate, far ahead of the more slowly expanding non-commercial energy. The overall pace continued into the seventies up to the first oil shock in 1973/74, when growth temporarily came to a halt. It bounced back thereafter to about 8-9% p.a. until, during the second oil shock in 1979/80, there was once more a brief period of no growth. Despite the two periods of contractions, energy supply in the seventies expcnded at an average rate of 7% p.a., marginally ahead of growth in GDP. 3/ Commercial and non-commercial energy combined. Non-commercial energy includes chercoal, firewood, bagasse (based on sugar cane) and paddy husk. 7. Throughout the sixties and seventies, petroleum products dominated total energy supply. By the end of the seventies, they accounted for about 72Z of total supply, while hydroelectricity provided about 3X of energy, lignite and small quantities of (imported) coal combined also about 3%, and other, mostly non-cocmercial fuels, the remaining 22Z. Again, by the late seventies, 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, either as crude oil for processing in Thai refineries or as end-use products. Since 1973/74, because of the steep increases in (real) prices for petroleum prod- ucts, these imports progressively burdened the Thai economy and weakened its external trading and financial position. By 1980, net oil energy imports amounted to about US$2.5 billion, which was about 30% of total merchandise imports 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 markets and to counter the high cost of energy supply, the Government, in the late seventies, developed a two-pronged energy strategy: energy conservation and constraints on growth in energy demand; and shift of energy supply toward domestic energy resources. The strategy of energy conservation and con- straining energy demand was, to a large measure, based on the close linkage of domestic energy prices with international oil prices.4/ After little domestic price adjustments in the mid-seventies for oil products, the Government sharply increased the prices in the late seventies. On various occasions since, the Government has confirmed the principle of reflecting price movements of imported energy in the domestic price structure. A complementary element of the pricing strategy was a package of regulatory measures of energy conservation, particularly in industry and transport. The design 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 consumptive sectors.6/ 10. The strategy of substitution of imported oil products was based on the development of all commercial sources of domestic primary energy--hydro- power, lignite and natural gas. Power, industry and transport were the most important sectors targeted for import substitution. Power offered the great- est scope for substitution of oil products because of potentially large-scale use of all three sources of indigenous energy. Industry could make wider use of lignite, on which it already based a small fraction of its fuel needs, and shift to natural gas, where feasible. Transport could utilize liquified petroleum gas (LPG), a component of natural gas, to power vehicle engines as a substitute for gasoline and possibly diesel. With some modifications in engines 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 larger utility vehicles.7/ 11. About one-half of the hydroelectric potential assessed at the time was considered economically feasible. By the late seventies, only about 20% of this potential was installed, leaving considerable scope for further expansion. In the long run, there was also the hydropotential of the inter- national Mekong and Salween Rivers, matching Thailand's entire domestic hydro resources, 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 Development Bank and the other by Japanese bilateral assistance, are in the final stages of completion. A study of incentives for energy conservation in industry, with Bank financing, is scheduled for the near future. For the transport sector, the Ministry of Communications, with Bank assis- tance (Sixth Highway Project, Loan 1519-TH) undertook a study on energy policies which, completed in 1982, forms the basis for a detailed action program currently under preparation. Other studies also had a bearing on energy conservation issues: a Bank-financed lignite pricing study (Mae Moh Lignite Project, Loan 1852-TH), completed in 1983, and an energy pricing study (Loan 2097-TH), completed in draft final form in 1983. 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, has confirmed the feasibility of an LPG-based fuel supply system. - 5 - envisaged doubling or tripling installed hydrocapacity by the late eighties.8/ 12. Thailand's (proven and probable) lignite reserves were, by the end of the seventies, assessed at about 750 million metric tons. The reserves, about one-half of them economically recoverable, were upgraded from only 200 million tons a few years earlier. Production had more than doubled from 1977-78 to 1979-80 and was projected to at least quadruple by the early nineties.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 in various other locations. The Mae Moh and Krabi deposits are mined by EGAT for 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 tcf were proven and 4.7 tcf were probable (PPAM, para. 33). All fields combined were conservatively estimated to produce some 500-600 million cubic feet per dayL/ (MKCFD) over some 20 years, or equivalent quantities for other periods (PPAM, para. 38). 8/ Current plans aim at an 80% utilization of the economically feasible hydro-potential by about the mid-nineties. 9/ Production was 0.6 million tons per year (tpy) in 1977-78, and 1.3-1.4 million tpy in 1979-80. Under investments undertaken since 1980 with Bank assistance, current (1983) mine output is about 1.8 million tpy, and with other Bank assisted investments in progress (para. 4), 1986 output is expected to be about 5.0 million tpy. Current long-term plans envisage total production to reach about 12 million tpy in the early nineties, a twenty-fold increase over the 1977-78 levels. 10/ In 1982, non-EGAT mines produced some 0.15 million tons, about 9% of the country total. 11/ Quantities standardized at calorific value of 1,000 British Thermal Units (BTU) per cubic foot. - 6 - 14. The energy sector strategy, shaped in the late seventies,12/ was projected to produce these global results: restraint of energy demand to a growth rate approximating that of GDP, in the eighties; and supply of primary energy from indigenous resources in the order of 55-65% of total needs, by around 1990. Among the comuercial energy sources, hydropower was to reach a supply share in 1990 of some 7%, up from 3Z in 1980; lignite, some 10%, up also from 3Z; and natural gas, 18-25Z, up from zero percent. The projections were based on production of some 500 MMCFD of gas. The supply scenarios made it explicit that natural gas had the potentially largest impact on oil import substitution, in view of the smaller resource base of hydropower and lignite, and that any serious setback in gas production would be an equally serious setback for energy import substitution. III. GAS EXPLORATION 15. The project was based on gas exploration initiated some ten years earlier, well before the 1973/74 oil shock forced a global rethinking of energy policies and raised rewards for development of indigenous energy. The exploration was greatly helped by improvements in off-shore drilling tech- niques and the 1972 passage of Thai legislation under which the legal and fiscal 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 Thailand and the Andaman Sea, and the first concessions for those areas were granted in the late sixties. Actual off-shore exploration was concentrated in the Gulf, with only minor activities in the Andaman Sea. Exploration in the Andaman Sea was finally discontinued and the concessions were relinquished by mid-seventy after prospects for finds had diminished. Exploration in the Gulf spanned over the entire seventies, with a marked intensity in 1974 and 1975. In the mid seventies, it led to the discovery of two major tracts of gas fields by two concessionaires, Union Oil (in partnership with South East Asia Petroleum Exploration Company) and Texas Pacific (in partnership with Canadian 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 it recast and formalized the quantitative sector targets. Under this plan, total energy consumption was to be limited to 4.6Z p.a. during the plan period, a figure below the target growth rate of GDP; and the share of oil products consumption of total (primary) energy consumption was set at 46% by the end of the plan period (down from over 70% in 1980). 13/ Various formulas for Thai capital participation in exploration are being explored. -7- 17. Union Oil discovered its first commercial quantities of gas in the so-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 some 150 km off the coast of southern Thailand, the field covers an area of about 25 x 5 km. The other fields, which Union Oil subsequently discovered, were Baanpot to the south of Erawan and Kaphong, Platong, Pladong and Satun to its north, 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, some 170 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 Second Natural Gas Pipeline Project. 18. The first concessions for on-shore exploration were also granted and relinquished by the early seventies, after several wells drilled were dry. In the late seventies, interest in on-shore exploration was rekindled, and new concessions were issued to several firms. isso, one of them, has more 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 of large investments for the gas pipeline system and a Government commitment to purchase, market and utilize the gas. Having already financed gas explora- tion and being prepared to finance field development, IOCs were reluctant to also finance the transmission system. To the Government, the project was a high-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 20,000 barrels of oil per day (bpd), and output is expected to remain at about this level. The oil field has raised hopes for more substantial oil discoveries. - 8 - confirmed energy resources into tangible and quickly maturing economic benefits.15/ 20. The Bank played several roles under the project. It assisted in arranging external financing for the public investments, which in view of tight domestic resources was mandatory. It helped organize the efficient installation and management of the gas transport and distribution system, and it endorsed the Government's Gulf gas development plans, project investments and agreements. Jointly with other external project sponsors, it also provided the private sector with cover against conceivable, though in no way imminent non-commercial risks. 21. The project focused on the provision and phasing-in of the gas transport and distribution system. Other main areas of attention were insti- tutional development of the executing agency and designated operator of the pipeline, the Petroleum Authority of Thailand (PTT), and studies of selected energy sector issues. The transport and distributioi system consisted of a marine pipeline (about 425 km) from the Erawan field to shore, a landbased pipeline (about i70 km) to two EGAT power plants in Bangkok, and on-shore terminal and operating facilities, including a communication center. Insti- tutional development of PTT was to be achieved primarily through a program of staff training in a broad range of gas-related skills, including pipeline operations and accounting/finance. The sectoral issues to be studied, also with consultants' assistance, included gas utilization, refinery expansion and energy conservation, the latter topic covering all of the following: an energy audit, an investment program for energy savings, policies for energy demand management a.nd future investments in energy including non-conventional sources.16/ 22. The marine pipeline was dimensioned to carry about 500 MMCFD of gas under free flow conditions and up to 700 MMCFD, if compressors (not included in 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 of project objectives. Some objectives may not have needed much elabora- tion, and others were implicitly covered in various parts of the reports. The lack of such statement, nonetheless, renders the task difficult 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 the Project, Part E: Studies) referred only to an energy audit of major industries. - 9 - Structure (Texas Pacific) and other, at the time yet uaconfirmed, eas struc- tures.17/ A pipeline with a smaller diameter dedicated to the projected Erawan production only would have resulted in savings of some 10% of total project cost, but would have required construction of a second pipeline for the Texas Pacific gas, had it come on stream while Erawan was at its pro- jected peak. A pipeline with a larger diameter was apparently rejected because a throughput exceeding 700 MMCFD (with compressors) was considered unlikely. 23. A cornerstone of the project was the existence of a gas sales agreement between Union Oil and PTT, under which, starting by September 1981, gas from Erawan would be delivered in annual quantities of 200 MMCFD in the first year of production (1982) and, subject to annual confirmation, 250 MMCFD thereafter. The contracted gas volumes were tied to the estimated size of Erawan's economically recoverable reserves and expected to be sustained for 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 recoverable reserves in the Erawan field, a condition which was met several months prior to loan approval.18/ The Union Oil-PTT contract included a take-or-pay provision, under which PTT would be heavily penalized19/ if it did not take delivery of the gas. PTT expected to cover its own contractual risks through a take-or-pay gas sales agreement with EGAT (for quantities broadly matching those of the Union Oil-PTT contract), which was not yet in force when the loan was approved, but made a condition of loan effectiveness.20/ V. PROJECT COST AND IMPLEMENTATION 24. Total project cost, including physical and price contingencies and interest during construction, were estimated at appraisal at about US$514 million. They were to be financed by a Government contrioution (US$77 million), export credits by the United States, Japan and European countries 17/ The pipeline connecting the -B Structure with the Erawan pipeline was not included in the project, but expected to be laid after the Texas Pacific gas had been contracted. 18/ SAR, para. 2.03. The amounts certified were 1.1 tcf of proven and 0.4 tcf of probable reserves. 19/ SAR, para. 2.15. Penalty in the order of USS0.5 million per day in 1982 based on 200 MMCFD. 20/ Despite the lack of a binding agreement between PTT and EGAT when the loan was made, it was expected that EGAT would be agreeable to taking timely delivery of the gas (PPAM, para. 49-51). - 10 - (US$180 million), loans from commercial banking sources (US$150 million) and the Bank loan (US$107 million). The Bank loan was primarily to finance the off- and on-shore pipelaying contracts, and it was to refinance the loan (US$4.9 million) arranged under the Natural Gas Development Engineering Project (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 is US$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 other savings were in taxes and import duties, freight and other pre-construction and installation charges. The PCR credits keen competition under prevailing market conditions, which were apparently not anticipated, for the substantial cost savings in pipelaying. Other explanations suggested in the PCR22/ for the cost underrun are good project management and the adherence to the orig- inal project schedule, although, of course, the original cost estimate was unlikely to have anticipated poor project management and the estimate was based on the original schedule which was actually achieved. 26. At appraisal, the cost for project engineering and management were estimated 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- of USS4 million. Actual total costs were about US$43 million, an increase of USS20 million or 87%. Bank supervision reports and the PCR23/ make only terse references to the causes for the stiff overrun--higher than anticipated staff input, resulting in part from inadequate communication between the con- sultants and their client, and rates higher than the Bank had experienced under 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 are not possible and where bidding procedures are unacceptable to the Bank, and to target the Bank loan at about 20%'. Why this particular target of Bank participation was chosen is exactly the point the audit is raising. 22/ PCR, para. 3.13. 23/ PCR, para. 3.14. 24/ Actual man-months and man-month rates have not been recorded. - 11 - less costly way to overcome communication problems and whether qualified consultants with lower fees could have been selected.25/ 27. The savings in total project cost affected mainly US-procured goods and services, and the share of export credits of total financing was accord- ingly reduced the most, from US$180 million, as estimated at appraisal, to about US$125 million. There were also savings under the Bank loan which were subsequently reallocated to another project item. Except for the Bank loan, which was fully disbursed, all other sources of financing were drawn down at a reduced rate. PTT internally generated cash, which was not expected at appraisal, also contributed to project financing. The first disbursement from the Bank loan was held up for 12 months, until the last of three condi- tions of effectiveness, conclusion of a satisfactory gas sales contract between 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 schedule and according to specifications. The system was commissioned in Soptember 1981, when the first gas was delivered, and it has been in satisfactory oper- ation since. Under its own financing, EGAT converted several thermal units at South Bangkok power station to gas and fitted the Bang Pakong station (also near Bangkok) with combined cycle units. Two cement companies built an 80-km long pipeline which connects their plants with PTT's pipeline to the EGAT power stations. The connector, dimensioned at about 95 MMCFD (without use of compressors) and available to other industries located nearby, was built at a cost of about US$60 million and brought into operation in 1983. A 43-km long ADB-financed pipeline (including on-shore compression), linking Union Oil's Platong field to the main marine pipeline (from Erawan), was completed in 1984, with a budget of US$135 million. 29. A training program covering "a11 aspects of PTT's petroleum business' was part of the Loan Agreement's project description. Two types of training programs were implemented under the project: overseas training for upper and middle management, and on-the-job training of staff in PTT's Office of Natural Gas (ONG), later merged into PTT's Natural Gas Operations (also ONG). The latter training was provided in the context of operational assis- tance rendered under various consultancy contracts. Bank reporting on implementing the training component was sketchy. A supervision mission in late 198126/ reportce the institution by PTT of proper manpower planning and training for all its activities, and the PCR states that from an institutional perspective, the Bank required and assisted in establishing 25/ Bank staff explain that they considered the fees unreasonably high for this kind of work and so advised the Government. The Government appar- ently disagreed and the Bank did not finance the contract. Also, staff note that slow decision-making (on the Government's side) contributed to the high cost overrun. 26/ Supervision Report, October 27, 1981. - 12 - appropriate technical, financial and operational training programs .27/ It would have been desirable that the Bank's requirements and assistance, in the context of the project under audit, would have manifested themselves in adequate documentation, detailing training programs, targets, and achieve- ments.28/ This might have also facilitated an assessment of PTT's institu- tional development in gas to date. Queries addressed to the audit mission left the impression that there is interest in such an assessment. 30. According to the Loan Agreement, three sector studies were to be undertaken: a gas utilization study, a refinery expansion study and an energy audit of major industries. The project contributed its share to the glut of foreign-financed studies, which in recent years has characterized the energy sector and which Government planners profess to have difficulty to deal with. The Gas Utilization Study was to identify potential and optimal uses of gas to the year 2000 and to assess the associated investment needs.29/ The commissioning of the study after, rather than before, commit- ment and delivery of gas to end users (notably EGAT) appeared justified at the time. Long-term gas production of the Gulf was expected to greatly exceed initial production under the project, and the use of the gas in accordance with the study's findings was therefore not much in jeopardy. The Energy 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 intended for identification of the most attractive investments in gas. Phase II was to study the identified _nvestments in detail. An interim report for Phase T, identifying LPG, certain petrochemicals and ammonia/urea as being of highest priority, was completed in mid-1981. The final report was submitted in early 1983. The Energy Pricing Study covered some of the same ground again. 31. The Refinery Expansion Study by consultants was satisfactorily completed in 1981. A main objective was the identification of measures for correcting the supply and demand imbalances for petroleum products. The findings were incorporated into the design of the Bangchak Oil Refinery Restructuring Project (Loan 2548-TH) under which the refinery configuration of Thailand will be changed. 32. The Energy Audit of Major Industries was not undertaken, but the project description in the Loan Agreement was not amended. Several studies with similar focus are being or will be undertaken outside the context of this 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. - 13- 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 on occasion alarming changes. In 1979, when Loan 1773-TH was made, the Gulf's economically recoverable proven and probable reserves were confidently and conservatively-30/ assessed at 7.6 tcf. The assessments, referring to Union Oil's Erawan and Texas Pacific "B fields, were performed by independent reservoir consultants. Erawan's share of the 7.6 tcf was 1.8 tcf (1.6 tcf proven 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 and expectations about Gulf gas climaxed, and the Gulf's economically recoverable proven and probable reserves were upgraded from 7.6 to 20 tcf. This time, the assessments, now also referring to other (than Erawan) Union Oil gas fields (with 9.2 tcf proven and probable out of the total of 20 tcf), were in part performed by the same independent reservoir consultants, and in part by PTT and the IOCs. In 1982, gas production from Erawan started, but was imme- diately and drastically short of targets. In response, a reassessment of Erawan by the same consultants was commissioned, which in mid-1983 produced a downgrading of that field from 1.8 to 0.6 tcf.31/ On the experience with Erawan, industry observers substantially revised their estimates of total Gulf gas reserves downward, and Bank staff went as far as provisionally estimating the reserves earlier certified at 20 tcf to be only about 4.5 tcf.32/ However, no reserve estimate has been produced since which appears reliable and on which various analysts and observers can agree. Since mid-1984, as a result of an accelerated drilling program by Union Oil, Erawan gas 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 recoverable reserves 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 be assumed in mid-1983. 34. The downgrading of Erawan, which triggered a downward revision of other fields, had an impact on the concessionaires, the Government, the Bank and the reservoir consultants themselves. It generated doubts about the adequacy of the field evaluations, caused uncertainty about the future of Thailand's energy sector and complicated sector policies. Some uncertainty lingers 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 these consultants and that there was also a mid-1982 independent reservoir study 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. - 14 - 35. Bank staff, which used the 1979-82 evaluations at face value in two lending operations (Loans 1773-TH and 2184-TH), and industry sources explain that the reservoir consultants followed accepted evaluation procedures, and that highly unusual geological conditions (faulting and fragmentation of fields) were responsible for the ill-fated assessments.34/ These sources also explain that only huge budgets for time-consuming gas field appraisals would have produced the data to give advance notice of the true characteris- tics of the fields and that such budgets and procedures are normally ruled out for off-shore gas. This, of course, means that the chosen gas verifica- tion method had considerable risk of error and that available procedures for reducing the risk are costly and lengthy. It follows that the terms proven and probable reserves have significant variability of meaning depending on the context. 36. The Bank played a fairly passive role in at least the earlier field evaluations 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 the reserve evaluations. The terms of reference did not lead to a meaningful discussion of substance and risks of such evaluations, and the Bank did not undertake a formal review of the evaluations upon completion.35/ Despite a brief warning, that fields may not always live up to expectations,30/ the appraisal neither elaborated on assessment risks nor corrected the impression that 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, no pre-1983 reserve assessment report by consultants could be found in any of the Bank's document centers.) Bank staff advise that for some time, energy sector record-keeping was not fully satisfactory. In the view of Bank staff, the completed reserve assessments, including the 1979 Erawan assessment financed under Loan SOIO-TH, did not require a formal Bank review, as the evaluations were performed to industry standards by reputable consultants. 36/ SAR, para. 2.35. - 15 - high degree of certainty for commercial production"37/, did not demonstrate the economics of gas recovery specific to the Gulf of Thailand or the locations in question,38/ nor shed light on the notion of certainty, and the Bank neither challenged this procedure in advance or later or corrected it in some form or another. A more active and informed Bank role in the design and review of reserve evaluations would be desirable, whenever possible, in future natural gas operations.39/ 37. The Bank's attitude towards the earlier evaluations was consistent with its assumption that total certified proven and probable reserves (7.6 tcf, of which 1.8 tcf for Erawan and 5.8 tcf for Texas Pacific) provided an adequate safety margin for project viability, as they were about five times the volume reportedly needed to make the project economic. This assumption greatly underestimated the assessments' inherent margin of error. The fields assessed at appraisal at 7.6 tcf were subsequently rated at only 1.8 tcf (of which 0.6 tcf for Erawan and 1.2 tcf for Texas Pacific), though this figure is in dispute and by no means universally accepted, and of these 1.8 tcf only 0.6 tcf (Erawan) are so far covered by a production contract. In the end, it may have been the other Union Oil fields, which had not been formally incorporated into the appraisal's 7.6 tcf safety pool (PPAM, pars. 40), which 37? -Estimated Reserves and Deliverability of 'A' Structure Field, Gulf of Thailand, as of March 1, 1979", page 8. In the follow-up report on the same field entitled 'Estimated Gas Reserves for Erawan Field, Gulf of Thailand, as of December 31, 1982", dated July 15, 1983, references to the degree of certainty (or probability) were dropped. According to the 'Manual of Oil and Gas Terms", Fourth Edition 1976, page 468, reserves denoted as proven are probably on the conservative side-. The 1983 downgrading of reserves is therefore even more surprising. According to the American Gas Association's publication -Reserves of Crude Oil, Natural Gas Liquids and Natural Gas in the United States and Canada and United States Productive Capacity", Volume 28, 1974, page 103, reserves are "considered proved that have demonstrated the ability to produce by either actual production or conclusive formation test'. It could be questioned, whether the 1979-82 assessments met the test for classifying reserves as proven . 38/ Such factors as gas well-head prices, drilling programs and cost and financial rates of return on exploration and development expenditures, were not explicitly incorporated into the assessments, even though all of them and not only the physical presence of gas, determine commercial volumes of gas. 39/ Bank staff state that the "basis of the reservoir studies" for the Gulf fields was "entirely normal" and the Bank review of evaluations entirely normal and satisfactory". Nonetheless, Bank staff also acknowledge that lessons were learned from the earlier Erawan experience and that they put them to use thereafter. The audit reiterates that the practices, which Bank staff calls "normal", are indeed good candidates for review and possibly overhaul. - 16 - provided the safety margin. If, at appraisal, total proven and probable reserves (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 years there would be no Texas Pacific contract, the project would likely have been delayed. It is apparent, that much care is needed to ensure that a margin of safety 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 safety margin, 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 in 1982) to an annual plateau of about 500/600 MMCFD in 1987-1990, and it implied that no less than this volume, indicating an "intermediate' produc- tion level, would be sustained to the year 2000.41/ In 1982, under Loan 2184-TH, the Bank revised the estimates for total 1990 Gulf production upward from about 500/600 MMCFD to close to 800 MMCFD, and it even suggested that the 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, against 200 MMCFD projected, and the 1984 production (from Erawan and Baanpot), was also about 200 MMCFD, against 400 MMCFD projected for the year. Despite these production results being well below projections and the low 1983 Gulf reserve 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 a recovery factor of 100X for proven reserves, as apparently assumed in the SAR (paras. 1.06 and 2.03), there would have been a factor of lees than 20% for prob^ble reserves. 41/ Total Gulf and individual field production volumes, which were projected in the SAR, were not fully consistent (SAR, paras. 2.03-2.07, Annex 1.01 and Annex 3.02), nor is the PCR (paras. 5.01-5.02) fully correct in stating that the SAR's estimate for the total 1990 Gulf production was 500 MMCFD. While the economic and financial analyses used 500 MMCFD for 1990, presumably to conform to pipeline capacity under free flow condi- tions, detailed production estimates given in other parts of the SAR were about 600 MMCFD. The 500 MMCFD were made up of 250 MMCFD from each Erawan and Texas Pacific. The 600 MMCFD consisted of about 250 MMCFD for Erawan, about 200 MMCFD for Texas Pacific and about 150 for not yet identified 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 had visions at the time of gas exports and large-scale downstream invest- ments in gas-based industries which would transform the Eastern Seaboard into the industrial power house of Thailand. These visions subsequently vanished, though lately, hopes have again been expressed for gas exports after 1990. - 17 - to gradually reach some 400-600 MMCFD by 1990 and some 500-800 HMCFD by che year 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 (from identified Union Oil fields) would be only 250-400 MMCFD in 1990 and 150-200 MMCFD in the year 2000. Since the very recent surge in Erawan production, and on the strength of Union Oil's accelerated drilling program, which will extend into the next fiscal year, Union Oil's total production from presently contracted fields (PPAM, para. 40) can now be expected to reach some 500 MMCFD by 1985 and to remain sustainable at this level until about the mid- nineties. New already identified Union Oil fields, if timely brought on stream (under a new contract), could by that time make up for the subsequent production decline from Union Oil's presently contracted fields and maintain a production level of some 500 MMCFD to the year 2000. Depending on avail- able pipeline capacity, production agreements and gas market, this number could conceivably be topped off by production from Texas Pacific and other not-yet-identified Gulf fields.44/ While aggregate production from the several fields would hence be sufficient to match the appraisal forecasts, production only from the fields assessed at appraisal and considered as the basis for the project (Erawan and Texas Pacific) would have been greatly below the forecasts for those fields. Thus, the final production outcome of the project is positive, but albeit through cicumstances different from those assumed at appraisal. In similar future circumstances, a more comprehensive analysis of the factors bearing on production seems desirable. In particu- lar, more attention might be given in future to gas sales agreements between concessionaires and the Government, which as much as adequate reserves in the ground, 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 the Korat Basin in the Northeast have also lately improved. Information about the scope of commercial quantities is yet inconclusive, but the reserves are expected to be large enough to significantly affect overall gas supplies. Present production on-shore is about 30-40 MMCFD and being 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 for bringing about the desired gas sales agreements other than through vari- ous post-appraisal interventions by supervision missions, both with Thai authorities and reservoir consultants. In the view of the operational division in the Bank responsible for the project, the IOC in question was unwilling to come to terms with the Thai Government at a price acceptable to the Government. If this be so, there still remains the question why the IOC maintained or maintains such a posture, whether the posture could have been anticipated at appraisal, and whether a differ- ent project design could have resulted in a different posture. - 18 - 40. Two gas contracts are currently in force, both with Union Oil---t:,e first, signed in 1978, for Erawan gas, and the second, signed in 1982, for gas from Kaphong, Platong, Pladong, Satun and Baanpot. The first contract was negotiated against the background of a certified volume of economically recoverable gas4 / and at the time expected fairly low production cost, with the full field development costs and risks carried by the oil company. The second contract, which was also negotiated before the full extent of the Erawan situation became apparent, was in substance and format tailored after the first.47/ Negotiations between Government and Texas Pacific were held with interruptions since 1978, though differences on some issues were nar- rowed. Among the earlier sticking points was the price of gas. Since the experience with Erawan, the volume of reserves and the gas recovery cost have become 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 gas field development cost and risk. With future Union Oil gas likely to claim full existing transmission capacity, temporary limitations on Thailand's absorptive capacity for gas48/ and still unresolved questions about the vol- ume of economically recoverable reserves, a near-term break-through on Texas Pacific gas does not appear to be in the offing, although it is difficult to make 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 not appear to exercise the same influence over the second (Union Oil) contract and particularly the negotiations with Texas Pacific.49/ Bank staff have advised OED that they attempted, on various occasions, to accelerate the pace and shape the outcome of the negotiations held after 1978, though the Bank was not a direct party to them. The Bank's role in these negotiations is not entirely clear from the documents available to the audit. Government officials, in comments to the audit mission, expressed confidence in the 46/ As noted above (PPAM, para. 23), the certified proven reserves were 1.1 tcf. This certification which was a condition of effectiveness for the Union Oil-PTT contract and cleared the way for Loan 1773-TH, was later revised, first upwards and thereafter downwards. 47/ Observers are now puzzled that Union Oil was agreeable to signing the second contract in the face of developing production problems under the first contract. 48/ Thailand is agreeable to accepting Union Oil's proposed increased pro- duction over current levels only after having made arrangements for sale of the surplus fuel oil, a result of the present refinery configuration. 49/ Bank staff state that they did, however, influence the second Union Oil contract and the negotiations with Texas Pacific although, of course, there is still no Texas Pacific contract. - !' - Government's own handling of the co.L.act negotiations. In any case, the Government has quickly asserted itself as its own independent decision maker in 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 not only by itself but in relation to the level of investment (US$514 million projected) was an extraordinarily high figure. Public sector returns of this order are uncommon for even low levels of investments. 43. The principal parameters, from which the ERR was derived, were the gas production volumes, the economic value of gas,51/ the investment cost5Z/ and the net gas supply cost (the well-head cost net of income taxes, royalties and gas condensate). Gas production, as noted above, has fallen short of projections for the first three years, but can now be expected to be on target. The economic value of gas and the (net) supply cost were appar- ently53/ underestimated, as established by the Energy Pricing Study, which 50/ The Government obtained professional guidance in negotiating tactics from consultants financed under this project. A study of gae purchasing strategies by the Government was also included in Loan 2184-TH. This study has made no progress yet and is reported as pending. Supervision Report, Loan 2184-TH, January 9, 1984. The Government is aware of crit- ical comments made in the international press about the time taken for reaching agreements with IOCs. Based on expe-ience gained, Government officials are confident that the time needed in future negotiations will be less than in the earlier ones and that the international community will 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 cost equation. 53/ The PCR provides information on the value of gas and the supply cost only in current terms, without information on the implicit rates of price inflation in the SAR estimates and PCR reestimates respectively, thus obscuring a comparison between SAR and PCR in constant terms. - 20 - 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 energy alternative to gas), rather than with the lower opportunity cost of a mix of fuel oil and lignite.55/ The investment costs were, as also noted earlier, overestimated. On balance, the overall structure of benefits and cost, as projected in the SAR, has remained fairly undisturbed by the parameters' changes.56/ 44. Primarily because of slow initial gas production, economic benefits are so far lagging far behind the SAR projections. The project's economic impact is therefore still weak, and the foreign exchange savings have so far been modest. In the long run, over the life of the investments and the gas reserves, 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, in 1983 prices, at US$4.OO/MMBTU; the well-head cost at US$1.60/MMBTU; the net supply cost at US$1.00/MMBTU; and the margin of economic value over the supply cost, accordingly, at USS3.OO/MMBTU. All these values were recalculated in the Energy Pricing Study, which estimates the economic value of gas for the same reference years at USS5.00/MMBTU, if derived from the fuel oil comparator, and USS4.OO/MMBTU, if derived from the lignite comparator; the net supply cost, at USS1.70/MMBTU (for Union Oil gas); and the margin of economic value over the supply cost, accord- ingly, at between USS3.30/MMBTU (based on fuel oil comparator) and USS2.30/MMBTU (based on lignite comparator), with a mid-point of USS2.80/MMBTU. In contrast to the Energy Pricing Study, the PCR in para. 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-based energy supply has the same cost and energy output characteristics as the fuel oil or lignite-based supply. The study's net supply costs are actually 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 in the power sector and (ii) substitute exclusively for fuel oil, the appraisal equated the value of gas with the opportunity cost of imported fuel oil. While the first assumption was fully valid, the second was valid only in part: without expected access to gas, EGAT might have accelerated the shift to lower-priced fuels (in particular lignite and imported coal), rather than to remain strongly exposed to international oil markets. 56/ Under- and over-estimates partly cancelled each other. 57/ Gas production assumptions: actual gas production 1982-84; 500 MMCFD throughout 1985-2000. The assumptions in the PCR (para. 5.02) are, in some years, slightly below the audit's assumptions. - 21 - 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 a variety of unfavorable project assumptions and that only lasting catastrophic events (such as lengthy interruptions of gas transmission) could seriously jeopardize them. The ERR, for example, would not fall below 40%, if the peak pipeline throughput was only 300 MMCFD (rather than 500 MMCFD), and if throughput was discontinued by the mid-nineties, falling from an assumed ceiling of as low as 300 MMCFD in 1990.59/ Further, the ERR would not fall below 20Z, if the net gas supply cost (through an increase in gas purchase cost, for example) was as much as doubled, or not below 30%, if lignite exclusively was the relevant gas comparator. 45. The project's economic viability is reportedly in sharp contrast to the financial rates of return (FRR) currently expected on the IOCs' invest- ments. No return has yet materialized for Texas Pacific, and the long-term financial rate of return for Union Oil, according to its own projections, supposedly will not even reach 15%60/: this return is to a large measure governed by the cost of developing th_e gas reserves, which are substantially above the level anticipated when the first and second gas contracts were negotiated.61/ Total Union Oil investments for the first and second con- 58/ Streams of economic benefits and costs, on which economic returns are calculated, should be given in project documents in constant terms with an explicit statement of the base year, to conform to normal practice. In case of the project under audit, both the SAR and PCR give the streams in current terms only. Constant (monetary) values should be given irrespective of whether there are also reasons to present current values. 59/ Such a low throughput would only be conceivable if the Union Oil first and second contract fields were less productive than currently expected and no third Union Oil contract materialized and negotiations for Texas Pacific gas failed. Such a combination of events is most unlikely. Evacuation of Gulf gai to Surat Thani in the South to feed an EGAT power station is also under consideration, but only if there is ample supply of Gulf gas. The Surat Thani pipeline, which EGAT would be prepared to finance, 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 be reviewed by the audit. According to Bank staff, Union Oil's financial rate of return expected in 1978 was "embarrassingly high", even though the company kept its project economics -secret". The recalculated return was released shortly before the opening of discussions on the third Union Oil contract. All this does not alter the fact that Union Oil states that the return, as projected at present, is unsatisfactory. 61/ The issue of retention of funds payable by PTT, brought ahout by Union Oil's inability to deliver agreed volumes of gas, has recently been resolved (PCR, paras. 3.07 and 7.02). - 22 - 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 gas delivery system financed by the public sector.63/ The company states that the 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 project assumptions, safeguards against non-viability were never much of an issue. The more pertinent issue was, whether the project would be designed and managed to fully use its economic potential. In the narrow sense of the investment analysis, Thailand appears to have been very successful. Union Oil gas from the first and second contracts is projected to fully use pipe- line capacity for years to come, and the gas transaction price, negotiated before the full extent of development cost became apparent, is low. In a sectoral sense, which is not fully captured by the project's economic analy- sis, the question is, whether the project's maximization of benefits is in the country's long-term interests. Perceptions of inadequate and unfairly low 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-half of this amount may have been spent. As the first and second contract fields will not be sufficient to feed the pipeline continuously to capacity, total private sector investments related to the project may ultimately exceed US$2 billion. According to Government sources, Union Oil may have invested already USS1.3 billion to date. 63/ Including the ADB-financed pipeline (PPAM, para. 28), public sector investments would be about US$555 million. Public sector downstream investments, such as LPG plants, raise of course substantially the public sector's financial commitments related to gas. 64/ The PCR (para. 3.10), In reference to Union Oil, calls the project a commercial success. The audit was informed by officials of the company that Union Oil does not agree with such a conclusion. - 23 - as Government attention in their mutual efforts to enlist private sector assistance for gas exploration and development.65/ 47. The audit has noted the dichotomy in project control arrangements for 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 to internationally experienced firms, consistent with Bank guidelines to promote efficiency, and the Bank monitored the adequacy of implementation arrange- ments. Completion on schedule was made imperative through the take-or-pay provision (though one could argue that PTT was put into a very tight position). In contrast, provisions for generating and sustaining benefits were neither as rigid nor as comprehensive. The project did not set condi- tions clearly designed to produce new field development agreements, nor did it monitor progress by defined milestones to ensure that gas would be pro- duced when and in the quantities needed.66/ Only the gas supply contract for Erawan became an integral part of the project, but not the cont:-act for Texas Pacific, for which nonetheless in the economic analysis benefits were 65/ Bank staff state that nowadays, Bank attention is being given to IOC's rewards, including in the Bank's (still ongoing) Energy Assessment for Thailand, and that the issue of IOC rewards was the subject of project supervision missions and new project preparation missions. In the con- text of the project under review, the audit could not clarify in what way the Bank dealt with this project in the past and how Bank concern with the issue of the IOC rewards was documented.--According to Govern- ment sources,, a reexamination of laws and regulations pertaining to exploration and development of hydrocarbons is underway to ensure that they are fair and realistic in the current environment and provide incentives to investors consistent with national interests. Particular attention is being given to established pricing policies, whose absence to date, in its judgment, has slowed negotiations with several oil or gas companies with interests in Thailand. 66/ Bank staff report that the Government refused the concept of defined milestones on the grounds that the Petroleum Law made information about field development secret. The audit notes that not all elements of 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 other Government-Bank lending agreements, amendments to laws by the legisla- ture have been made. The audit mission in 1984 had no difficulty obtaining thorough briefings by Union Oil about details of its future field development plans. - 24 - calculated.67/ The reliance on -self-generating benefits seems to be paying off under this project, after some initial struggle, but may not be appropriate 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. While taxes and royalties payable by the oil companies, because of the modes of payment, 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 price below that of the chosen fuel comparator (fuel oil), would make the power sector a project beneficiary. Making gas available to EGAT at a price equal to the comparator would make PTT the sole beneficiary until the treasury would claim its share of the gas revenues.68/ 49. To promote energy efficiency, ensure financial soundness of the borrower (PTT) and generate Government revenues, the Bank, during project preparation and negotiations, argued forcefully for closely linking the PTT- EGAT gas transfer price to the chosen comparator (fuel oil). Showing for its part little enthusiasm for a new fuel whose financial cost would be about as high as those of the alternative (supposedly fuel oil), EGAT aimed at a gas transfer price which was noticeably below the price of the (fuel oil) compar- ator. At project negotiations, the Thai delegation reported69/ that PTT and EGAT had reached agreement- on a (1978) gas price, which was about 90% of the (1978) price of fuel oil, and it agreed to propose to the Government the same pricing formula in future PTT-EGAT transactions. The delegation argued that the gas price should provide a modest incentive to use gas rather than fuel 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 (at 10% discount rate, 1978 base year) was US$1,800-1,900 million, if all projected Union Oil (Erawan) and Texas Pacific gas was taken into account; and US$1,250 million, if Texas Pacific gas was excluded. Accordingly, the production agreement for Erawan gas protected an estimated two-thirds of the project's total net present value (US$1,800-1,900 million). Of course, there was the subsequent shortfall in Erawan gas, which will substantially reduce that field's actual contribution to the net present value. Because contract negotiations went slowly, Texas Pacific was delinked from the project after the Decision Meeting: project processing was not supposed to be held up until a gas production agreement had been reached. 68/ It was understood that the treasury would, in due time, claim part of the benefits after they had accrued to PTT. 69/ Minutes of Understanding, para. 9. - 25 - 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 prematurely concluded in the President's Report, that the PTT-EGAT sales agreement would set the gas price at a level close to 90X of the international fuel prices.70! Nonetheless, to safeguard the conclusion, negotiation of a legally 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 because of 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 in early 1981, made no explicit reference to the 90% fuel oil parity but con- tained indirect linkage with international (Singapore) fuel oil. The Bank raised no objections to the contract terms and implicitly sanctioned the absence of the parity clause stipulated earlier. Under the Liquified Petro- leum Gas Project (1982), this time being fully consistent with its most recent stance, the Bank agreed to a provision, under which natural gas was to be priced substantially in accordance with the 1981 PTT-EGAT contract. The issue of a numerically specific parity was not revived again under the two SALs (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 been reported. Indications are, it could have been 80% or below. In 1983, it was about 732. In 1984, it may have been about the same.72/ Bank staff explain that the issue of a close fuel oil-gas price parity has not faded, as it seemingly has, but was somewhat kept in abeyance pending the outcome of a follow-up study to the Energy Pricing Study. The follow-up study, now near completion, 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 ensure that the price of gas to EGAT is maintained at a level close to 90Z of the international fuel price-, -are incorporated into the PTT-EGAT sales agreement.--The 90% (rather than a 100%) parity was explained with reference to the 90% parity of 1978, which apparently took account of EGAT'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 disbursement was 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 comparable fuel oil price could have been close to US$5.00/MMBTU (PPAM, footnote 54). - 26 - reported as reconfirming the need, for years to come, for pricing EGAT gas at the full opportunity cost of fuel oil. Despite falling short on the stated pricing parity objective, Bank staff express satisfaction at the gas pricing levels actually achieved so far, as the levels attained could have been even lower. In their view, even though the Bank had firm grounds for aiming at a 90% parity, there was merit in restudying the issue in light of more recent developments. The audit has the impression that the Bank's position on gas pricing was ambiguous, and the audit has not found the basis for such a posture. A well-reasoned, clear and consistent position would enhance the effectiveness of the Government-Bank energy policy dialogue.73/ 52. While the project set out to minimize potential financial benefits to EGAT (and electricity users), it was designed to make PTT's Office of Natural Gas (ONG), if not PTT itself, within a short time financially power- ful. Matching the enormously high economic return on the public sector investment, ONG's rates of return on net fixed revalued assets were projected to rise from 9% in 1982 to 152 in 1984, 24% in 1990, 43% in 1995 and 187% in 2000.74/ Cash balances would develop in a similar fashion. ONG/PTT's finan- cial fortunes were even more remarkable, as the project contained no specific provision for transforming ONG revenues into treasury revenues. Rates of return 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 Government controls, and the companies are frequently under a profit and financing squeeze. Several incur chronic losses. While the objective of ONG's finan- cial prosperity may have seemed desirable to assure its financial health to safeguard financing of future natural gas investments and to avoid the 73/ Bank staff now emphasize that the actual PTT-EGAT gas price, in their view, will not fall below 70% of the equivalent fuel oil price, based on their reading of the PTT-EGAT pricing agreement. Assuming this reading is correct, the question remains, of course, about the justification for claiming an agreed 90% parity in the President's Report. Bank staff also informed the audit that in the Government's view, the Bank should not 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, which was supposedly agreed at negotiations (PPAM, para. 49), the financial analyses for ONG were based on a constant 67% parity throughout 1982-2000 (SAR, Annex 3.02, Annex 5.02 and para. 3.07). The choice of the 67% parity was unexplained. If the 90% parity had been incorporated into the SAR's financial analysis, ONG's rates of return on assets and cash balances would have by far exceeded the already very high results actually projected. Also, the (real as opposed to nominal) financial rate of return for ONG would have been well above the 15% given in the SAR (para. 5.04). - 27 - chronic financial problems of other public sector enterprises, it could potentially breed excessive investments and inefficient operations, and it was seemingly inconsistent with the Government's budget situation and the fiscal objective of the PTT-EGAT gas pricing structure. There have been sad instances of financial problems with public sector hydrocarbon enterprises in several 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 of initially poor gas production, the arrival of ONG/PTT's financial prosperity has been delayed by several years, and little concern about a financially excessively endowed ONG/PTT is justified at present. On the contrary, PTT currentl5 faces a situation of tight liquidity and unsatisfactory profit- ability. 7/ 761 Bank staff advised the audit that the issue of transfer of funds was addressed in the Liquified Petroleum Project (Loan 2184-TH). Bank staff are of the opinion that no special fiscal provision was needed under Loan 1773-TH because the PTT Act requires that all [PTTJ profits be transferred to the Thai Treasury-. Technically, Bank staff appear to be incorrect as the PTT Act of B.E. 2521 (A.D. 1978, published in the Government Gazette, Volume 95, Part 152, dated December 28, 1978), refers only to that PTT revenue balance as being payable as -State revenue-, which remains after deduction for operating expenses and various commitments as appropriate, e.g., ...reserve funds... and investments...". The creation and use of reserve funds are subject to the approval of the fIT Board of Directors. The PTT investment budget requires approval by the Council of Ministers. What this means, in practice, is, for example, illustrated in the Office of the Auditor General's Report on the Petroleum Authority of Thailand as of September 30, 1983. In that report, the FY83 net profits of PTT were given as about Baht 1,066 million, while revenues transferred to the treasury were about B107 million. It would, however, be correct to say that the Government, through the PTT Board of Directors (consisting of high- ranking Government officials) and the Council of Ministers exercises control over the utilization of PTT net profits. In this light, the practical question of importance therefore would be, whether the consid- erations of fiscal revenues and financial discipline are better served through the initial transfer of all or substantial parts of net profits to the treasury, followed subsequently by suitable arrangements for financing future PTT activities, or through initial retention by PTT of those parts of the net profits deemed necessary for PTT and the subse- quent, if any, payments of residual funds to the treasury as 'State revenues-. 77/ PCR, Chapter VII and Supervision Reports for Loans 1773-TH and 2184-TH. - 28 - IX. CONCLUSIONS 53. The project was conceived as a major building block in the strategy to shore up the economy against harmful developments in the international oil markets. 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 to international oil prices. The project further served as a vehicle for devel- oping institutional expertise in natural gas (through PTT staff training) and rationalizing various sector policies. 54. The projqct estimates of specific gas production volumes have not yet been achieved. However, natural gas from the Gulf is now on the thres- hold of living up to expectations, and in combination with other indigenous energy supplies (lignite and on-shore gas) and demand-based policies, has moved the country close to a manageable energy-import dependence.78! Insti- tutional expertise in gas has been broadened, to some extent, through the project's formal training programs, and presumably to an even greater extent through the sheer exposure to the project and follow-up operations. Energy sector policies were also developed under the project, or where the project left off, through substitute arrangements. 55. Experience under the project emphasizes the long lead time in restructuring energy supplies and the need to take long-term energy perspec- tives. Gulf gas exploration, preceding the project, spanned over a period of some ten years, and project preparation and implementation, which by any standard were speedy, took some additional four to, five years. A further two to 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 was initiated well before the 1973/74 oil events forced a rethinking of energy policies. 56. The project was built on a marriage of public and private sector interests. The public sector's main contributions to the production of gas were the fiscal and regulatory frameworks for gas exploration and develop- ment, the transmission system and market outlets for gas. The private sector committed 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$2.5 billion. The scope of the Government's financial commitment under the pro- ject, in conjunction with downstream investments (such as LPG plants), was in earlier Bank discussions viewed with concern because of other sectors' justi- fied claims on the country's scarce financial resources. However, it was rationalized in light of the IOCs' reluctance to increase their exposure. 78/ The Bank's ongoing Energy Assessment is expected to provide quantitative energy supply-demand scenarios. - 29 - The argument has also been made that Government ownership of the transmission system would enhance the Government's negotiating position with the IOCs. At the Government's option, the system would, in principle, be available for gas from any field, which may not be the case if individual IOCs controlled it. 57. The project has confirmed the general wisdom that development of indigenous natural gas can be economically most rewarding. The potential for economic gain is, of course, in particular high, if gas, as it was here the case, is to replace high-priced oil products. Despite possible snags, some of 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 below the opportunity cost of capital. 58. Given the project's low propensity for economic failure, the challenge was rather to fully use its economic potential. Considering the project context only, the project appears to perform very well: gas produc- tion, after initial shortfalls, is likely to use up existing transmission capacity, and the gas well-head cost under existing contracts are favorable to Thailand. In the broader context of Thailand's oil and gas sector, the conclusion is less obvious. Union Oil, the project's only gas producer at present, argues that its investments may end up relatively unrewarding, and this 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 exploration and field development could be costly, if not unavailable, if mobilized by the public sector. 59. After a 20 years' focus on electric power, the Bank, with this project, broadened its involvement in Thailand's energy sector. Bank financ- Ing, by providing informal cover against non-commercial risks, helped set the stage for private sector funding of gas development, it provided the back- ground for the Bank's operational assistance to the Government, and it opened new doors for Government-Bank dialogue on energy policies. The Bank also established good relations with Union Oil, a necessary condition for an effective Bank-private sector cooperation in Thai energy development. Wheth- er the full scope of Bank financing, US$107 million, was needed to accomplish all this, is debatable. Operational assistance was fruitful in the context of implementation of the physical infrastructure. Well established proce- dures for implementing large civil works proved effective in controlling cost and meeting a tight schedule. Operational assistance in sizing up gas reserves was not fully effective. On this experience, the Bank may wish to review procedures for designing and evaluating reserve assessments. Fore- casting for gas production could also be improved and sustained generation of project benefits could be enhanced, under new lending operations, through increased attention to gas production agreements. Conditions bearing on pro- duction agreements could be reviewed in more depth at appraisal, if not shaped under the project. A related issue is the framework of public and private 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 lessons has also been learned from the project about improvements in presenting - 30 - information in project documents. A main lesson, now being recognized in current Bank practice, is to routinely discuss project objectives in the SAR and the President's Report. In its campaign for economically correct energy prices, the Bank succumbed to the exigencies of project implementation. Less ambiguity in the Bank's position could make a Government-Bank policy dialogue more effective. ATTACHMENT - 31 - COMMENTS FROM THE GOVERNME ZCZC DIST 0886 RCA 4006 OEDOD REF: TCP FCA 01341 03-11 1047A EST TLX 71248423 248423 WORLDBANK BT 1-107065G070 03/11/85 ICS IPMIIHA IISS PMS WASHINGTON DC WUB6071 TUR062 DSX249 TNX 055 BKTN200126 OFFICE OF THE PRIME MINISTER 48/44 11 1430 MR. YUKINORI WATANABE DIRECTOR, 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 PAKKASEM COL 1818 20433 1773 ,I-' 1l U4 ~Aj - 33 - PROJECT COMPLETION REPORT THAILAND: SECOND NATURAL GAS DEVELOPMENT PROJECT (LOAN 1773-TH) I. Introduction 1.01 The rise in crude oil prices in 1973 prompted the Government of Thailand to stimulate petroleum exploration, particularly in the offshore areas. During 1975-76, two important natural gas discoveries resulted, both in the Gulf of Thailand. Union Oil Company found gas in what was then known as the "A" structure (now called the Erawan Gas Field), located in the central portion 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 Oil discovery in what is called the "B" structure. Both discoveries were believed to have tapped reservoirs of sufficient size to be commercially exploitable, and discussions were begun on marketing the gas. However, serious negotiations were, from the very beginning, limited to the Union Oil discovery because it was recognized that the initial phase of natural gas development in the 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 to mid-1976 when an energy mission visited the country to assess the possibilities of developing the offshore gas discoveries. It turned out that the Government was very interested in Bank assistance for the preparation and financing of such a project, and as a result, a close working relationship developed. Major results of the Bank's involvement were a market and feasibility study, the hiring of a consultant to assist in gas sales contract negotiations, and the establishment of a national gas company, the Natural Gas Organization of Thailand (NGOT) in March, 1977. 1.03 By late 1977, it became apparent from enco-araging drilling results in the Union Oil and Texas Pacific areas that there were commercial-size gas reservoirs in the Gulf. It was also obvious that a project to develop and utilize the gas was a matter of urgency in view of the country's dependence on imported oil. The Government consequently requested a Bank loan of $4.9 million to finance the various preliminary activities essential to the preparation of a natural gas development project. The engineering loan (S10- TR) was negotiated in February, 1978, but Board presentation was delayed until July 11, 1978 because Union Oil and NGOT did not meet until then a Bank condition requiring their prior agreement on a sales contract. The loan became effective on September 25, 1978 and provided for projoct design and engineering, preliminary implementation services, financial management advisors, gas reserves appraisal, consultant services and training. This prepared the -day in 1979 for a follow-up loan (Loan 1773-TH) which refinanced the earlier engineering loan and helped finance the pipeline and other facilities needed to transport, treat and market the natural gas from the Erawan field. Loan 1773 was approved on December 11, 1979 but did not become effective until March 27, 1981 when the Electricity Generating Authority of Thailand (EGAT) signed a contract to purchase the Erawan gas, a condition of loan effectiveness. The delay in effectiveness resulted from protracted negotiations over the price EGAT would pay for the gas. - 34 - 1.04 This report is based on reports and documents in the Bank's files and on the findings of a Bank mission that visited Thailand in January 1983 and on information furnished by the Borrower. It covers the initial engineering project (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 1.0 trillion (million million) cubic feet (tcf) of proven recoverable reserves would be established and certified by an independent reservoir evaluation before the agreement became operative. This required Union Oil to drill four more 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 0.4 tcf probable was accepted by both parties as the legal reserves of the field. Union Oil subsequently drilled an additional two appraisal wells on the flanks of the Erawan structure; this raised the estimated proven reserves to 1.58 tcf. At the same time Union was drilling and discovering a number of gas bearing structures which substantially strengthened project confidence. The Erawan gas sales contract allowed both parties 36 months, after acceptance of the gas reserves estimate, to prepare their respective facilities for producing, transporting and marketing the gas. However, an earlier date of September 15, 1981 was subsequently agreed on as the date when gas sales would begin. 2.02 Preparation work on the project proceeded in parallel with further appraisal drilling and reservoir evaluation in Erawan and elsewhere, and project appraisal took place during March, 1979. On July 15, 1979, the Petroleum Authority of Thailand (PTT), established December 28, 1978, took over NGOT and Its entire staff. This necessitated a post-appraisal and caused Board presentation to be delayed until December 11, 1979. The project was defined to include the following principa. .:omponents: (a) a 34-inch offshore buried pipeline from Union Oil's production platform to landfall, approximately 425 km long; (b) a 34-inch onshore pipeline from landfall to a terminal a short distance inland, and a 28-inch buried pipeline, approximately 170km, to the EGAT power stations at Bang Pakong and South Bangkok; (c) infrastructure, comprising metering, hydrocarbon dewpoint control, communications, supervisory control, telemetry, maintenance and office staff support facilities at the terminal and an operations' center at Chon Burl; and (d) technical assistance, project management, consultancy, training and studies. - 35 - III. Implementation Background 3.01 PTT was responsible for implementing the project, primarily through its Office of Natural Gas (ONG). For its engineering consultant PTT appointed one of the major US engineering firms whose assignment included engineering, project and construction management, training and start-up. Because of the size and complexity of the project and PTT's inexperience, the modus operandi for carrying out the project placed responsibility for initiating and executing project implementation activities on the engineering consultant and the normal client supervisory and approval responsibilities on PTT. 3.02 The gas sales agreement with Union Oil included take or pay provisions which could have amounted to US$500,000 per day if PTT was not prepared to take delivery on the contract date. This made it crucial to complete the project in time to allow "running-in" operations to begin by September 1, 1981 and to start contract sales on September 15, 1981. The completion schedule was met but it took great effort to do so. Sufficient time was allowed in the schedule to complete construction and commissioning at, what was then thought to be, an acceptable pace. However, all the slack in the schedule was eventually lost because of the procurement procedure which had resulted in slow decision and approval action by PTT and its board. It ultimately became necessary to resort to crash program tactics to finish the project on schedule. The fact that the project was completed on time speaks well for all those connected with its implementation, especially the engineering consultant who bore the brunt of the responsibility for expediting and keeping critical activities on schedule. 3.03 The construction phase proceeded smoothly except for problems normally encountered on a project of this nature. Two of the more serious were connected with the installation of the pipeline. On the offshore portion, several leaks were discovered in a section of the pipeline already underwater, and on the land portion which traverses a rice paddy area, difficulty was experienced in maintaining the pipe at the proper burial depth. Neither of these problems was sufficiently serious to threaten the project schedule. 3.04 Union Oil's development program also proceeded according to plan during the installation of offshore structures and drilling operations, but ran into serious problems from then on. The first gas delivery started on schedule with 15 weils completed. However, Union Oil soon discovered that several wells were showing unusually steep pressure declines and could not maintain the required flow rates. The situation became further exacerbated by the failure of the dual completion packers due to higher bottom hole temperatures than had been anticipated. Despite the replacement of the packers with ones suitable for the temperature and other efforts to increase production, the rate for FY82 only averaged about 120 MMCFD. According to the sales contract, the daily contract quantity (DCQ) should have been increased to 250 MMCFD in July 1982. However, the contract stipulates that Union Oil's gas delivery obligation is limited to 1/6,000 of the field's recoverable reserves, and it was on this point that Union Oil based its claim that the DCQ agreed to in the sales contract could not be sustained. - 36 - Gas Reserves and Deliveries 3.05 Development drilling and three dimensional seismic data accumulated since the reserves evaluation suggest that the original estimate1 ight be overly optimistic. The fault blocks appear to be more numerous - than expected and there is evidence that the producing zone consists of many different reservoirs separated by water bearing strata. Individual sands appear to have different gas/water contacts with many lateral discontinuities. Union oil, on June 1, 1982, submitted a report to PTT downgrading the remaining proven and probable reserves of Erawan to 0.489 and 0.197 tcf, respectively, with a corresponding reduction in DCQ to 82-114 MMCFD. On the other hand, an independent reservoir study on behalf of PTT in August 1982 estimated remaining proven reserves at 1.353 tcf with an equivalent DCQ of 225 MMCFD. 3.06 In view of the conflicting reserve estimates, and in accordance with the gas purchase agreement, PTT and Union Oil commissioned the consultant who established the original legal reserves to carry out a reevaluation based on all 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 Ultilmte Reseryoirs Pcoducticn Reserves RecDvery Reserve Deteinatic e thod) Cbs Liqud Gas I;lquid Gs Liquid Prod. Reservoirs (Materal Balance) 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 1.4 Pmd. 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 and 309,000 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. - 37 - These results supported Union Oil's claim that gas reserves and the corresponding delivery rates should be reduced from the levels originally agreed to. PTT refused to accept the revised reserves claiming that the evaluation was incomplete because an appropriate analysis was not made of the development and production costs to Union Oil in determining the maximum reserves which could be recovered at the contract price. Such a detailed economic analysis was not carried out. However, the consultants could only base the evaluation on data and instructions received from the client, in this case PTT and Union Oil jointly. Without specific instructions to do otherwise, the consultant interpreted the data and arrived at the reserves estimate in accordance with standard practices in the industry and Union Oil's development program. Given the revised representation of the reservoir's production zones by the 3-D seismic survey and the production history, the downgrading of the original recoverable reserves appears to be technically justified. 3.07 During the ensuing dispute over reserves and delivery shortfalls, PTT withheld approximately 20X of the contract price, based on the reduced price it would have paid for the higher sales volumes it should have been receiving. In June, 1984 a settlement was reached and the contract amended to reflect the existing reservoir performance (see para. 7.02 for further details). 3.08 In the meantime, Union Oil has continued to develop the Erawan field. By end 1983, 63 wells from 7 platforms were in production, and by early 1984 the 8th platform was installed for additional drilling. During 1983 Union Oil was able to maintain an average production rate of about 140 MMCFD of Erawan gas by puttir.g new wells into production and by adding compression when reservoir pressure decline made free flow impossible. Production has stabilized and should be sustainable for several years until after the main supplies from the next contract come on stream. 3.09 The performance of Erawan field raises the question of whether a more conservative approach should have been taken in evaluating the field's production capacity and economically recoverable reserves. In fact, every measure 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 and within the budget, to fulfill its contract commitments, and similarly Union Oil completed the production facilities to deliver the contract gas. Proper steps were taken to minimize risk. The reservoir did not live up to expectations, and as a result gas supplies from the field had to be scaled down to about two-thirds of the original goal. Nevertheless, the project has proved to be a commercial and economic success, even for Union Oil whose development and production costs greatly exceed original estimates. A second sales contract was entered into by PTT and Union Oil in May 1982 for the - 38 - supply of 150 MMCFD of gas from five fielda/ in the neighborhood of Erawan with provisions to increase the supply to 200-300 MMCFD in 1986 and 400 MMCFD in 1987, depending on reservoir performance. A contract amendment was signed in April 1983 advancing production from Baanpot (one of the five neighboring fields). Gas delivery from this field started on October 31, 1983 at the rate of 12 MMCFD and reached 20 MMCFD by end 1983 and is expected to reach 40-50 MMCFD, the maximum expected rate, by mid-1984. With the new Union Oil supplies coming on stream, PTT can expl7t by mid-1985 gas deliveries in the range of the pipeline design capacity__ 3.11 At project appraisal it was envisaged that 250 MMCFD of gas would be supplied by Union Oil and 250 MMCFD from the Texas Pacific (TP) field about 170 km southeast of Union Oil's central production platform. The Platong and Kaphong 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 with PTT, and other attempts to market the gas, such as through a joint venture with the Government or LNG export ventures, have also met with no success. At last report (February 1984) TP was negotiating a gas price with the newly created Committee for Negotiations on Petroleum Joint Ventures and Pricing headed by a minister fr"m the prime minister's office. At the same time, both parties recognize the cisadvantage of the existing form of contract and are actively considering "n alternative approach suggested by the Bank. Both sides 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 $347 million foreign) including interest during construction. Union Oil's estimated expenditures were about $300 million, but by end 1983 the company spent an additional US$300 million for platforms, wells and workovers not originally anticipated. In addition, Union Oil will have to make a substantial investment to produce the remaining recoverable reserves from Erawan 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 underrun were made by contracts, freight, taxes and import duties and the unused contingency funds, the latter amounting to $64 million (70%) of the underrun. One of the main causes for the underrun was the fact that the three major pipeline contract costs were substantially below estimates as a result of prevailing market conditions and keen competition for these contracts. A share of the underrun can probably also be credited to good project management and 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 the addition of compressor stations. - 39 - 3.14 The cost of project engineering and management services exceeded the estimate by $22 million, about 100l. Unanticipated heavy staffing of expatriate manpower to keep the project on schedule accounts for some of the overrun. In addition, the consultant's fees, although consistent with those charged its other clients, were much higher than the Bank expected from experience with similar project assignments. 3.15 A summary of the project financing is set out below: Current Current Estimate/ Appraisal Estimate Appraisal (%) IBRD 107 107 100 Export Credits 180 125 69 Commercial Banks 150 125 83 Government 77 51 66 Internal Cash - 15 Total 514 423 82 Export credits (U.S., Japan) funded a significantly smaller proportion of the project costs than the appraisal estimate. In addition to cost underrun, this was mainly because the goods and services procured from the U.S. fell short of expectations, resulting in reduced drawdown ($41 million) from the U.S. Export-Import Bank which had committed to extend a $75 million crt t for the project. Delayed effectiveness of IBRD loan and U.S. Export Credit necessitated bridge financings from commercial banks during the project construction period. Notwithstanding a project cost underrun, the IBRD loan was fully utilized. This was the result of a reallocation of Bank loan in 1981 to cover an additional item, namely pipe coating, in order to help alleviate PTT's liquidity problem then. ONG's funds flow during the project construction period is further discussed in para. 7.04. The unexpected contribution of PTT's internal cash helped to retire the bridge financing in FY82. The Government has not yet paid its equity contribution equivalent to the import duties and taxes. PTT submitted a formal request for this in January 1984. This issue has been raised by the Bank with the Ministry of Finance 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 along with the original disbursement schedule. The 15-month delay in disbursement was due to late compliance with a condition of effectiveness in the Loan Agreement, namely the conclusion of a satisfactory gas sales agreement between PTT and EGAT. Once it started, disbursement closely followed the original schedule which can be considered to represent a typical profile for this type of project. - 40 - Use and Performance of Consultants 3.17 PTT and its predecessor, NGOT, made extensive use of consultants in preparing and implementing the project. All together PTT employed 13 different consultants to assist in various aspects of project implementation, training and studies. The project also included provisions for carrying out energy convervation studies covering such aspects as an energy audit, an investment program for energy savings, policies for energy demand management and future investments in energy conservation, including non-conventional sources. GOT subsequently arranged other financing for these related activities. At the time of preparing this report the following studies were either completed or in progress: ti) an energy audit by the National Energy Administration (NEA) and the Asian Development Bank; (ii) an energy conversation (industrial incentives) study by NEA agreed upon under the Bank's Second Structural Adjustment Loan; and (iii) a transport energy conservation study by the Ministry of Communications. An energy conservation center financed by private industry and also agreed upon under the Bank's SAL was in progress 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 consultants pprformed their assignment in a generally satisfactory manner, but as explained in para. 3.06, PTT was not entirely satisfied with the reservoir reevaluation it commissioned jointly with Union Oil. The performance of Erawan field raises the question of whether a more conservative approach should have been taken in evaluating the field's production capacity and economically recoverable reserves. In fact, every measure was taken to do so except extended production testing. With onshore gas reserves a certain number of the wells could have been subjected to an extended production test, but expense normally rules this out for offshore operations. For example, rig hire 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 a large number considering the size and nature of the field) for 30 days each would cost $9 million. In these circumstances reliance had to be placed on a wider judgement, namely, such considerations as the fact that: (i) at the time of appraisal four gas fields had been proven along with some additional discoveries and all of these could be served by the pipeline; (ii) an experienced oil company was willing to commit over $300 million, (iii) one of the most experienced reservoir consultant was engaged for the field evaluation and initial economically recoverable reserves were based on the consultant's field development plan and cost; and (iv) all gas users would have dual firing capability in case there should be a problem with gas supply. Moreover, the proven and probable reserves estimated at the time were about five times the level needed to make the project economic. Procurement and Performance of Contractors 3.19 Project procurement comprised 15 contracts for services and ibrks and 28 contracts for the purchase of materials and equipment. Except for normal claim adjustments on completion of a contract, PTT reports no undue problems with contractor performance, and none have been observed by Bank staff who have supervised the project. - 41 - IV. Operating Performance 4.01 PMT reported that all its equipment and facilities were operating satisfactorily. An inspection of the project area showed excellent housekeeping and care of equipment. All project facilities were operated entirely by PTT personnel who were alert and knowledgeable and gave every indication of being well trained. As a precautionary measure, PTT appointed two firms to assist during the initial operating stages: one to provide assistance with maintenance procedures and preparation of plans for future maintenance of the pipeline and the other as s indby assistance in the event of an operating failure and as a source of practical knowledge to supplement the 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 "no smoking" and "hard-hat" regulations are strictly enforced. There is satisfactory provision for fire detection and fire fighting and personnel are trained in emergency procedures. 4.03 The only operating problem of any significance occurred in August 1982 when a sudden pressure drop developed in the offshore portion of the pipeline as a result of condensate build-up. This condition was due to the fact that at the existing low flow rates the gas had insufficient velocity to entrain and sweep along the condensate forming in the pipeline. Because of the large accumulated volume, the pipeline had to be shut down before the condensate could be removed. Since then, frequent pigging (every three weeks) has allowed continuous operation. As pipeline throughput increases condensate accumulation will become less and less a problem, particularly since all gas supplies except from Erawan will be required to have a hydrocarbon dewpoint sufficiently low to prevent condensation in the pipeline. To ensure continuous gas flow at all possible operating conditions, consideration is being given to the installation of a back-up slug catcher as part of the Liquefied Petroleum Gas Project (Loan 2184-TH). V. Economic Performance Benefit Streams 5.01 Project economics and finance were appraised both on already contracted supplies and assuming reasonably prompt completion of ongoing negotiations. In addition, the benefits of gas supply from existing contracts only were considered in order to estimate the intermediate position of the project return. At the time of project appraisal, the only contract in existence was gas supply from Union's Erawan field. PTT has since then concluded a further contract with Union Oil for gas supply from a group of five other fields. The current estimate of total gas production from existing contracts with Union exceeds the appraisal estimate. However, most of the gas from the additional fields will not come on stream until 1985, one year later than assumed at appraisal. Furthermore, the negotiations between PTT and Texas Pacific (TP) for a gas sales contract, already identified at the time of appraisal, are still incomplete, and the current estimate of gas supply from TP is seven years behind the appraisal forecast. As a result, current estimate of gas production falls short of the appraisal estimate for the first nine years of the pipeline operations (1982-90), but is expected to reach the - 42 - appraisal estimate of 500 MMCFD in 1991. However, the life of Erawan field is currently estimated to be shorter than the appraisal estimate. As a result, from 1995 onward, gas supply is expected to be from Union second contract and TP 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 the quantities under consideration, fuel oil is the relevant comparator. While the international price of fuel oil was higher than the appraisal forecast in FY82, the price of oil has since fallen and the current estimate of gas value is lower than anticipated over the period FYs83-88. From FY89 onward, the current estimate of gas value is expected to be higher than the appraisal estimate, reflecting higher real growth of fuel oil prices. 5.02 Comparisons between the appraisal and cYrrent estimates of gas production and value are summarized as follows:1. FY82 FY84 FY86 FY88 FY90 FY92 Production (MMCFD) Appraisal - Main case Union 200 250 250 250 250 250 TP - 150 200 250 250 250 Total 2r00 400 450 500 500 500 Current Estimate Union 120 200 495 465 385 385 TP - - - - - 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 7.4 Current 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 import duties) represents a 21Z underrun against the appraisal estimate of $417 million. However, the current estimate of the costs of gas is higher than the appraisal forecast for gas from Erawan; which, to some extent, reflects higher inflation. On the other hand, based on the assumption that TP gas cost is the same as that of Union second contract, the current estimate of TP gas cost is lower than the appraisal estimate. The cost of gas is summarized below. 1/ The gas volumes shown have different calorific (Btu) content for Union and TP. The SAR adjusted to a standard 1,000 Btu/cu ft value. - 43 - (in current terms) FY82 FY84 FY86 FY88 FY90 FY92 Gas Cost ($/MMBTU) Erawan Appraisal 1.6 1.8 2.0 2.3 2.6 3.0 Current 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 3.6 Current estimate - - - - 3.4 3.5 Economic Rate of Return 5.04 The detailed economic analysis based on gas supply from both Union Oil and Texas Pacific is presented in Annex 3. Comparisons between appraisal and current estimates are sUmmarized below: Appraisal Current Estimate Economic rate of return (Z) in real 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 the economic rate of return and the net present value of the project are lower than the appraisal forecast. This is mainly because of the lower margin between the value and cost of gas, and the benefits foregone by gas supply shortfall during the initial years of pipeline operations. Nevertheless, the current estimate of the project return remains attractive. - 44 - VI. Institutional Performance Background 6.01 The Petroleum Authority of Thailand (PTT) is a state enterprise established in December, 1978 to engage in and promote the petroleum business. It is under the jtrrisdiction of the Ministry of Industry. At present, PTT operates as a single legal entity with no subsidiaries. It has three major operational units, namely the natural gas operations (ONG), oil marketing operations (ODS) and refinery. 6.02 Implementation of the project was transferred to PTT when it took over the Natural Gas Organization of Thailand (NGOT) in July 1979. ONG was responsible for the construction of the natural gas pipeline and is now charged with its operation. It will also be responsible for implementing and operating the gas separation plant (Loan 2184-TH). The major part of the oil marketing operations were transferred from the Oil Fuel Organization (OFO) to PTT in September, 1979, and the balance transferred from the Summit Corporation in early 1981. The Bangchak refinery was formerly leased to the Summit Corporation and taken back by the Government in early 1981. Bangchak is owned and operated by the Ministry of Defense. PTT is responsible for the acquisition of oil, distribution of petroleum products and financial management of the refinery. Bangchak has separate books of accounts and its financial statements are not consolidated with PTT, but the PTT role with Bangchak has a significant effect on PTT's financial situation. Under a joint venture agreement for the expansion of TORC refinery, PTT holds 49Z of the shares of the IYJRC refinery. In addition, PTT will hold 25% of the shares in a 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 a chairman and eleven other directors. The Governor of PTT, who is its chief executive officer, is a Director and Secretary of the Board. PTT also has an executive committee chaired by a member of the main Board. In view of the rapid growth in its activities, PTT underwent a major reorganization in mid- 1981. Under the Governor, there are now six Deputy Governors responsible for Technical and Planning, Natural Gas Operations, Marketing, Logistics and Refining, Finance and Administration, and Special Affairs. In addition, there are 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 are under the Natural Gas Operations. PTT's top management is experienced in business and management but has only limited experience in the petroleum industry. The middle management is generally young, keen and well educated but in many cases with relatively little experience. Under the provisions of the project, theoretical and on-the-job training has been given for the natural gas operations and in accounting and finance. In addition, training is planned for the operation of the gas separation plant and LPG distribution, as provided under the LPG project. Apart from specific instances associated with new projects, PTT's future needs are practical, on-the-job experiences rather than making much use of further training courses. - 45 - Management Information System 6.05 During the initial phase of project implementation, there appeared to be inadequacy in the accounting system at ONG (formerly NGOT) particularly with respect to documentation of payments. In addition, the accounting system at 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 consultants were engaged to assist PTT in the maintenance of its accounts and in internal auditing. Specifically, the consultants assisted ONG to strengthen its accounting system, design a management information system as well as a budgetary control system, taking account of the expanding activities of natural gas operations. In addition, the consultants assisted ODS to strengthen its accounting and control system and undertake verification of fixed assets at ODS. Furthermore, the necessary staff training was provided with the assistance of consultants. As a result, there has heen a marked improvement in PTT's management reporting system. With respect to internal control, the consultants have, until recently undertaken the internal auditing of PTT as an interim step until the company can build up its own staff to perform the task. However, the service of the consultants was discontinued in 1983 when PTT decided that it could implement the management reporting system on its own. Since the internal audit function at PTT has not as yet been staffed, internal auditing is no longer undertaken as a part of its internal control. This is not in compliance with the loan condition provided under the Liquefied Petroleum Gas (LPG) project. The issue has been raised with PTT management, which has assured the Bank that is actively seeking suitable consultants. This will be followed up by future supervision missions for the LPG Project. VII. Financial Performance 7.01 At the time of appraisal, the imminent transfer of OFO was undecided and the transfer of Bangchak refinery was even further into the future. No review of OFO, as a military establishment, was feasible and for prc-tical purposes, the appraisal only took account of ONG's financial forecast. Accordingly, the comparison between appraisal and actual performance has been limited to ONG only. ONG's comparative income statements, funds flow statements and baluLce sheets are presented in Annex 4. Revenue Position 7.02 As PTT's gas purchase/sales contracts with Union Oil and EGAT provide for a lower price of gas when volume increases, the gas supply shortfall has led 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% of Union Oil's invoiced amount. The dispute over the gas supply shortfall was settled between Union Oil and PTT in June 1984. According to the agreement on the settlement, PTT would make cash payment to the concessionaires (Union Oil/ Seapec) in the amount of Baht 654 million (US$28 million), representing 40% of the disputed amount (US$61.0 million) plus interest. In addition, in order to provide the concessionaires with an incentive to produce more gas from the Erawan field, PTT will provide an "incentive gas price" for all gas volumes produced in excess of 54,750 MMCF (150 MMCFD) in any contract year. In - 46 - effect, this would mean that instead of four tiers of gas prices which would decrease with increased volume under the original contract, the settlement calls for the price of gas to remain flat after an average of 150 MCFD has been reached. After reaching an agreement with Union Oil on the settlement, PTT has started to negotiate with EGAT on the same issue. The renegotiation between PTT and EGAT on the gas sales/purchase contract (which is provided under the present contract terms) will not start until after an agreement has been reached between the two state enterprises on the gas shortfall dispute. 7.03 Notwithstanding the gas supply shortfall, ONG's operating income in FY82 was in line with the appraisal estimate. For its first year of operation, ONG reported income before interest of $46 million, as compared against the appraisal estimate of $42 million. The negative impact of gas supply shortfall was essentially offset by the higher selling price of gas and the profits from condensate sales which were not known and consequently not included in the appraisal estimate. However, ONG's income after interest of $5 million was significantly less than the appraisal estimate of $8 million on account of higher than anticipated interest rates which in turn led to higher interest expense. Nonetheless, ONG's operating ratio of 0.81 which was close to the appraisal estimate of 0.78. ONG's return on revalued net fixed assets of 12% was slightly higher than the appraisal forecast of 9% mainly because the project cost underrun has resulted in a significantly lower asset base than anticipated. 7.04 ONG's profitability in FY83 fell considerably below the appraisal forecast mainly because of the marked shortfall (45%) in gas supply. Operating income before interest expense was $51 million as compared against the appraisal estimate of $77 million. However,actual interest expense of $28 million compared favorably with the appraisal estimate of $48 mil±ion primarily as a result of the lower financing need. After the inclusion of foreign exchange loss ($8 million), ONG reported net income of $15 million as compared against the forecasted $29 million in FY83. Its operating ratio of 0.83 was considerably higher than expected (0.70), and its return on revalued net fixed assets was 13% as compared against the appraisal estimate of 15%. 7.05 On a DCF basis, the financial rate of return over the life of the project is currently estimated to be the same as the appraisal estimate of 15% (in real terms). The adverse impact of gas supply shortfall is offset by the project cost underrun and higher profit margin than anticipated (Annex 4). - 47 - Funds Flow 7.06 ONG's funds flow over FYs79-83 are summarized as follows: FYs 79-83 (In US$ million) Appraisal Z Actual Z Internal Cash generation 174 26 139 26 Loans /a 412 62 358 66 Government Contributions 77 12 2 - Other Liabilities - 44 8 Total Sources 663 100 545 100 Capital expenditures 482 73 373 69 Debt Service 112 18 136 25 Changes 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 were substantially below the appraisal estimate as a result of the cost savings of the pipeline project. However, borrowings and other liabilities financed a considerably higher proportion of the total requirement than anticipated mainly due to the marked shortfall in Government contributions to cover taxes and import duties. Nonetheless, ONG's cash flow position was not adversely affected 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 reduced drawdowns from the U.S. Export-Import Bank necessitated the occurrence of substantial short-term bridge financings at prevailing high interest rates in FYs 80 and 81. ONG's debt service in FY82 was significantly higher than the appraisal forecast, reflecting substantially higher interest expense and earlier loan repayment than anticipated. As a result, even though ONG's internal cash generation in FY82 was in line with the appraisal estimate, its debt service coverage of 1.3 times in the same year fell short of the expected 2.0 times. In FY83 ONG's internal cash generation was considerably below the appraisal estimate mainly as a result of the marked shortfall in gas supply. Even though its debt service was slightly below the appraisal forecast, its debt service converage of 1.9 times was lower than the expected 2.3 times. - 48 - 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 79 Current assets 82 14 106 21 Total Assets 591 100 509 100 E.quity 176 30 61 12 Long-term debt 402 68 368 72 Current liabilities/a 13 2 80 16 Total Liabilities & Equity 591 100 509 100 Current ratio 6.09 1.32 Debt/equity ratio 70/30 86/14 /a Includes taxes and import duties payable of $51 million on actual balance sheet 7.09 ONG's current ratio and debt/equity ratio were significantly weaker than the appraisal estimate mainly as a result of the delayed Government contributions noted above. Had there been no such delay, ONG's current ratio would have been 3.7 and debt/equity ratio would been decreased to 77/23 by the end of FY83. Financial Covenants 7.10 In light of the fact that it was impractical to incorporate conventional financial covenants for a consolidated PTT at the time of appraisal, the company was requested to adopt a statement of corporate and financial objectives with the view towards sound financial performance. The Loan Agreement requires that: (i) PTT would maintain separate accounts for each of its major activities, including ONG; (ii) no long-term debt would be incurred by O14G without prior agreement by the Bank unless a debt service coverage of 1.2 times would be achieved for 1982 through 1985 and 1.5 times thereafter; (iii) surplus funds from gas operations would only be applied for other purposes after ensuring sufficient funds for requirements of ONG; - 49 - (iv) PTT would earn a reasonable rate of return on the capital invested; (v) PTT would ensure sufficient cash flows to each of its operational unit to enable it to meet its operating and maintenance costs and debt service needs; (vi) PTT would ensure that its internal cash generation could cover its debt service by a margin comparable to that for industry generally and cover capital expenditures to the extent they need to be financed from Income; and (vii) PTT would prepare, on an annual basis, a five year corporate plan including, among others, its investment program, a forecast of its profitability, the projected balance sheets and funds flow. 7.11 Actual performance of consolidated PTT are summarized in Annex 5. PTT has complied with all of the covenants summarized above. However, while PTT has compiled with (v) which requires adequate coverage of debt service on long-term debt, its internal cash generation was insufficient to cover interest expense on short-term loan in FY81. As noted in Annex 5, PTT's liquidity position improved significantly in FYs 82 and 83 and debt service on both long and short term loans were adequately covered. PTT's financial performance will continue to be monitored closely under the LPG Project now under implementation. 7.12 The Guarantee Agreement provides that the Government would make an equity contribution to cover the cost of land and right Lf way as well as import taxes and duties of the project. As noted above, such contributions from 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 Second Gas Development Project, the Bank made significant contributions to the development of Thailand's natural gas resources and the institutional capacity to deal with this new energy source. The Bank's supportive role was especially important in light of the country's inexperience with this new energy resource; it included such diverse functions as: (i) serving as a source of impartial advice in technical, financial and institutional matters; (ii) expediting the decision making process; (iii) identifying essential project and sector studies and technical assistance; and (iv) preparing terms of reference of consultants, and providing guidance in their evaluation. The Bank's efforts were particularly effective in bringing about an early launching of the development project through assistance in setting up a natural gas utility (NGOT), engaging technical and legal advisers in contract negotiations with the foreign oil companies and undertaking timely preparation and implementation activities critical to the success of a project of this magnitude and complexity. From an institutional perspective, the Bank required and assisted in establishing appropriate technical, financial and operational training programs. While there is still room for improvement, these programs have provided PTT with a competent staff capable of independently carrying on its natural gas operations. Studies and related - 50 - 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 continued Its supportive role. 8.02 The Bank was originally called in by the Government to provide unbiased advice on how to proceed with the gos purchase and the project. No alternative source of advice acceptable to Thai authorities was identified during the project (i.e., although the Government was satisfied with virtually all consultants In relation to specific project tasks, they were not satisfied that any of the consultants could give competent and impartial advice on the broader issues). In light of the above, the question remains as to whether the Bank needed to finance 25% of the project cost to achieve the various objectives. With benefit of hindsight, we believe the extent of parti- cipation, was appropriate. An important part of the task was to ensure that the management decisions were taken in time for the project to be completed for the commencement of deliveries. Further, to ensure efficient procurement the Bank had to exert strong influence on procurement decisions a number of times during the project. Both of these required a weighty participation, and the Bank's position as the largest single financier was important for this role. 8.03 Relations with PTT (and its predecessor, NGOT) have been good throughout the Bank's involvement in these two lending operations. PTT confirms that complying with Bank requirements on procurement and project supervision have not been a source of problems. However, both PTT and the Ministry of Finance are critical of the Bank for making conclusion of a gas sales agreement with EGAT a condition of loan effectiveness (para 1.03). This condition of the loan delayed disbursement by 15 months and made it necessary for PTT to arrange short term bridge financing for over US$70 million at a time when interest rates were at near all-time-high levels. PTT maintains that the condition provided no penalty to EGAT (which caused the delay), and that it had to suffer a substant'al financial loss through no fault of its own. The point is a valid one, and from hindsight it appears that a fairer and more effective approach would have been to put a comparable covenant in the 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 a substantial cost underrun, and it constitutes Thailand's first step in developing an indigenous energy supply. So far, anticipated gas volumes have not been realized, but the economic rate of return nevertheless remains very attractive. Further benefits will follow as additional gas supplies already under contract are connected to the project facilities. 9.02 Also successful was the Bank's institution building role which spanned the period from the time when there was not even a natural gas organization to the present successful operating entity. 9.03 Bank processing of Loan S-10-TH was linked to a gas sales agreement between NGOT and Union Oil (para. 1.03). Government officials and others involved in the negotiations felt that this gave a bargaining advantage to Union Oil. That is to say, Union Oil, by knowing that a Bank loan would not be forthcoming until a contract was signed, could afford to stall while the - 51 - pressure to make concessions was on NGOT. This reasoning overlooks the fact that it would have been a poor bargaining tactic for either party to commit money to the enterprise before an agreement was reached. In fact, the condition was an important factor in concluding the agreement. However, this does demonstrate that care must be taken in setting Bank lending conditions in similar situations where they may influence ongoing negotiations. 9.04 Although the project remains economically sound, the shortfall in gas supply demonstrates the geological risk associated with all petroleum exploration and development, no matter how favorable the prospects appear. This risk was recognized at appraisal and as discussed in this report found acceptable because sufficient steps were Laken to mitigate the economic implications and also because the field's estimated proven and probable reserves were five times the actual quantity required to make the project economic in addition to the sizeable additional gas deposits known to be in the area. The project demonstrates that a much more comprehensive - and expensive - appraisal of the field would have been necessary to avoid possible financial 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 the gas sales contract between PTT and Union Oil are somewhat one-sided in that PTT is required to compensate Union Oil for contract deliveries (or portions thereof) it fails to accept, whereas the contract is not fully explicit in the costs and penalties Union Oil is subject to for not making the contract deliveries. However, such a conclusion is not valid when full acccunt is taken of how other contractual and legal provisions affected Union Oil and such considerations as the fact that: (a) the risk to PTT was acceptable. PTT helped set the contract delivery date which allowed ample time to prepare for the deliveries, and EGAT provided a ready market. The Union Erawan gas supply represented only a fraction of the likely demand; (b) the take-or-pay provision was felt to be the only practical means for ensuring that the PTT facilities could be installed on time, and it was later demonstrated that th.! many delays encountered during implementation would not have been overcome without this contractual imperative; (c) Union Oil has already been penalized by the reservoir's inability to deliver the expected gas production both through the initial deduction of 20% of its revenues and through the lower gas volumes. The gas supply contract provides for a substantial work coumitment by Union toward remedying the problem, and it will take a larger investment than previously anticipated to produce a smaller quantity of gas; and (d) the gas price finally agreed to by both sides reflected the terms and conditions of the contract. Considering the time and hard bargaining it took to reach an agreement, it can be concluded that both sides probably got the best deal either could 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 COSrs l.@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 67.5 Cathodic 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 4.2 Da ,v4nt ctntrol - 44 64 - 3.2 1.2 1.8 16. 3 322.1 0.2 19.0 15.2 latnratn ctura tOO 192 292 5.0 9.6 14.4 266.8 I30N. 419.7 12.2 *.6 1i1.6 Spo 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 16.4 Oftsbore pipe 1eystZ 320 1.400 1.920 14.0 80.0 94.0 - 1.591.? 1,911.2 - N6.7 169.7 Osbhore 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 - 1.5 NobIlIzatio 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 50.9 O0wr. ar 52 - 52 2.4 -- 2.4 37.1 5.4 42.7 1.9 0.3 2.2 Start-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 42.7 Conetractine 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 0.4 TechniCEl 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 Project Schedule of Disbursements (In US$ '000) IBRD Fiscal Year and 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 87 December 31, 1981 98,000 96,450 98 March 31, 1982 99,000 96,450 97 June 30, 1982 100,000 96,450 96 1982/83 September 30, 1982 101,000 96,450 95 December 31, 1982 103,000 96,450 94 March 31, 1983 105,000 96,450 92 June 30, 1983 106,000 96,450 91 1983/84 September 30, 1983 107,000 101,500 95 December 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 Estimatg Year 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 12 123 124 1983 469 7 ISO 312 267 11 150 106 1984 714 - 233 481 382 50 IS3 139 1985 773 - 323 450 691 48 327 316 1986 913 - 319 594 924 102 427 3g5 1987 1113 - 375 738 1033 170 475 389 1988 1214 - 417 797 1175 68 537 570 1989 1295 _ 446 849 1362 613 749 1990 1369 - 478 891 1447 648 799 1991 1450 - 512 938 1531 684 847 1992 1541 - 548 993 1626 - 739 888 1993 1644 - 586 1058 1746 - 797 949 1994 1757 - 626 1131 1866 - 856 1014 1995 1878 - 670 1208 1985 - 457 0i71 1996 2007 - 717 1290 2129 - 937 1192 1997 2145 - 767 1378 2272 - 1007 1264 1998 2291 - 821 1470 2440 - IO2 1358 1999 2449 - 878 1571 2607 - 1156 15l 2000 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 boilers 37 Includes gas purchase costs, pipeline operation cots and increase in minimum vorking capital requirements. - 56 - ANNEX 4 Page 1 of 5 THAILAND Second Natural Gas Development Project Natural Gas Operations Finances For purposes of comparison with the Staff Appraisal Report (SAR), the following adjustments have been made to ONG's actual financial statements: 1. Fixed assets and related depreciation which were reported on historical 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 been adjusted to be written off as an operational expense during the year of 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-term loan. THAILAND PTT SECOND NATURAL GAS DEVELOPMENT PROJECT Income Statements (In US$ Million.-) For Year Ended September 30 1979 1980 1981 1932 1Q1 ApprctrAppralppralmal Actuel ApprInial Actual AppraiNsl Actuel Appraisal Actual Appraisal Actual Production Gas (MHCFD) - 200 20.00 2.0 140o0n Condensate (million bbl) -- -- -- -- -- - - 1.10 - 2.5 Natural 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 - -- -- -- 192.79 182.31 253.20 212.23 Condensate - 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.nn Co'dansate Coats -- -- -- -- - - - 44.14 - 74.30 Natural Oabolf7a Costs - -- -- -- -- -- -- 0.32 - n.47 D 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 SECOND NATURAL GAS DEVELOPMENT PROJECT Sources & p atlone of Funds Mf S illions) For Year Ended September 30 1979 1980 1981 1982 1983 Appraisal Actual Appraisal Actual AppraLtel Actual Appraisal Actual Appraisal Actual Sources Net Incoge Befora Intereat -- -- 42.n7 45.63 77.48 50.71 Adds 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 5.05 lxin 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 8.50 Long-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. THAILANM PTr SECOND NATURAL GAS DEVELOPMENT PROJECT Palance Sheets (Ifn Us$ millions) An of September 30 1979 1980 I1RI 1002 1983 Appraisal 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 s22.00 407.51 565.00 444.54 Leses 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 39.09 Accounts Receivable -- -- -- --- - 15.h5 36.91 21.22 40.74 Other 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 2.74 Revaluation 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 329.26 401.57 319.74 leserve 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 0.86 Current Ratio -- -- -- -- -- -- 1.68 0.50 6.09 1.32 Return ou Average Net Assets (2) -- -- -- -- -- - R.68 12.0R 15.42 12.60 I/ Actual state.entu include tares and import dutlea payable THAfLAND SECOND NATURAL GAS DEVELOPMENT PROJECT Gas Sales Margin (in US$/MMBTU) Appraisal Current Estimate Selling Price Average Cost Gross Margin Selling Price Average Cost Gross Margin 1982 2.5 1.6 0.9 3.7 2.5 1.2 1983 2.7 1.6 1.1 3.7 2.6 1.1 1984 2.9 1.8 1.1 3.7 2.5 1.2 1985 3.1 1.9 1.2 4.1 2.6 1.5 1986 3.3 2.1 1.2 4.3 2.8 1.5 1987 3.5 2.3 1.2 4.5 3.1 1.4 1988 3.8 2.5 1.3 4.7 3.4 1.3 1989 4.1 2.6 1.5 4.9 3.6 1.3 1990 4.3 2.8 1.5 5.1 3.9 1.2 1991 4.6 3.0 1.6 5.5 4.2 1.3 o 1992 5.0 3.2 1.8 5.9 4.6 1.3 1993 5.3 3.4 1.9 6.4 4.9 1.5 1994 5.7 3.7 2.0 6.9 5.3 1.6 1995 6.1 3.9 2.2 7.5 5.7 1.8 1996 6.5 4.2 2.3 8.1 6.? 1.9 1997 7.0 4.5 2.5 8.7 6.7 2.0 1998 7.5 4.8 2.7 9.4 7.1 2.3 1999 8.0 5.2 2.8 10.2 7.7 2.5 2000 8.5 5.5 3.0 11.0 8.3 2.7 1/ Based on gas supply from both Union Oil and Texas Pacific. o - 61 - ANNEX 5 Page 1 of 2 THAILAND Second Natural Gas Development Project Consolidated PTT Finances PTT's consolidated finances over the last four years are summarized below: (in million US$) FY1980 FY1981 FY1982 FY1983 -------------…-audited…--------------- Revenues 1165 1199 1364 1559 Net Income 28 (41) 41 46 Current Assets 406 664 595 540 Total Assets 653 1107 1048 1042 Current Liabilities 411 782 440 426 Long-term debt 160 288 545 513 Total Equity 82 37 63 102 Operating Ratio 0.96 0.99 0.93 0.95 Current Ratio 0.99 0.85 1.35 1.27 Receivables Turnover (days) 88 95 77 39 Debt/Equity Ratio 66/34 92/8 90/10 83/17 Total Liabilities/Equity Ratio 87/13 98/2 94/6 90/10 Consolidated PTT's finances were dominated by ODS before pipeline operations started in FY82. As the above table shows, PTT reported net income of $28 million in FY80. However, its liquidity position was weak. This was mainly due to delayed payments by EGAT, by far the largest customer of PTT. In addition, ODS' inadequate billing and control system prevented effective management of accounts receivable. In FY81 EGAT began to make timely payment to PTT and ODS' accounting system was strengthened with the assistance of consultants. Nonetheless, delayed payments by the Oil Stabilization Fund and delayed effectiveness of two long-term loans for the pipeline project necessitated the occurrence of substantial bridge financing at prevailing high interest rates. In addition, funding of the Bangchak refinery represented a major drain on PTT's cash position and a short-term loan in the order of $300 million was drawndown to meet Bangchak's working capital requirements. PTT's operating income of $9 million 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 of 1.3-1.4 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-term liquidity problems, PTT sought co-mercial financing of $200 million, interest and principal on which would be paid by the Government. Of this amount, $125 million would represent payment of the Oil Funds indebtedness to PTT, while the balance would represent equity injection into PTT. In addition, the Government allowed PTT to consolidate the inventory of ODS and Bangehak refinery for purposes of 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 and substantial bridge financing was retired. (d) ODS' profitability was improved. Notwithstanding a 6Z drop in sales revenues, ODS reported a sharp increase in operating income of $41 million in FY82 as compared against $9 million in FY81. This was mainly as a result of a change in product mix, with an increased share of gasoline which is the single most profitable product. Interest expense was decreased by 37% to $20 million, resulting in a net income of $21 million. Together w4th a net income of $20 million from ONG, consolidated PTT-s net income totalled $41 zi.llion in FY82. Consolidated PTVs net income continued to increase to $48 million in FY83, with $27 million 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 5amut ; - Proposed Pipeline% Phrhbr0 (,us F,elds Area of nPietcha-ur( - -Iierflarional Boundaries or ALAW YIA ,Ii.*'i. rNDONESA '' hi7 | ( aDEMOCRATIC 3 KP. chwp ° | \ KAMPUC-+IEA 1- . ,. ,r .' 0 zuE AlA / * C humpPhon AA / > ! t Ranong a O ;-: r. Kha 0~~~~ o ~~~~~~0 0' hRonong Sur TlhanP uNI/ON OiL STRuc rURf It IP O *~* ~THA AAIAVD Phangrnga BOC/NDAA'Y CIAIM4 0~~~~~~~~~ ° Nokhon SSg A \ Tkan,morat V B.t(b \.a rFX.A S.f/ - Pfuke,O 5 rR(jcfUJ ~IEl1 0~~~~~~~~~~~~~~ T.'ang0 ° / 0~~~~~~~~~ _. SHSARED BY Sorealkhla O , WrAL AND MALAYSIA Sorun 5 Yala/ o A Y~~~~~orihat l'l '4,,;a, ~~~~~~~'S ;- ~Narothawar O 20 40 60 X 10e0 120 140 160 |1 O ZD140 a 0 BI:; I1C .