Document of

The World Bank

FOR OFFICIAL USE ONLY

A-A 3c2'0 - /-VL)

Repon No. 8112-IND

STAFF APPRAISAL REPORT

INDONESIA

GAS UTILIZATION PROJECT

MAY 8, 1990

Industry and Energy Operations DivisionCountry Department VAsia Pegional Office

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

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CURRENCY EQUIVALENTS

Currency Unit = Indonesia Runiah (Rp)US$1.00 = Rp 1,750Rp 1,000 = US$0.57

WEIGHTS AND MEASURES

1 barrel (bbl) = 0.159 cubic meters (cu.m.)1 standard cubic foot (cf) = 0.028 cu.m.1 British Thermal Unit (btu) G 0.252 kilocalories (Kc)MCF = thousand standard cubic feetMMCF = million standard cubic feetMMCFD = million standard cubic feet per dayMCM = thousand cubic metersMMCM = million cubic metersBCF = billion standard cubic feetTCF = trillion standard cubic feetKl kilolitertoe = tons of oil equivalent (in heating

value)boe = barrels of oil equivalent (in

heating value)tpy metric ton per yearbbl/d = barrels per dayKWh = kilowatt hour (1,000 watts per hour)MW megawvtt (1,000 kilowatts)Km = kilomEterHP = horse ,ower

ABBREVIATIONS AND ACRONYMS

BAKOREN National Energy Coordinating BoardBAPPENAS National Development Planning BoardERR Economic Rate of ReturnFRR Financial Rate of ReturnGOI Government of IndonesiaHSD High Speed DieselICB International Competitive BiddingIDO Industrial Diesel OilLIB Limited International LiddingLNG Liquefied Natural GasLEMIGAS Research and Development Center for Oil

and Gas TechnologyLPG Liquefied Petroleum GasMIGAS Directorate General of Oil and Natural

Gas, Ministry of Mines and EnergyPERTAMINA National Oil and Gas CompanyPGN State Gas CorporationPLN State Electricity Corporation

FISCAL YEAR (FY)

April 1 - March 31

FOR OFFICIAL USE ONLY

INDONESIA

GAS UTILIZATION PROJECT

STAFF APPRAISAL REPORT

Table of Contents

Page No.

Loan and Project Summary ...................................... i-iii

I. THE ENERGY SECTOR AND GAS SUBSECTOR ........................... 1Introduction ...................................... 1Primary Energy Resources ...................................... 1Power ...................................... 3Organization of the Energy Sector ............................. 4The Natural Gas Subsector ........... . ........................ 4Bank Role and Strategy .......................... 9

II. THE BENEFICIARIES .......................... 10PGN (STATE GAS CORPORATION) .......................... 10

Background .......................... 10Statutory Functions .......................... 11Organization .......................... 11Proposed Reorganization ............................ . ..... 12Technical Assistance Requirements .......................... 13Human Resource Requirements and Training .13Accounts .14Audit .15Budgeting .15Billing and Collection .16Insurance .16

MIGAS AND LEMIGAS .16

III. THE PROJECT .17Background .17Market ........................................................ 17Gas Supply ....................... 19Project Objective and Rationale ....................... 19Project Description ....................... 21Project Costs ........................ 24Financing Plan ....................... 26Implementation ....................... 27Procurement ....................... 28Disbursement ....................... 29Environment ....................... 30Reporting Requirements ... .................................... 30

This report was prepared by ilessrs. S. Khwaja (Sr. Gas Specialist), M. Sergo(Sr. Financial Analyst), and Ms. M. Manzo (Energy Specialist) on the basis ofa field appraisal during May 1989. Ms. Rosa Lema assisted in the typing ofthis report.

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

IV. FINANCIAL ASPECTS .......................................... 30PGN's Margins on Gas Sales .................................... 30Past Financial Performance .................................... 32Present Financial Position .................................... 33Financial Projections ......................................... 34Risks in Financial Projections ................................ 37Project's Financial Rate of Return ............................ 38

V. PROJECT JUSTIFICATION AND RISKS. r. .......... _U

Economic Evaluation of the Project .39Project Risks .42Fiscal Impact of PGN's Operations .43Benefits from Institution Building Component.. 44

VI. AGREEMENTS REACHED ........................ 45

ANNEXES

1.01 Estimated Gas Reserves1.02 Historical Gas Production1.03 Gas Production/Utilization Balance1.04 Historical Gas Productior & Consumption By Region2.01 Composition of Current Industrial Demndnd in Surabya and Medan2.02 Gas Demand and Supply Projections for Medar and Surabaya3.01 PGN's Existing and Proposed Organization3.02 Organization of MIGAS and LEMIGAS4.01 Implementation and Technical Assistance-Terms of Reference4.02 Planning Study for Gas Technology Development Center-Terms of Reference4.03 Regulatory System for Safe _Jilization of Natural Gas5.01 PGN's Project implementation Sch lule5.02 Phasing of Expenditure5.03 Estimated Schedule of Disbursements5.04 PGN's Progress Reporting Requirements6.01 Notes and Assumptions on Financial Statements6.02 PGN's Income Statement for FYs 1986-19976.03 PGN's Balance Sheet for FYs 1986-19976.04 PGN's Sources and Uses of Funds for FYs 1986-19976.05 Efficiency Improvement Program for PGN6.06 Income Statement for Medan Component of the Project6.07 Income Statement for Surabaya Component of the Project6.08 Financial Internal Rate of Return7.01 Assumptions Underlying Economic Analysis7.02 Economic Analysis - Internal Rate of Return7.03 Domestic and International Prices of Petroleum Products7.04 Economic Rate of Return Calculations based on Least Cost

Alternative.7.05 Fiscal Impact of the Project8.01 List of Documents in the File

Maps

General IBRD 21723Region-wise IBRD 21724R1, IBRD 21725R1

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INDONESIA

GAS UTILIZATION PROJECT

Loan and Project Summary

Borrower: Republic of Indonesia

Beneficiaries: Perum Gas Negara (PGN)

Amount: US$86 million equivalent

Lending Terms: Repayable over 20 years, including five years of grace,at the standard variable interest rate.

On-lending Terms: The Government would onlend US$76 million to PGN at arate of 13Z per annum, with repayment over 15 yearsincluding a grace period of five years.

Project Description: The primary objective of the project is to acceleratethe substitution of exportable petroleum product fuelsin domestic consumption with non-exportable naturalgas. This would be achieved through: (a) the provisionof an assured supply of natural gas, at competitiveprices, to power plants, manufacturing industries, andcommercial entities in Surabaya and twelve other townsin its vicinity in East Java and in Medan in NorthSumatra; (b) the integration of gas utilization plansand operations to facilitate balanced development; and(c) institution building, technology transfer andmarketing studies to accelerate safe and efficientutilization of natural gas and to help plan for itslong-term development. The project would consist of:(a) design and construction of a natural gas supplysystem for Surabaya and its environs and expansion ofexisting natural gas supply system for Medan; (b)technical assistance involving enhancement of PGN'sskills in growth management and efficient expansion ofits gas supply infrastructure, establishment of a GasTechnology Development Unit in LEMIGAS and upgrading ofskills in MIGAS to facilitate the coordination of gassector development plans and to institute a regulatorysystem for safe utilization of natural gas; and (c)feasibility studies for natural gas marketing inPalembang (South Sumatra), Jambi (Central Sumatra),Batam island (Riau) and Balikpapan (East Kalimantan).

Benefits: The main benefits of the project are: (a) substitutionof low value natural gas for high value petroleum

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products for power generation and manufacturingindustry thus releasing more oil for export; (b)strengthening of institutions so as to improve theefficiency in the gas sector; and (c) reduction ofenvironmental pollution and forest depredation with thereplacement of polluting fossil fuels and wood byrelatively clean natural gas. The project is expectedto yield an economic rate of return of about 59Z forthe Medan and Surabaya components combined.

Risks: The potential risks to the project fall in fourcategories: (i) timeliness of gas supply; (ii) delaysin market development; (iii) declining retail prices(in real terms) of the fuels to be substituted; and(iv) shortfalls in institutional capability toimplement the project. These iisks are recognized andthe precautions to minimize them have been built, asfar as possible into the project design. Thesubstantial benefits from the project far outweighthese risks.

Estimated Costs:Local Foreign Total

A. Natural Gas Transmission and ------US$ million-----Distribution Systems for

Surabaaa & its environsPipelines 8.2 52.4 60.6Regulator Scations 0.3 1.7 2.0Meter Stations & Service Lines 0.7 5.1 5.8

Subtotal 9.2 59.2 68.4

MedanPipelines 2.6 3.1 5.7Meter Stations & Service Lines 0.0 0.4 0.4

Subtotal 2.6 3.5 6.1Base Cost (A) 11.8 62.7 74.5

B. Technical Assistance

PGNTwinning Arrangement 0.0 5 0 5.0Staff Training 0.0 2.5 2.5Equipment (computers & software) 0.5 0.6 1.1

Subtotal 0.5 8.1 8.6

LEMIGAS (Gas Tech. Development Center)Consultancies 0.0 2.0 2.0Staff Training 0.0 1.5 1.5Equipment 1.3 4.0 5.3

Subtotal 1.3 7.5 8.8

-iii--

MIGASStaff Training 0.0 0.5 0.5

Base Cost (B) 1.8 16.1 17.9

C. Studies

Marketing FeasibilityStudies for PalembangJambi, Batam Island & Balikpapan 0.0 0.3 0.3Base Cost (C) 0.0 0.3 0.3

Total Base Cost (A+B+C) 13.6 79.1 92.7Physical Contingencies 2.2 4.0 6.2Price Contingencies 1.4 8.0 9.4

Total Project Cost a/ 17.2 91.1 108.3

Capitalized Interest During Const. 2.5 8.0 10.5Total Funding Required 19.7 99.1 118.8

a/ includes taxes and duties amounting to US$11.0 million equivalent.

Financing Plan

The total funding required (US$118.8 million equivalent) is expectedto be financed as follows:

Source Local Foreign Total---------US$ million---------- z

Proposed Bank Loan - 86.0 86.0 73Bilateral Sources - 5.0 5.0 4PGN Internal Cash Generation 9.7 - 9.7 8GOI 10.0 8.1 18.1 15

Total 19.7 99.1 118.8 100

Estimated Disbursements:

IBRD Fiscal Year 1991 1992 1993 1994 1995 1996

Annual 9.5 36.1 29.8 4.3 3.6 2.7Cumulative 9.5 45.6 75.4 79.7 83.3 86.0

Economic Rate of Return: 59Z

Maps: IBRD 21723, 21724R1, 21725R1

INDONESIA

GAS UTILIZATION PROJECT

I. THE ENERGY SECTOR AND GAS SUBSECTOR

Introduction

1.1 Indonesia is endowed with large and diverse energy resourcesincluding oil, gas, coal, hydiopower and geothermal resources. Untilrecently, the energy sector was the main source of export earnings for thecountry, accounting for as much as 81% of total exports in FY1981/82.However, triggered by a lower international price of crude oil and OPECproduction quotas, and with the coriconmitant promotion by the Government ofnon-oil exports, the share of energy exports has since steadily aeclined.In FY1987/88 and FY1988/89, the sector accounted for 48% and 39% of totalexport revenues, respectively. Although its export share has been reduced,the energy sector still remains the largest single source of foreignexchange earnings. To mitigate the decline in oil export earnings, theGovernment has adopted a two-pronged energy development strategy that callsfor (a) maximizing the country's export of energy resources throughdevelopment of tradeable energy resources including oil, coal and gas, and(b) the diversification of domestic energy consumption away from heavyreliance on petroleum products towards alternative fuels for which thereare non-exportable surpluses (gas and coal) or which are non-tradeable(hydropower and geothermal).

1.2 Given the abundance of gas reserves and its relatively lowmarginal cost to develop, the natural gas subsector offers wideopportunities for pursuing Got's energy development .rategy. On theexport side, LNG exports to Japan and Souch Korea represent 25Z of totalenergy exports and there are planned increases in exports with thecommissioning of additional LNG facilities to meet supply commitments toTaiwan and additional contracts with Japan. On the other hand, the shareof natural gas in domestic energy consumption is only 1Z, indicating a needfor greater recognition of the prospects offered by gas as a more efficientand cheaper fuel for domestic use. Accordingly, GOI is promoting theexpanded production and use of gas as substitute fuel for power generationand industrial manufacturing. Highest priority has been given to theregions of East Java and North Sumatra where recent gas findings haveconfirmed the adequacy of reserves accessible to the major economic growthcenters of Surabaya and Medan. The avdilability of gas supply in theseregions is expected to attract existing industrial users of more expensiveliouid fuels to shift to gas, as well as promote more industrialdevelopment. Gas supply for power generation is likewise intended to meetthe rising energy demand at a reasonable cost and thus sustain the regions'growth.

Primary Energy Resources

1.3 Oil. Indonesia's proven and probable reserves have been estimatedat about 70 billion barrels. Cumulative production as of 1988 has reached

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12.9 billion barrels and the remaining proven recoverable oil is estimatedat 8-10 billion barrels. Oil production reached a peak of 1.7 milli.-barrels per day (bbi/d) in 1977, but due to depletion of reserves and OrECquota restrictions, production has since declined to 1.2 million bbl/d in1987 and is expected to continue at about 1.1 to 1.3 million bbl/d in thecoming years. In a bid to spur more exploration and production of oil, GOIrecently announced easier terms for oil contractors especially in the moreremote areas of eastern Indonesia. In July 1989, GOI signed nine newproduction-sharing contracts with international oil firms with fourteenmore scheduled to be concluded by the end of the year.

1.4 Natural Gas. Indonesia's natural gas resources are estimated atabout 106 trillion cubic feet (TCF), of which a total of 84 TCF is proven.The proven reserves are in Sumatra (22 TCF), Java (5.5 TCF), Kalimantan (20TCF), Natuna in South China Sea (36 TCF), Sulavesi (0.4 TCF) and Irian Jaya(0.2 TCF). About 90 4 of these reserves is non-associated and can bedeveloped independently of oil. In 1987, gross ratural gas production wasabout 1.7 TCF (300 million boe).1/ Since 1980, natural gas output hasincreased at an annual average rate of 7.5 Z. Indonesia's large gasreserves suggest a continued growth in natural gas production which isprojected to outpace production of crude oil in the coming decade. GOIestimates gas production to increase to 2.8 TCF (490 million boe) by1993/94.

1.5 Coal. Total coal resources are estimated to exceed 25 billiontons located primarily in Sumatra and Kalimantan, proven reserves of whicha,e estimated at 1280 million tons. The current production level is 2.7million tons per year with plans to boost production to over 10 milliontons annually in the early nineties. GOI envisions coal as a major fuelfor power generation as well as a growing export commodity. Work on athree million ton-per-year mine at Bukit Asam in South Sumatra and on a 0.6million ton-per-year mine at the nearby Muara Tiga coal field is nearingcompletion. TLe Bukit Asam mine is estimated to have 2 billion tons ofcoal reserves. Its output is now usei mainly as fuel for power generation,specifically for the thermal station in Suralaya, West Java. In Ombi'Lin,West Sumatra, which is estimated to have 150 million tons of reseives, GOIis implementing a rehabilitation and development program to raise theproduction rate from the current 0.75 mil'lion tons per year to 1.3 milliontons per year, mostly for export. In Kalimantan, exploration activitiesundertaken by contractors under production-sharing arrangements with theGOI have defined 700 million tons of recoverable coal in the region.

1.6 Hydropower. Hydroelectric potential has been estimated to total75,000 MW consisting of 22,370 MW in Irian Jaya, 21,600 MW in Kalimantan,15,000 MW in Sumatra, 10,200 MW in Sulawesi, 4,200 MW in Java, 620 MW inBali and Nusa Tenggara, and 430 MW in Maluku. It is estimated that some34,000 MW of the total potential can be developed for power generation.But while Indonesia's hydroelectric resources are large, their developmentis limited by their geographic distribution relative to demand. Thegreatest potential (over 307) lies in Irian Jaya where the demand is less

1/ 1 TCF of Gas = 176 million barrels of oil equivalent

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than 12 of total domestic demand, while Java wqhich accounts for 80% ofelectricity consumption has less than 6% of the total potential. Existinghydroelectric installations total about 2800 MW and are mostly situated inJava (1,840 MW). Sumatra *(736 MW), and Sulawesi (203 MW). Schemes with anaggregate capacity of about 300 MW are currently under construction andbased on a systematic countrywide resource survey conducted by the StateElectricity Corporation (PLN), various prefeasibility and feasibilitystudies of identified hydroelectric sites are being pursued.

1.7 Geothermal Energy. The Indonesian archipelago lies in a volcanicbelt and has large geothermal energy potential estimated at 10,000 MW ofwhich 5,500 MW is in Java and Bali, 1,100 MW in Sumatra, 1,400 MW inSulawesi and 2,000 MW in other islands. Several sites have beeninvestigated of which the first to be developed was the Kamojang field inWest Java. In 1976, GOI, in collaboration with the Government of NewZealand, initiated development of the field and the first 30 MW generationset was commissioned in 1983. Additional power plant installation, of 110MW was commissioned in 1987. In 1982, PERTAMINA (The National Oil and GasCompany) entered into a joint operation contract with Union Geothermal, asubsidiary of Union Oil of California, for development of the Salak fieldin West Java. A. potential of over 200 MW has been proven by exploration.Pertamina has also explored geothermal fields in the Dieng and Drajat areasin Java, which appear promising for further development. During the nextfive years, exploration drilling in 14 areas in Java has been programmed aswell as the development of the Salak and Drajat fields to the extent of 110MW each.

Power

1.8 Electricity demand has grown rapidly in Indonesia with per capitaconsumption expanding from 59 kWh in 1977 to about 200 kWh in 1988.Despite the rapid growth, only 24Z (542 urban and 13% rural) of allhouseholds in Indonesia have been electrified as of 1988. The principalsources of electricity supply have been PLN (State Electricity Corporation)and self-generation by industries. PLN's total installed capacity in1988/89 was 8100 MW. PLN's sales grew by about 14Z per year since 1982 dueto increased consumption by existing customers, opening up of new serviceareas and the gradual take-over of supply to industries with captivegeneration. At the same time, captive capacity continued to increase,reaching 7000 MW in 1988 2/ meeting the growth in industrial demand thatcould not as yet be serviced by PLN. GOI's development program for theelectricity sector is aimed at raising the electrification ratio to 35% by1993/94 and to 54% by 2000/01. It also calls for tv- substitution by PLNgrid supply of 80X of captive generation in Java by .993/94. To achievethese targets, PLN's proposed expansion program will .aise PLN's installedrapacity to 12000 MW by the end of 1993/94 and to 22000 MW by 2000/01. Bygiving priority to the development of coal, natural gas and geothermal-based power plants, PLN's least cost program will result in a reduction inthe share of oil anc diesel-based capacity from nearly 60Z in 1987/88 toless than 32Z by 1993/94.

2/ Including 1900 MW capacity in five major enclave projects.

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Organization of the Energy Sector

1.9 The Ministry of Mines and Energy (MME) is the principal agencyresponsible for the development and implementation of Government policiesin the energy sector. The MME was established in 1978 to coordinate andsupervise the activities of public and quasi-public enterprises operatingin the sector, namely: PERTAMINA, responsible for the development of Al,gas and geothermal resources; P.T. Aatubara and P.T. Bukit Asam for coalmining and developm,;nt; PLN for electricLty supply; and PGN for gasdistribution. Othe miristries and agencies at, also involved in thesector. These include the Ministry of Public Works, which deals withhydropower resource surveys; the Ministry of Forestry, which overseesforestry products; and the National Atomic Energy Commission. which isresponsible for nuclear development. To ensure proper coordination ofenergy policy, the GOI has established a cabinet-level interministerialNational Energy Coordinating Board (BAKOREN) to oversee sectoraldevelopment. Reporting to BAKOREN is the Energy Resources TechnicalCommittee currently chaired by the Director-General for Electricity and NewEnergy; the committee is tasked with the formulation of the energydevelopment plan and providing policy advice and assessment to BAKOREN.

The Natural Gas Subsector

1.10 The gas subsector is regulated and monitored by the MME throughthe Directorate General of Oil and Natural Gas (MIGAS). The entitiessupervised by MIGAS are ka) PERTAMINA which is responsible for explorationand development of gas fields (including supervision of production-sharingcontracts), as well as transmission and distribution of gas to bulk users;and (b) PGN (State Gas Corporation), which is responsible for the supplyand distribution of manufactured and natural gas to medium-sized and smallindustries, commercial establishments and domestic consumers. In addition,MIGAS issues licenses to service companies that conduct business in thepetroleum and gas sector, enforces safety and environmental regulations andsupervises training for local workers. MIGAS also includes LEMIG'AS(Research and Development Center for Oil and Gas Technology) and PPTMGB(Oil and Gas Manpower Development Center).

Gas Utilization

1.11 Natural gas production has steadily increased from 0.5 TCF in 1981to 1.5 TCF in 1984 and reached 1.7 TCF in 1987. Of the 1987 production,(4600 MMCFD), 232 was used for field operation, 8.5Z was flared, 53Z wasused in liquid natural gas (LNG) production, 9Z in fertilizer production,and the balance of 6.52 (300 MMCFD) was utilized as commercial fuel andprocess gas. Domestic consumption of natural gas has largely beenrestricted to use as feedstock, process gas and fuel in fertilizerproduction, the steel industrv, refinery and LPG operations, and cementplants located near gas supplies. Small city and town systems operated byPGN and power generating units run by PLN have also used small amounts ofgas. In 1987, the cement sector accounted for 0.7X of total commercialfuel and process gas consumption; the steel industry for 2.4?; LPGproduction, 1.42; refinery operation, 1.22; the power sector, 0.32; andother industries, 0.5Z.

1.12 Developrn,ent of natural gas for domestic use as fuel has beenlimited because large gag fiejds are generally located far from the majorcenters of population and industry and infrastructure for bringing thesegas supplies to the end-consumers at reasonable costs have yet to besufficiently developed. Consequently, most gas production has beendirected towards LNG operations situated on-site or adjacent to the fields.But with slowdown in the growth of the Far Eastern LNG export markets, useof Indonesia's large surplus reserves for domestic energy consumption isbecoming more economically attractive. In particular, the large offshoreand onshore reserves in Java and Sumatra readily lend themselves fordevelopment as fuel sources in view of their accessibility to the majoreconomic and industry centers at Surabaya and Medan. Natural gas is nowconsidered as the most economical fuel (except for coal in certain cases)fo: power generation and manufacturing industries in these regions.Accordingly, GOI is promoting the use of gas as a substitute for highervalue oil, thus releasing petroleum products for exports. Potential demandfor gas in FY91, on a fuel substitution basis, is estimated by GOI to reach480 MMCFD (31 million boe/year) in West Java, 300 MMCFD (19 millionboe/year) in East Java (19 million boe/year), and 337 MMCFD (22 millionboe/year) in Sumatra.

Key Sectoral Issues and Strategy

1.13 Dominant issues in the gas sub-sector relate to (a) development ofa regulatory framework to promote safe and efficient utilization of naturalgas; (b) establishment of least cost long-term gas development program; (c)creation of modern and efficient institutions to manage natural gastransportation and utilization; and (d) formulation of an appropriate gaspricing policy.

1.14 GOI's strategy to facilitate economic substitution for petroleumproducts in domestic energy consumption, by non-tradeable, indigehLousnatural gas involves coordinated pursuit of four courses of actions:(a) expansion of gas supply in Java and Sumatra through efficiently phasedand designed infrastructure projects; (b) building of institutions andupgrading the Indonesian expertise in gas technology; (c) studies to helpdefine long-term plans; and (d) review and formulation of a gas pricingpolicy that would attract investors further to explore and develop gasresources, as well as to encourage energy consumers to substitute gas forliquid petroleum products wherever economical.

Natural Gas Sub-sector Planning

1.15 Due to the availability of ample gas reserves in Java and Sumatra,where the demand for energy is immediate, and to forestall environmentalpollution, GOI has given priority to the expansion of gas supply anddistribution systems in these islands. As a first stage of planning, GOI,through PGN, has formulated a medium-term program consisting of discreteexpansion projects for existing service areas of PGN in Java and Sumatra.The on-going Gas Distributien Project (Loan 2690-IND) for expanding PGN'sfacilities in Jakarta and Bogor in Java, and for Medan in North Sumatra ispart of this strategy. It involves laying of supply and feeder mains tonine industrial and commercial areas and setting up local distribution

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networks to serve an initial core group of 350 new industrial consumers and800 large commercial consumers. As part of the same program. GOI plansnext to expand the use of gas for power generation and manufacturingindustries in and around Surabaya (East Java) and Medan (North Sumatra)through the rehabilitation and expansion of gas transmission anddistribution systems in these cities. This will be the core of theproposed Gas Utilization Project.

1.16 Parallel to the implementation of the medium-term program, GOI isdefining a long-term plan for Java and a strategy for expanded gasutilization for which it has commissioned the Java Gas Grid Study under abilateral assistance from the Dutch Government. This study commenced inSeptember 1988 and is expected to be completed by June 1990. A similarstudy for Sumatra is under consideration.

Insitutional Development

1.17 Apart from the expansion of infrastructure, the building ofinstitutions to sustain the growth and to ensure efficient utilization ofgas has been a key component GOI's planning from the outset. Under thecurrent Gas Distribution Project (LN. 2690-IND), PGN is being transformedinto a modern gas utility through a Bank-designed long-term technicalcollaboration (twinning) with British Gas; and an Energy Pricing PolicyStudy is being conducted to provide a basic framework to promote theefficient use of fuels. Under the proposed project, GOI plans to developand institutionalize Indonesian expertise in (a) promoting safe andefficient gas usage, through the establishment of a Gas TechnologyDevelopment Unit, (b) long-term planning and growth management of gasutility business by enhancing PGN's capabilities, and (c) coordination ofdevelopment planning in the gas sector and improvement of gas safetyregulation by upgrading the capabilities of MIGAS.

1.18 The Gas Technology Development Unit will be established withinLEMIGAS, which is a department of MIGAS entrusted with research anddevelopment of oil and gas technology under a statute that permits it toundertake such activities. Its scope is outlined in the terms of reference(Annex 4.02) for its on-going planning study. This study is beingconducted by the Institute of Gas Technology (IGT) of Illinois, USA and isexpected to be completed by June 1990. Through high quality research andreliable dissemination of knowledge, this Unit is expected to establishitself as a primary source of technical information on natural gas. Itsprincipal interactions will be with:

- the government, for legislation and human resourcedevelopment;

- the gas producing and marketing companies, for research onstandards, materials and equipment;

- the universities, for development of curriculae for gasengineering and technology courses;

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manufacturing industry, for the manufacture of efficientmaterials, equipment and appliances; and

- the consumers of gas and other fuels, for interfuelsubstitution and energy conservation.

1.19 PGN is steadily developing its expertise in all areas of the gasutility business and has increased its credibility with its customers andthe Government. It has demonstrated its medium-term planning skills in thepreparation of the proposed project and now intends to develop its skillsin longer-term planning, growth management and system optimization, underthe proposed project.

1.20 Development planning for the gas sector requires activecoordination by the Ministry of Energy through MIGAS. It involvesassessing exploration and production schedules at the supply end, andmatching these with the build-up of suitable markets and the phasing in ofinvestments in transmission and distribution systems. To pursue this roleeffectively, MIGAS will need to strengthen its technical expertise indetailed evaluation of natural gas expansion plans. MIGAS also intends toenhar.ne its capability for developing a legislative, regulatory andtechnical program (with technical support from the proposed Gas TechnologyDevelopment Unit) to ensure that natural gas delivery and utilizationsystems in Indonesia will continue to be installed and operated safely.

Gas Pricing

1.21 The gas tariff in Indonesia is characterized by differentialpricing, largely reflecting GOI's development priorities among users.Producer prices paid by PERTAMINA are determined within the context ofproduction sharing agreements. PERTAMINA, in turn, sells gas to consumersat prices fixed by the GoveLnment which may be higher or lower than theproducer prices, thus implying cross-subsidies among users. The currentcategories of users and the applicable gas charges are as follows:

Table 1

Category US$/MMBTU a/

Krakatau Steel 0.65 for use as feedstock inproduction process2.00 for use as fuel for power

Fertilizer 1.00Other Industries 3.00PLN (Electricity) 2.53 in East Java; 3.00 in North SumatraPGN purchase price 2.00PGN city gas selling price 2.86

a/ At the exchange rate of Rp l,750/US$.

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1.22 Since the present structure of gas and other fuels pricing is notconsistently based on the economic costs of supply and the economic valueto Indonesia of alternative energy resources that gas replaces, the signalsreceived by the gas producers and users make it difficult to ascertair :heappropriate balance between supply and demand for gas. Accordingly,through the on-going Energy Pricing Policy Study funded by the Bank underthe Gas Distribution Project (Ln. 2690-IND), GOI is reviewing gas tariffsin the context of an overall energy pricing review, with the objective ofdeveloping a comprehensive energy pricing strategy that will encourageincreased gas production, especially of non-associated gas, as well aspromoting increased gas utilization by the power and industrial sectors.

1.23 The general objective of the energy pricing review is to minimizedistortions in domestic prices by using economic costs of supply andnetback value as benchmarks. Specifically, the price for nontradeablesurplus energy resources such as natural gas, coal and geothermal steamwould be established with the costs of competing fuels as ceilings and theeconomic cost (LRMC) of supply as the floors. The domestic prices ofpetroleum products, particularly kerosene and diesel, will also need to bere-aligned to correct distortions between domestic and internationalprices. To illustrate, preliminary findings of the Energy Pricing PolicyStudy indicate that the marginal cost of most gas supply in Indonesia isestimated to be less than US$0.50 per MCF at field gate, and depending onthe transport route, gas costs wo;l d range from US$1.00 and US$1.50 per MCFat city-gate. The latter cost is .ess than half the international price ofsubstitutable petroleum products (equivalent to US$2.9 per MCF in the caseof fuel oil and to over US$4.0 per MCF for other products). These suggestthat gas tariffs to the final consumer could be set between US$1.50 andUS$2.9 per MCF if fuel oil is to be replaced, with the actual level to bedetermined by the equipment conversion cost of customers, and by financialand fiscal considerations.

1.24 In addition, under the Power Sector Efficiency Project, the GOIhas agreed to specific proposals for institutionalizing the process ofreview of the energy prices, including the prices of petroleum fuels (LPG,kerosene, gasoline, diesel, fuel oil), gas, geothermal steam, coal andelectricity. The proposals consist of the following:

(a) establishment of an Interdepartmental Energy Pricing TaskForce to review and to advise Government on energy prices --the Steering Committee for the "Energy Pricing Policy Study'would be the core group for this; and

(b) establishment of an Energy Pricing Unit in MME to provideanalytical support and technical data to the Task Force --the counterpart team for the Energy Pricing Policy Studycould be the core group for this.

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Bank Role and Strategy

1.25 The Bank's involvement in Indonesia's natural gas subsector beganwith the Fnergy Assessment Report of 1981, which concluded that alternativeenergy sources could be developed economically and expeditiously to replaceoil consumed domestically in order to conserve the limited oil reserves forexports. This was followed by studies (in 1984 and 1985) for Natural GasUtilization and City Gas Distribution financed under Fifth TechnicalAssistance Project (Cr. 898-IND). The Natural Gas Utilization Studysupported the policy of developing large-scale domestic markets for naturalgas as a substitute for oil. The City Gas Distribution Study confirmed thepotential for economical distribution of natural gas to medium and smallindustries, commercial entities and households in urban areas. It resultedin a decision to rehabilitate and extend the use of gas distributionsystems in Jakarta, Bogor and Medan, with the prospect for furtherimplementaticn in other cities. Assistance for this project was providedby the Bank through LN 2690-IND. This was the first Bank-financed projectin the natural gas sub-sector in the country. Since then, the EnergyOptions Review report of August 1987 prepared by the Bank has confirmed theimportant role of natural gas as a substitute for petroleum products tomeet the growing fuel requirements of the power, industrial and commercialsectors, especially in Java.

1.26 Currently, the Bank's involvement in gas is through threeactivities: (a) the gas distribution project (Ln 2690-IND) which, interalia, aims to strengthen the institutional capability of PGN to play a moreeffective role in gas distribution, (b) the Energy Pricing Policy Studyfinanced from the same loan, which is designed to help GOI to rationalizefuel prices and thereby promote efficient utilization, and (c) monitoringthe Java Gas Grid Study, funded by a Dutch grant, which should help definelong-term gas development strategies. Also, through close involvement inthe power sub-sector, the Bank has been promoting gas utilization for powergeneration which, in certain cases, can be managed to exploit economies ofscale in gas transportation, and allow the gas to be supplied to industrialand other pitential consumers at the lowest possible cost.

1.27 The expansion of natural gas utilization in Java and Sumatra wouldevolve through a number of discrete but interlinked projects. Formulationof adequate policies is necessary at this stage to ensure efficient sectordevelopment. Through project financing and ensuing policy dialogue, theBank can assist GOI irn (a) developing a natural gas pricing policyframework for optimizing its development and utilization, (b) determiningthe appropriate scale and phasing of investments, (c) formulating policiesconducive to private sector participation in natural gas utilization,including spawning of an efficient natural gas appliance manufacturingindustry, and (d) creating modern, efficient institutions to regulate andmanage natural gas transmission, distribution and utilization, as well asto develop technology and standards suitable to local conditions.

1.28 Mo,reover, the Bank will continue to assist GOI to coordinate thedevelopmer.t of gas and power strategies and to devise suitableinstitutional and financing arrangements which would attract private sectorparticipation in gas-fired power plants.

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II. THE BENEFICIARIES

2.1 The promotion of natural gas utilization in domestic energyconsumption would involve three organizations namely: PGN (State GasCorporation), for building and operating of gas supply facilities andconsumer conversion; MIGAS (Directorate General of Oil and Gas), for safetyregulation and coordination of development plans; and LEMIGAS (Research andDevelopment Center for Oil and Gas Technology), for research and develop-ment of standards to facilitate safe and efficient usage. Since PGN wouldbe the core organization for project implementation, receiving about 9oz ofthe proceeds of the loan, this chapter mainly refers to PGN and the otherbeneficiaries are briefly discussed at the end.

PGN (STATE GAS CORPORATION)

Background

2.2 PGN (Perum Gas Negara) was .reated in 1958 as a Government agencyto take ovpr the foreign interests in the manufacture and distribution oftown gas in the cities of Jakarta, Bogor, Bandung, Cirebon, Semarang andSurabaya in Java; Medan in North Sumatra and Ujung Pandang in Sulawesi.With the availability of natural gas in west Java, several localdistribution systems in Jakarta, Bogor and Cirebon were wholly or partiallyconverted to natural gas during 1979-1982. Under a Government regulationof 1984, PGN was turned into a Public Corporation, which gave it someoperating autonomy within the Government regulations but restricted thecapital ownership to the Government. By 1985, PGN's total gas salesamounted to 95 million cubic meters (MMCM) per year, equivalent to anaverage sale of 7.4 million cubic feet per day (MMCFD), with a sales mix of702 natural gas and 30X manufactured gas, which was about 20X of the thenestimated potential demand from private industries and commercial entities.It had failed to expand the use of natural gas in the growing fuel marketprimarily due to lack of technical expertise. As a remedial measure, in1986 GOI negotiated and signed a Bank loan (No. 2690-IND) for PGN's firstmajor expansion project (the Gas Distribution Project) providing a ten-foldincrease in natural gas distribution (from about 5 MMCFD to 50 MMCFD) by1992 to about 350 medium size industries and 800 commercial entities inJakarta, Bogor and Medan.

2.3 The implementation of the Gas Distribution Project began inDecember 1986; its progress has been satisfactory and it is expected to becompleted by July 1991. The institution building of PGN is a keycomponent, for which the Bank designed a long-term collaboration (twinning)of PGN with a prominent and experienced gas utility (British Gas). Thisrelationship provided the means to integrate the know-how transfer andstaff training on site in the course of project implementation and exposedPGN to an experienced operating organization acting as a role model. Ithas been very successful, and has enabled PGN to upgrade its management andtechnical skills. PGN's on-going skills development program covers 130professionals (engineer, accountants and sales executives) and 250

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technicians of PGN, 200 technicians of gas pipeline constructioncontractors and internal gas n4Ding installers, and 800 technicians ofindustrial consumers.

2.4 Since 1986, PGN's sales have increased at an average rate of 362per year and its gas losses have been reduced from 302 to 6Z. Prior to1986, PGN operated at a loss, in FY88 it achieved breakeven and, in FY90 itmade a 2.6Z return on net fixed assets in operation, which was short of thetarget of 10X but still reflects a turnaround in its operations. (Thereasons for the shortfall are discussed in para 4.3). It is to PGN'scredit thet, despite the adverse domestic price movements in gas and liquidfuels, it was able to expand its gas sales in a competitive market throughskillful marketing.

Statutory Functions

2.5 The main functions of PGN under its charter are as follows:

(a) production, supply and distribution of manufactured gas;

(b) supply and distribution of natural gas to customers with acontracted demand not exceeding 5 MMCFD (except in specificcases with the prior permission of GOI);

(c) planning and construction of natural gas distributionsystems; and

(d) provision of services associated with the supply of gas andgas by-products.

Current Organization

2.6 PGN, being a state-owned utility, is held responsible to theGovernment through the Minister of Mines and Energy. It is managed by aBoard of Directors, which comprises a President Director and a maximum offour Directors appointed by the President of the Republic on therecommendations of the Minister of Mines and Energy. The Board ofDirectors is entrusted, under the statutes of the Government and within theguidelines set by the Minister of Mines and Energy, to draw up the annualwork plan and budget, appoint and discharge employees, establish pay scalesand determine the numbers and categories of staff required. Theperformance of PGN is periodically reviewed by a Board of Supervisors.This Board, also appointed by the President of the Republic, comprisessenior staff of the Ministrv of Mines and Energy and the Ministry ofFinance.

2.7 The President Director is the Chief Executive Officer of thecorporation. He is assisted by a Director Operations, a DirectorDevelopment, a Director Finance and General Affairs and an InternalAuditor. The Director Operations is responsible for gas marketing anddistribution systems operations. The Director Development is responsiblefor planning and design of new transmission and distribution systems, their

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construction management and procurement of materials. The Director Financeand General Affairs is responsible for finance, personnel management,general administration and stores management.

2.8 PGN's field activities are geographically organized through eightregional branches, located at Jakarta, Bogor, Bandung, Cirebon, Semarangand Surabaya in Java, Medan in North Sumatra and Ujung Pandang in SulawesiThe gas marketing and distribution system operations in the regions aremanaged by Branch Managers who report to the Director Operations andmaintain functional links to other Directors. The construction activity ismanaged by Project Managers who are responsible to thz Director Developmentand maintain functional links to Branch Managers and the other directors.

2.9 Each Director is supported by Sub-Directors with responsibilityfor a major function or a group of smaller functions. Additionally somekey functions i.e. research, train.ing and information service, are headedby Senior Managers reporting directly to the Board of Directors. Thisstructure (Annex 3.01) was agreed with PGN and implemented as a conditionof loan effectiveness under the on-going Gas Distribution Project (Ln.2690-IND).

Proposed Reorganization

2.10 To facilitate the management of increased corporate anddevelopment activities under the proposed project, PGN will enlarge itsexisting management structure and regroup some of the functions. In theproposed reorganization (Annex 3.01) the President Director will beassisted by four Directors and an Internal Auditor. The titles of the fourDirectors and their responsibilities will be:

Director Operations - gas marketing, operation andmaintenance of gas transmissionand distribution systems;

Director Development - planning and design of gastransmission and distributionsystems, materials controland construction management;

Director Finance - corporate budget, finance,accounting and cost control; and

Director Administration - personnel management, procurementand Logistics and stores management, general

administration and legdl services.

2.11 The significant changes involved in the organization are: (i)consolidation of personnel management, logistics and administration underthe fourth Director to provide the necessary focus on performance andskills development; (ii) appointment of a sub-Director with the soleresponsibility for each of the functions of material control, maintenance,

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cost control and logistics to enhance operational efficiency and costeffectiveness; and (iii) the addition of regional planning in theresponsibilities of the Branch Manager to coordinate the projectpreparation and design with local authorities.

Technical Assistance Requirements

2.12 PGN has matured considerably during the execution of the on-goingBank financed Gas Distribution Project (Ln 2690-IND) with substantialincrease in skills in all areas of its operation, and has developedcredibility with its customers and the Government institutions with whichit interfaces. This rapid maturation has given PGN an adequate base fromwhich to undertake another expansion project. However, there is still alarge experience gap within the company as a result of earlier years ofstagnation and lack of recruitment. Therefore, PGN will require furthertechnical assistance, along the same lines as that in the current project.

2.13 This technical assistance is in the form of a long-term technicalcollaboration (twinning) with an experienced operat..g entity to provide abroad based package of technical assistance in key operating areas,integrate know-how transfer and staff training on site in the ,urse ofproject implementation and expose the client to mature operations of thecollaborating entity. In such an arrangement the seconded staff of theexperienced operating entity work in parallel with the client's nominatedstaff to build-up the client's skills and to upgrade its operations ratherthan the consultants being made responsible for discreet tasks. It ensuresa higher level of on-the-job training and a higher level of understandingand commitment by the clients' staff who remain responsible for all aspectsof project execution. It also permits the work program to remain flexibleovertime, permitting some variation in the input of technical assistance tosuit the project needs and staff capabilities.

2.14 Apart from strengthening its skills in the areas addressed in thecurrent project, PGN needs to develop skills for a larger role in the gasutility business, notably in long-term planning, growth management andsystem optimization. As PGN's current technical collaboration (twinning)relationship with British Gas is working well, it Lntends to extend thisarrangement (Annex 4.01) for the duration of the proposed project whichwill provide both continuity and consistency of approach. This has beenacceptable to the Bank.

2.15 PGN will finance this arrangement through bilateral aid and hassought assistance from the Overseas Development Administration (ODA) of theUK Government which in principle has agreed to continue funding it. Sincethe twinning arrangement is considered critical to the successfulimplementation of the project, its finalization would be a condition forloan effectiveness.

Human Resource Requirements and Training

2.16 The proposed project will involve about a two-fold increase inPGN's operation and a three-fold increase in its gas sales. Since under

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the current project (Ln 2690-IND) PGN is developing a sizeable base ofhighly skilled manpower (130 professionals i.e., engineers, accountantsand sales executives and 250 technicians) it will require proportionatelyless additional manpower to manage the proposed project and follow-onoperations. The additional staff it would need to employ would compriseabout 80 professionals in the fields of engineering, marketing, humanresource development and finance and approximately 100 technicians. AsPGN's pay scales are comparable with other public sector corporations, therecruitment of additional staff is not expected to po e any problems.During negotiations, it was agreed that GOI would allow PGN to maintain itspay scale at a level as remunerative as that offered by similar publicsector corporations.

2.17 In the proposed project, PGN's skills development program willcover, (a) the training of its newly recruited staff under a programsimilar to that being followed in the on-going project but expanded torecognize the new areas of PGN's operations (e.g. gas transmission andcompression); (b) advanced training to its existing professional staff inlong-term planning, growth management and system optimization; and (c) thetraining of an aaditional 200 technicians of pipeline constructioncontractors and internal gas piping installers and 700 technicians of theindustrial consumers in basic skills and safe operations. Duringnegotiations assurances were obtained that PGN, with the help of theconsultant to be appointed after the proposed loan is made, will prepare adetailed training program and discuss it with the Bank for implementationunder a timetable acceptable to the Bank.

Accounts

2.18 PGN's accounts are maintained in accordance with the "IndonesianAccounting Principles' issued in 1983, the relevant parts of theGovernment's 1984 regulations on public corporations, the 1984 Governmentdecree converting PGN into a public corporation, and the instructions fromPGN's management on specific accounting procedures. Each branch office isexpected to send a monthly financial report (mainly income statement) tothe head office within 5 days of the close of the month for consolidation,as well as an annual report within two months of the close of PGN's fiscalyear. PGN's annual consolidated statements are generally completed withinthree months of the close of its fiscal year as required for tax purposes.PGN's Board of Directors is required to submit the annual financialstatements to concerned Government agencies (including the State AuditBoard) within six months of the close of its fiscal year. Furthermore,PGN's Board of Supervisors submits quarterly and annual reports to theMinistries of Mines and Energy and Finance.

2.19 The accounts of each branch office are supervised by a certifiedbookkeeper and the timeliness and accuracy of reporting is generallysatisfactory. On the whole, PG1's accounting system follows generallyaccepted principles and utility practices. Under the ongoing project, ateam was formed within PGN for the implementation of an integratedaccounting system, including cost accounting and budgeting and forcomputerization of accounting routines (e.g. billing/collection, wages,

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stores, budgets and project accounts) to permit PGN to expand itsoperations in an efficient way. With the assistance of the twinning agencyand consultants, PGN has made substantial progress in the simplificationand computerization of its accounting routines and PGN staff have wellabsorbed the necessary computer skills. The new integrated accounting isexpected to be operational in FY91.

2.20 In recent years, PGN may have charged excessive amounts ofinterest to capital investment and transferred work in progress (WIP) toassets in operation before the work was actually commissioned and startedto produce revenues. The computerization of VIP and stores will becompleted in FY91, and this will provide PGN with the tools to improve itsproject accounting procedures. This may have an impact on PGN's incometaxes as well as the rate of return. During project implementation, thismatter will be reviewed to ensure a sound and consistent basis for rate ofreturn calculations.

Audit

2.21 According to its 1984 charter, PGN's accounts are audited byGovernment auditors: the Finance and Development Supervisory Board (BPKP),and if serious reasons so indicate, the State Board of Auditors (BPK). Forprojects financed by the Government, the Tschnical Department of theMinistry of Mines and Energy also carries out project audits. PGN'sinternal audit unit reports directly to its Board of Directors and consistsof five officers. External audits are carried out following generallyaccepted audit practices and PGN's audit arrangements on the whole aresatisfactory. PGN's financial statements are generally submitted for auditwithin 4 months of the end of PGN's fiscal year. The number ofobservations in the audit reports has been substantially reduced in recentyears and PGN expects a FY89 report without qualifications. Audit reportsare often finalized late, however, about a year after the closing of PGN'sfiscal year. During negotiations, agreement was obtained that PGN willprovide the Bank with its unaudited annual financial statements within sixmonths of the end of its fiscal year, and the corresponding audited reportwithin nine months after the end of its fiscal year.

Budgeting

2.22 Under its charter, PGN is required to submit its project andoperating budgets to it,; Supervisory Board for review and to the Ministriesof Mines and Energy and of Finance for approval. Budgets have to besubmitted at least three months before the start of the budget year. Ifthe Government does not object to PGN's budget before the budget yearbegins, the budget is implemented as submitted. Supplementary or amendedbudgets may be submitted during a budget year following the same proceduresas for the annual budgets. As a public corporation, PGN can redistributeamounts between different headings in its operating budget on directivefrom its Board of Directors. The budget procedures prescribed for PGN arereasonably flexible and should be adequate for carrying out the proposedproject. PGN's internal procedures for preparing its budget and monitoringactual expenditures have been improved with the assistance of the twinningagency; as from FY90, expenditures are compared with budget estimatesmonthly within five days of the close of the month.

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Billing and Collection

2.23 PGN bills its customers monthly and gas bills generally reach thecustomers within a month after the close of the billing period. In 1986,bills were prepared with the help of obsolete office machines and monthlysummaries for accounting purposes were prepared manually. Under theongoing project, PGN was provided with adequate equipment and is nowimplementing the computerization of its billing and collection procedures.Customers generally pay their gas bills ;ithin one month after receipt, asrequired by PGN, and the value of outstanding bills currently equals lessthan two months of billing, which i3 satisfactory. The number of unpaidbills is insignificant and PGN's current provisions for bad debts appearadequate.

Insurance

2.24 PGN's assets are spread over eight different cities and any singleloss would be relatively small in comparison with PGN's total assets andoperations; PGN, therefore, did not carry any comprehensive insurancecoverage, except for vehicles and material in transit. Under the ongoingproject, PGN agreed to review the adequacy of its insurance coverage anddiscuss the findings of the review with the Bank. This resulted in astrengthened insurance coverage for PGN, including a blanket cover ofcapital works in progress combined with fire insurance for assets inoperation and third party injuries and/or damages. Assets underground arenot insured. This insurance coverage is acceptable and in line with gasindustry practices. However, during the implementicion of the proposedproject, PGN's insurance coverage will be monitored to avoid doublecoverage, e.g. by PGN and turnkey contractors for major nipe works.

MIGAS AND LEMIGAS

2.25 MIGAS (MINYAK DAN GAS BUMI) is the Directorate General of Oil &Gas in the Ministry of Mines & Energy. lt is responsible for planning,regulating and monitoring the development and utilization of hydrocarbonand aeothermal resources in the country. It is headed by a DirectorGeneral who reports to the Minister of Mines & Energy. The DirectorGeneral is assisted by six Directors, responsible for: exploration andproduction of oil and natural gas; exploration and production of geothermalresources; technical services; business development; research inhydrocarbon development and utilization; and human resource development.

2.26 LEMIGAS (PUSAT PENELITIAN DAN PENGEMBANGAN TEKNOLOGI MINYAK DANGAS BUMI) is the organization for research and development of oil and gastechnology. It was established in MIGAS in 1984 with the followingstatutory functions:

- research to £acilitate the development and utilization of oiland natural gas resources in Indonesia;

- collection and dissemination of technical information; and

- technical consultancy service to the oil and natural gasindustry in the country.

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2.27 LEMIGAS currently employs about 900 professional and support staffof whom more than 200 hold university degrees and a further 37 hold post-graduate qualifications. Its current duties include survey and evaluationof oil and gas deposits and research in oil production, processing andutilization. MIGAS now wants it to acqui-e expertise and facilities forresearch to promote safe and efficient natural gas utilization through theestablishment of a Gas Technology Development Unit. Organograms of MIGASand LEMIGAS are given in Annex 3.02. The organization of the GasTechnology Devrelopment Unit will be determined after the completion of itsplanning study (para 1.18) and its implementation will be a condition forthe disbursement of funds allocated under the project.

III. THE PROJECT

Background

3.1 The Bank's Energy Assessment Report of 1981 and the studies of1984 and 1985 for Natural Gas Utilization and City Gas Distributionfinanced under Cr. 898-IND, established a basis for expanding the use ofnatural gas in domestic consumption, and identified the need forinstitutional and policy reforms in the sector to facilitate thepenetration of natural gas in the domestic economy. Accordingly, the on-going Gas Distribution Project (Ln 2690-IND) was formulated and launched in1986 for: (a) the expansion of gas supply to medium-size industries andcommercial entities in Jakarta, Bogor and Medan; (b) the institutionalstrengthening of PGN to enable it to function as the core organization forthe development of gas utilization; and (c) the Energy Pricing Policy Studyto provide a framework for developing a comprehensive energy pricingstrategy. Subsequiently, the Bank's Energy Options Report of 1987reconfirmed the importance of natural gas as an economic substitute forpetroleum products to meet the growing fuel requirements of powergeneration, and the industrial and commercial sectors, especially in Java.The proposed projeL.t is a follow-up to consolidate the gains being made inthe on-gcing project and to sustain and accelerate the economic expansionof natural gas utilization.

Market

3.2 The market to be served by the project comprises medium-sizedindustries and large commercial firms and three large customers i.e., PLN'stwo power stations in the Medan area dnd a paper mill at Leces, about 80 Kmsoutheast of Surabaya. Residential and small industrial/commercial demandshave not been considered in view of the relatively higher cost involved insupplying low volume consumers. Focusing on large-volume consumers wouldrender PGN's operations more cost-effective permitting strong product com-petitiveness and enabling PGN to establish its market base faster. Based onmarket surveys conducted by PGN, the current and potential average and peaksales of gas in the project areas of Surabaya and Medan are estimated to beas follows:

Table 2

FY ending 1992 1993 1994 1998 1998 2000 2005

Ove. max. ave. Max. ave.max. ve.max. ave.max.ave.max. ave.max.

--------------------------------- UMCFD--------------------------------

SurabayaIndus./Commercial 0 0 0 6 8 28 27 60 68 80 72 70 84Paper Lecos O 0 0 0 6 6 20 22 20 22 20 22 20 22

Total 2 2 0 0 10 14 43 49 70 80 80 94 9018

MedanIndustries 6 6 12 14 1° 14 12 14 12 14 12 14 12 14PLN ao 46 48 74 48 74 48 74 48 74 48 74 48 74

Total TS E i 8 088088 80 8i 0 80 g 88 80 i

3.3 In the Surabaya area, PGN's market presence is currentlyrestrictc_ Lo the distribution of manufactured gas and LPG supply to 38small industrial and commercial users and 3,572 domestic consumerssituated in downtown Surabaya. Gas sales in FY89 consisted of 0.20 MMCFDof manufactured gas to industrial and commercial consumers, and 1,290 tonsof LPG to domestic consumers. There are about 3,000 industrial andcommbrcial enterprises using petroleum products as fuel in Surabaya and 12small towns in the vicinity, of which 340 medium-s.ze industries and 150commercial entitites, accounting for about 702 of the total demand, havebeen targettel for natural gas supply under the project. There is also amajor industry, the paper mill at Leces, that would like to substitutepetroleum product fuels (fuel oil and diesel) with natural gas. Accordingto the current rules, major consumers (contracting for more than 5 MMCFDgas supply) should be PERTAMINA's customers, which in this case wouldentail duplication of investments in supply facilities. To avoid this,PERTAMINA and PGN have agreed that the Leces paper mill will be PGN'scustomer. The average-day sale of natural gas is projected to grow from10 MMCFD in FY94 to about 80 MMCFD by FY2000 and to about 90 MMCFD by'-Y2005.

3.4 In Medan, PGN currently supplies natural gas to about 100 medium-sized industrial and commercial consumers, 2000 households and a PLN'spower station at Paya Pasir near Belawan. The industrial, commercial andhousehold consumers are PGN's customers, while the PLN power station isPERTAMINiA's customer. PGN is paid a carrying charge by PERTAMINA fortransporting gas to the power station. In FY90, PGN's average day supplyto its customers and to PLN's power station reached 5 MMCF and 30 MMCFrespectively. Urnder the proposed project, it is expected to increase to60 MMCF (including 48 MMCF for PLN9s stations) by FY93. Further growthwill depend on the availability of gas supply from the fields beingappraised and developed in the vicinity. The PLN stations will remainPERTAMINA's customers and PGN will be paid an adequate charge (beingnegotiated) for transporting gas to these stations.

3.5 The sale forecasts are considered reasonable given the stablebase of industrial activity in and around the cities of Medan and

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Surabaya, and the target levels of gas connections under the project aredeemed achieveable particularly in the light of recent PGN experience inpenetrating the liquid fuels market.

Gas Supply

3.6 PGN's Surabaya gas transmission and distribution system can beprovided up to 90 MMCFD natural gas from ARCO's Kangean offshore field(located about 250 miles east of Surabaya) througn an offshore pipeline tobe laid by ARCO from Kangean to a landing point at Porong. This pipelineis being planned to provide 220 MMCFD gas supply for PLN's power stationat Gresik and 60 MMCFD gas supply for Petrokimia, also at Gresik, inaddition to the aforementioned quantity for PGN. The supply for PGN willbe at a pressure of 17 to 20 bars. The pipeline is required to be builtand commissioned within thirty months of the signing of the gas supplycontract between PLN and PERTAMINA. (The gas supply agreement between PLNand PERTAMINA was signed in March 1990.) This gas supply would meet thelevel of consumer demand (para 3.2) that is expected to be attained by2000. Increments in demand above that level can be met from thedevelopment of other offshore fields, particularly Mobil's recentdiscovery of non-associated gas about 80 Km offshure Leces.

3.7 The gas delivery from PERTAMINA's onshore fields to PGN'sexisting supply system for Medan is being raised from 30 MMCFD to 40 MMCFDat Pangkalan Brandan to provide additional gas to PLN's power station atPaya Pasir near Belawan. An additional 20 MMCFD gas from PERTAMINA'Sonshore fie'.a, near Wampu, is now planned to be delivered at Payapasirthrough a 24 Km long transmission pipeline to be built under this project.As this supply would only partially meet PLN's demand of 270 MMCFD,further development of fields in the vicinity is being undertaken byPERTAMINA to enhance the supply.

3.8 The conditions of gas supply for the Surabaya and Medan areasinvolving quantity, price, and the carrying charge for PGN'stransportation of the desired quantities to PLN's power stations at Medanare being negotiated. The execution of supply contracts, satisfactory tothe Bank, betT .Fen PGN and PERTAMINA for gas supplies to the Surabaya andMedan systems covering the project requirements, will be a condition ofloan effectiveness. Additionally, PGN will have to continue to prepare(as under the ongoing project agreement) a rolling five-year plan coveringits future gas requirements to be updated each year and discussed with GOIand PERTAMINA to form the basis for further network expansion.

Project Objectives and Rationale

3.9 The primary objective of the project is to support GOI's programof diversifying domestic energy consumption away from heavy reliance onpetroleum products by substituting petroleum product fuels in powergeneration, industrial and commercial sectors with natural gas. Thisobjective will be pursued through:

(a) the provision of an assured supply of natural gas, atcompetitive prices, to power plants, manufacturing

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industries, and commercial entities in Surabaya and twelveother towns in its vicinity in East Java and in Medan inNorth Sumatra;

(b) the integration of gas utilization plans and operations toachieve economies of scale in the development and operationof gas supply infrastructure;

(c) istitution building, technology transfer and, marketingstudies to accelerate safe and efficient utilization ofnatural gas and to help define its long-term developmentplans.

3.10 The use of natural gas by small and medium-sized industries inSurabaya and Miedan is expected to yield an average economic netback valueto Indonesia of US$4.1 per MMBTU and US$4.3 per MMBTU, respectively,compared to an estimated cost of gas supply of UJS$1.50 per MMBTU. Forpower generation, the netback value for gas is estimated to exceed US$3per MMBTU relative to a plant using industrial diesel oil (IDO). Gassales to industries will be largely market-driven as gas prices will haveto compete with the domestic price of liquid fuels creating a strongincentive for the gas sector constantly to strive for efficiency in itsplans and operations.

3.11 Identificatior and selection of Surabaya and Medan as projectservice areas is based on the availability and accessibility of abundantproven gas reserves and the existence of a market ready to shift from useof liquid fuels to natural gas. By integrating the gas utilization plansof the power sector with that of industrial and commercial users in thedesign of common delivery systems, the project would be able to achieveeconomies of scale in the establishment of the gas transmission anddistribution networks. Moreover, the economic base in the these cities isdeemed adequate to sustain a growing demand for energy creating favorablelong-term prospects for a stable and expanding market for gas.Accordingly, by focussing on these service areas, it is anticipated thatfaster gains in GOI's program for increasing the share of natural gas indomestic energy consumption will be achieved.

3.12 The expansion of natural gas utilization, being linked with thedemand and resource development, would involve lumpy infrastructureinvestments in the form of discret; but interlinked projects spread overseveral years. Efficient planning and phasing of these investments,implementation of projects and the management of follow-up operationswould therefore require building of Indonesian institutions for long-termplanning, growth management and safe utilization. The proposed projectaims to bring about the development of these capabilities through theinstitution building and interaction of PGN, LEMIGAS and MIGAS.

3.13 Specifically the project aims to:

(a) promote the use of natural gas as fuel for power generation,manufacturing industries and commercial entities by

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constructing new gas transmission and distributionfacilitiesfor Medan and Surabaya;

(b) develop Indonesian expertise in long-term planning of gasutilization, including the planning of integrated supplysystems common to all categories of consumn :s, through theskills upgrading of MIGAS and PGN and through theestablishment of a Gas Technology Development Unit inLEMIGAS;

(cj build PGN's expertise in the optimization of expanding gassupply systems and the management of expanding gas utilityoperations;

(d) develop cost effective standards and codes of practicesappropriate to the Indonesian environment for safe, -

efficient transportation and utilization of natural gasthrough research at the proposed Gas Technology DevelopmentUnit; and

(e) promote the establishment of a regulatory system for safeutilization of natural gas under the control of MIGAS withthe technical support of the Gas Technology Development Unitand active participation of PERTAMINA, PGN and themanufacturers of transportation and end-use equipment.

3.14 Other objectives of the project are to:

(a) enhance the safety and efficiency of PGN's operations inSurabaya through the rehabilita&ion and replacement of itsout-dated pipeline networks; and

(b) reduce environmental pollution by using gas which is acleaner fuel than the other fossil fuels it would replace.

Project Description

3.15 The project consists of four main components:

A. Provision of Natural Gas Supply System in Surabaya and itssurrounding areas, involving:

(i) the laying of about 80 km of high pressure transmissionpipelines, 190 km of medium pressure steel pipelines and165 km of medium pressure polyethylene pipelines;

(ii) the construction of 5 gas metering, pressure regulating andodorization stations with associated instrumentation and 4pressure reducing stations on the pipeline networks; and

(iii) the construction of service lines, pressure regulationand flow metering stations for 375 medium size industriesand 150 commercial enterprises and the paper mill in Leces.

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B. Expansion of Natural Gas Supply System for Medan involving:

(i) the construction of about 24 km of high pressuretransmission pipeline with associated cathodic protection,pressure/flow monitoring facilities and three pressurereducing stations; and

(ii) construction of service lines and pressure regulating FT

and flow metering stations for two PLN power stationsat Belawan.

C. Technical Assistance involving:

(i) enhancement of PGN's skills and efficient implementation ofits expansion project;

(ii) establishment of a Gas Technology Development Unitin LEI4IGAS; and

(iii) upgrading of skills in MIGAS to facilitate the coordinationof development plans in gas sector and to institute aregulatory system for safe utilization of natural gas.

D. Studies: Feasibility studies for natural gas marketing inPalembang (South Sumatra), Jambi (Central Sumatra), Batam Island(Riau), and Balikpapan (Kalimantan).

Gas Supply Systems

3.16 The project provides for the detailed design, construction,testing and commissioning of gas supply systems involving high pressureand medium pressure natural gas transmission and distribution networks,pressure regulating stations, service lines and customer meter stationsfor the supply of natural gas for power generation, manufacturingindustries and commercial entities in Surabaya and its environs andadditional supply for similar consumers in Medan on the basis of theconceptual design prepared by PGN with the assistance of its consultants(British Gas).

3.17 The Surabaya supply system, comprising the gas transmission aswell as the distribution networks, will cover Surabaya city and twelveother towns in East Java within a 100 Km distance from Surabaya. It willsupply natural gas to about 375 medium-size industries, 150 largecommercial enterprises and the paper mill at Leces. The existing lowpressure manufactured gas distribution system supplying 3600 households ina limited area in downtown Surabaya will be rehabilitated and integratedwith the planned system after conversion to natural gas.

3.18 PERTAMINA has indicated an input pressure of 17 to 20 bars forthe Surabaya system at the receiving stations. The max-day demands of theconsumers in the medium and long term (i.e. by FY99 and FY2006) areestimated at about 90 MMCF and 120 MMCF respectively. Since Mobil

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recently discovered non-associated natural gas 80 Km offshore Probolinggo(near Leces), which is being evaluated, there is a possibility ofadditional gas supply at an input precsure of 40 bars. The additionalcost of increasing the system capacity by about 30Z (from 110 MMCFD to 140MMCFD) and the operating pressure capability by 130Z (from 17 bars to 40bars) is approximately US$5 million i.e., 1OZ of the basic cost. Thetransmission pipelines of this system have therefore been designed todeliver 140 MMCFD with an input pressure of 17 bars along with provicionfor raising the operating pressure to 40 bars. The design of distributionpipelines is based on the supply mains operating at 10 bars (the maximumsafe pressure under the prevailing procedures) and the reticulationnetworks at a uniform pressure of 4 bars, resulting in a simpler design,reduction in pipe size and substantial (about 20Z) reduction in cost ascompared with the alternative multi-stage pressure system. This approachhas alreadv been tried with good results in the distribution systemdesigns under the on-going Gas Distribution Project (Ln 2690-IND).

3.19 The expansion of the Medan supply system involving a highpressure transmission pipeline from Wampu to Payapasir will enable supplyof additional quantities of natural gas to the two PLN power stations atPaya Pasir and Belawan. The existing gas supply system for Medan comprisesa transmission pipeline from Pangkalan Brandan to Medan via Wampu and acompressor station at Pangkalan Brandan for boosting the pipeline inputpressure from 17 bars to 40 bars. The total max-day demand of theconsumers in Medan is estimated at 150 MMCF in FY93, growing to about 300MMCF by FY2000. About 60 MMCF of this demand will be met after theproposed expansion of existing supply systerm and the balance of 240 MMCFthrough further expansion of this system as additional gas becomesavailable upon development of other fields in the area.

Technical Assistance

3.20 To fulfill the institution 1-uilding aims as discussed in para 3.12,the project will provide multi-disciplinary technical assistance involvingthree organizations, namely PGN, LEMIGAS and MIGAS.

3.21 PGN will execute an agreement for its twinning arrangement (TORin Annex 4.01) for the duration of the project, with British Gas or withanother gas utilicy acceptable to the Bank to ensure successfulimplementation of this project concurrently with the on-going project.This arrangen&qnt will provide assistance in:

- detailed design and cost estimates, preparation of tenderdocuments and evaluation of bids for goods and services,preparation and monitoring of the project implementationschedule, construction management, market development, andcustomer conversion;

- planning and operation of integrated gas supply systems withautomated supervisory control and data acquisition;

- corporate planning and management of an expanding gasutility business;

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- long-term development planning, involving demandforecasting, gas supply systems optimization, investmentappraisal and risk analysis; and

- preparation of a training program as discussed in para 2.17.

3.22 Bilateral financing for this purpose is being discussed between GOIand the Government of the United Kingdom. The extension of PGN's twinningarrangement with British Gas (or execution of a similar agreement with anotherestablished gas utility), on terms of reference satisfactory to the Bank, willbe a condition for loan effectiveness.

3.23 A Gas Technology Development Unit will be established in LEMIGAS forthe development of in-house expertise in (a) research on ar.d development ofefficient and safe standards and codes of practices, appropriate to Indonesia,for all the activities in the transportation of natural gas and its usage; (b)studies and research in gas utilization, interfuel substitution and energyconservation; (c) human resource development; and (d) dissemination ofreliable technical information to promote safe and efficient use of gas and toencourage private sector industry to support it. The technical assistance forits establishment and initial operation will be obtained through a long-term(3 to 4 years) collaboration with a prominent gas technology institute iniNorth America, Western Europe or Japan. The execution of an agreement,satisfactory to the Bank, for such a collaboration, will be a condition forthe disbursemf!nt of the funds allocated under the Bank loan.

3.24 MIGAS will strengthen its expertise in (i) the coordination andevaluation of development plans in the sector; and (ii) the institution of aregulatory system (outlined in Annex 4.03) to ensure continued safeutilization of natural gas. For this purpose, four engineers and twofinancial analysts from MIGAS will be provided broad-based training atoverseas institutes in gas production, transportation and utilization; andthree staff members will be sent to North America and Western Europe for sixto eight weeks to study the regulatory procedures of prominent gas consumingcountries. The training program will be prepared by MIGAS with the assistanceof the consultants to be engaged for setting-up the Gas Technology DevelopmentUnit.

Studies

3.25 Under the project, MIGAS, with the assistance of PGN and its twinningpartner, will conduct studies into the feasibility of distributing andmarketing natural gas in Palembang (South Sumatra), Jambi (Central Sumatra),Batam island (Riau) and Balikpapan (East Kalimantan). These areas aredeveloping commercially and are located close to known reserves of naturalgas, with the exception of Batam island which lies on the route of thepipeline proposed for the transportation of Natuna gas to Singapore.

Project Costs

3.26 The total project cost, based on the scope and design in paras 3.15through 3.25, is estimated at US$108.3 million, of which US$91.1 million isexpected to be in foreign exchange as shown below (details of project costsestimates are given in Annex 5.02).

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Table 3

Local FE Total Local FE TotalA. Expansion of Natural Gas ---US$ million--- ---Rps billion---

Transmission & DistributionSystems for

Surabaya & its environsPipelines 8.2 52.4 60.6 14.35 91.70 106.05Regulator Stations 0.3 1.7 2.0 0.52 2.96 3.48

Meter Stations & Service Lines 0.7 5.1 5.8 1.23 8.93 10.16Total 9.2 59.2 68.4 16.10 103.60 119.70

MedanPipelines 2.6 3.1. 5.7 4.55 5.43 9.98Meter Stations & Service Lines 0.0 0.4 0.4 0.00 0.70 0.70

Total 2.6 3.5 6.1 4.55 6.13 10.68Base Cost (A) 11.8 62.7 74.5 20.65 109.73 130.38

B. Technical AssistancePGNTwinning Arrangement 0.0 5.0 5.0 0.00 8.75 8.75Staff Training 0.0 2.5 2.5 0.00 4.36 4.36Equip. (computers & software) 0.5 0.6 1.1 0.88 1.05 1.93

Total 0.5 8.1 8.6 0.88 14.16 15.04

LEMIGAS (Gas Tech. Devl. Unit)Consulcancies 0.0 2.0 2.0 0.00 3.50 3.50Staff Training 0.0 1.5 1.5 0.00 2.62 2.62Equipment 1.3 4.0 5.3 2.28 7.00 9.28

Total 1.3 7.5 8.8 2.28 13.12 15.40MIGAS

Staff Training 0.0 0.5 0.5 0.00 0.88 0.88Base Cost (B) 1.8 16.1 17.9 3.16 28.16 31.32

C. StudiesMarketing FeasibilityStudies for Palembang Jambi,Base Cost (C) 0.0 0.3 0.3 0.00 0.52 0.52

Total Base Cost (A+B+C) 13.6 79.1 92.7 23.81 138.41 162.22Physical Contingencies 2.2 4.0 6.2 3.85 7.00 10.85Price Contingencies 1.4 8.0 9.4 2.45 14.00 16.45

Total Project Cost 17.2a/ 91.1 208.3 30.11a/ 159.41 189.52

Capitalized interest During 2.5 8.0 10.5 4.38 14.00 18.38during ConstructionTotal Funding Required 19.7 99.1 118.8 34.49 173.41 207.90

a/ Includes US$11.0 million equivalent as duties anfd taxes.

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3.27 The cost estimates are based on September 89 price levels. As theproject has been designed in sufficient detail, the physical contingenciesfor FE cost have been estimated at 5Z of the base cost, however to providefor any unforeseen problems in civil works, the physical contingencies forlocal cost have been estimated at 10% of the base cost. Price contingenciesfor foreign costs have been estimated at 5.4% per annum for 1990 and 4.3%for 1991 and thereafter and for local costs at 72 for 1990 and 6% for 1991and thereafter.

Financing Plan

The project funds required, totalling $118.8 million equivalent,are expected to be financed as follows:

Table 4

Source Local Foreign Total---------US$ million---------- 2

Proposed Bank Loan - 86.0 86.0 73Bilateral Funds - 5.0 5.0 4PGN Internal Cash 9.7 - 9.7 8GOI 10.0 8.1 18.1 15

Total 19.7 99.1 118.8 100

3.28 The Bank loan will cover all foreign exchange costs of theproject, ixcept for interest during construction (IDC) and the cost ofPGN's twinning with an experienced gas utility. The Bank loan represents87% of the foreign exchange cost, 73X of total project funding required or80% of the total project funding, exclusive of duties and taxes. Remainingproject expenditures will be funded by bilateral assistance (4%), PGN'sinternal cash generation (8Z), and GOI (15Z). During negotiations,agreement was obtained from GOI that it will ensure that MIGAS/LEMIGAS andPGN are provided with the necessary funds to carry out the project.

3.29 Of the proposed Bank loan $10.0 million will be made available byGOI to MIGAS/LEMIGAS for the Gas Technology Development Unit, training andmarketing studies; the remaining $76.0 million will be onlent by GOI to PGNunder a Subsidiary Loan Agreement satisfactory to the Bank. The on-lendingrate will be 13% p.a., with GOI carrying the foreign exchange risk in linewith GOI policies towards public corporations, and PGN will repay the loanto GOI over fifteen years including five years of grace. GOI is alsoexpected to fund capitalized interest during the grace period, as it hasdone under the ongoing gas project. During negotiations, assurances wereobtained from GOI that $10.0 million of the proposed Bank loan will be madeavailable to MIGAS/LEMIGAS and that the Bank would be furnished with theaudited project accounts for the Gas Technology Development Unit and themarketing studies within nine months of the end of each fiscal year. Thesigning of a Subsidiary Loan Agreement between GOI and PGN, satisfactory tothe Bank, will be a condition of Loan effectiveness.

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Implementation

3.30 PGN will have the overall responsibility for the implementation ofthe Surabaya and Medan components of the project. It will be assisted bythe consultants (under the twinning arrangement) in the detailedengineering, procurement, and construction management of the supply systemsas well as in the marketing of gas, customer connect'on and follow onoperations along the same lines as for the on-going project. The projectplanning is already in progress, market and route surveys and basic designshave been completed. GOI will enable PGN to secure the necessary rights ofway/way leave for the pipelines to be built under the project, in a timelyfashion, at least six months prior to the estimated start of the relatedconstruction.

3.31 All construction works will be carried out by contractors. As theconstruction of transmission pipelines for Surabaya and Medan is on thecritical path in the implementation schedule, these works will becontracted on a turn-key basis, through internationsl competitive bidding(ICB), following the Bank guidelines, to facilitate early completion. Theconstruction of distribution pipelin' s, sc4ttered geographically and spreadover tinie, will be carried out by local contractors (as in the on-going GasDistribution Project) who possess the necessary skill, equipment andresources to undertake the expanded workload under the project. To providean independent check, an outside agency will be engaged for inspection ofquality and tests.

3.32 The transmission pipelines to Medan and Surabaya areas arescheduled to be commissioned by July 1992 and February 1993 respectively.The gas supplies to major consumers, the PLN stations near Medan and thepaper mill at Leces are expected to commence soon thereafter. Theconstruction of distribution pipeline networks in Surabaya and its environswill continue till March 1996. The implementation schedule is given inAnnex 5.01. The pipeline construction and customer connection is expectedto proceed as follows:

Table 5

Customers to be Connected inPipelines for Surabaya Medan

Fiscal Year Surabaya Medan Industrial Commercial Industrial Commercial-_____(Km)------ -No-

1992 100 24 30 - -

1993 129 - 50 - - -1994 72 - 70 50 - -1995 71 - 90 50 - -1996 59 - 135 50 - -

431 24 375 150 - _

3.33 LEMIGAS will be responsible for the establishment of the GasTechnology Development Unit with the technical assistance as discussed in para3.23. Its implementation schedule will be determined by the on-going planningstudy (para 1.18). The preparation of its implementation schedule,satisfactory to the Bank, will be a condition for the disbursement of fundsallocated under the project.

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Procurement

3.34 All major items of material, equipment and related services andconstruction contracts financed from the proceeds of the loan would be procuredthrough international competitive bidding (ICB) in accordance with the Bankguidelines except for items of small value to be used for the distributioncomponent (not exceeding US$50,000 each and US$3 million in total for PGN andUS$500,000 in total for LEMIGAS) which are available off-the-shelf, such aselectrical switch-gear, flex, low pressure pipes and valves, etc. Such smallvalue items will be procured through prudent shopping after receiving pricequotations from at least three eligible suppliers in accordance with proceduresacceptable to the Bank. For the purposes of evaluation and comparison of bidsfor the supply of goods under ICB, qualified domestic suppliers will be alloweda preference of 15% of the CIF price or the applicable import duty, whicheveris lower. In the evaluation of bids for construction contracts, local eligiblecontractors will be given a preference of 7.5Z. Bidding packages overUS$300,000 will be subject to the Bank's prior review of procurementdocumentatior. Thus the documents for the procurement covering over 952 of thelan amount will be subject to the Bank's prior review. This is not expectedto pose any major problems as the procurement documents have already beenstandardized under the current Gas Distribution Project and will be reviewedagain a- the outset of the proposed project to ensure efficient processing.

3.35 The procurement arrangements are summarized in the following table.The figures in the parentheses are the respective amounts to be financed fromthe proceeds of the Bank loan.

Table 6

Project Component ICB LCB Others N.A. a/ Total_______________US$ million…-----

1. Gas Supply SystemLine Pipes 41.5 0.5 b/ 6.1 48.1(Steel pipe,PE Pipe,valves & fittings) (41.5) (0.5) (-) (42.0)

Other Materials 6.8 1.8 b/ 3.2 11.8(Compressors, regulators, (6.8) (1.8) (-) (8.6)meters, SCADA, etc)

Construction 22.9 6.3 29.2(22.9) (-) (22.9)

2. Technical AssistanceEquipment for:

PGN 0.6 0.2 0.8(computer software) (0.6) (-) (0.6)

LEMIGAS 5.0 1.5 6.5(Gas Technology Develop. Unit) (5.0) (-) (5.0)

Consulting Services for:PGN 5.0 c/ 5.0

(-)LEMIGAS 2.0 d/ 2.0

(2.0) (2.0)

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Staff Training for:PGN 2.5 2.5

(2.5) (2.5)

LEMIGAS 1.5 1.5(1.5) (1.5)

MIGAS 0.5 0.5(0.5) (0.5)

3. Studies 0.4 dl 0.4(0.4) (0.4)

Total 76.8 6.3 14.2 11.0 108.3.76.8) () (9.2) (-) (86.0)

a/ Customs duties and taxes.b/ Prudent shopping.cl Financed by bilateral aid funds (para 3.22).d/ Following Bank guidelines for the use of consultants.

Disbursement

3.36 The Bank loan will be disbursed against: (a) 100% of the foreignexchange cost of imported equipment, materials and related services; (b)100X of the cost of local equipment and materials (ex-factory); (c) 65% ofthe cost of other items procured locally (off-the shelf); (d) 1002 offoreign expenditures for training; and (e) 1002 of expenditures forconsultants services.

3.37 The implementation period for the project is estimated at sixyears and the disbursement schedule (Annex 5.03) is largely in line withthe Bank's standard disbursement profile. Projected disbursements arebased on loan effectiveness and the signing of major pipeline contracts inFYs92 and 93. Therefore, substantial disbursements are expected for theearly years of the project.

3.38 To facilitate disbursement, a Special Account will be opened withan authorized allocation of US$5.0 million equivalent, the estimatedaverage loan disbursement for a four-month period. The account will beopened in US dollars in a bank acceptable to the Bank and will have sub-accounts for PGN, MIGAS and LEMIGAS respectively. Applications forreplenishment of the Special account will be submitted quarterly orwhenever the Special Account is drawn down to 502 of its initial deposit,whichever comes first. Disbursements will be made against priced corntractsfor the goods, services and works procured under the Bank loan, and SOEs--if any. Interim certification of works completed and costed at unitrates in the contracts will be done by PGN/MIGAS/LEMIGAS. DisburseLuentsfor training overseas will be made against the actual costs of travel,subsistence and tuition or training fees. Disbursements against statementsof expenditure will be made for the training component and for goods orservices costing less than US$300,000. Documents supporting theexpenditure statements will be retained by PGN/MIGAS/LEMIGAS and the DGbudget office, as appropriate, and made available for review by Banksupervision missions. During negotiations, instructions for the operationsof the Special Account were provided to PGNIMIGAS/LEMIGAS.

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Environment

3.39 As the project was appraised (in May 1989) before theenvironmental evaluation directive (No. 4.00-A) was issued, it was notsubjective to environmental analysis. Its implementation will however notpose any significant hazard to the environment. Design configuration andpipeline system layout has been established taking into account safetynorms and standard design codes. Substantial segments of the pipelinenetwork will be buried using existing easement strips where there areminimum obstacles to the laying of pipes. In heavily congested areas,pipeline routing has been carefully planned to ensure that service lineswill be situated at safe distances from human traffic. For waterloggedareas or where soil conditions are heavily corrosive, upgraded materials Uand construction design have been provided and are reflected in the highercost of pipelines for these segments. Aside from the limits posed byoperating pressure and mechanical loads on the pipes, selection ofpipelines materials are also based on proximity of property and risk ofinterference damage.

3.40 The project will also alleviate urban pollution particularlywithin the industrial zones with the replacement of liquid hydrocarbonfuels by natural gas. The combustion products of gas are less pollutingthan those for petroleum products. M-reover, replacement of old andinefficient gas pipelines would reduce the hazards earlier posed by gasleakage in the old system.

Reporting Requirements

3.41 During negotiations, assurances were obtained that PGN willcollect relevant data through the monthly operating reports, combine itwith project data and use it for compiling quarterly progress reports onthe project. The progress reports should be made available to the Bankwithin 45 days of the end of the reporting period. An outline of thequarterly progress report is given in Annex 5.04.

3.42 The progress reporting requirement for the Gas TechnologyDevelopment Unit will be prepared by LFMIGAS after the completion of theplanning study and will require the Bank's approval prior to thecommencement of disbursement of funds allocated under the Bank loan for theGas Technology Development Unit.

IV. FINANCIAL ASPECTS

PGN's Margin on Gas Sales

4.1 In recent years, PGN gas sales price varied from about Rp 4,900 toRp 5,300/MMBTU depending on the volume the consumer contracts for. Acomparison between this gas price and the current domestic prices of liquidfuels competing with gas is given below:

;

r

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Table 7

Current Domestic Price(Rp/liter) Rp/MMBTU

Fuel Oil 200 5,200Diesel (ADO) 200 5,600Kerosene 165 4,700LPG (per Kg) 591 13,300Natural gab - 4,900-5,300

4.2 The average natural gas price of about Rp 5,000 thus represented adiscount of 4% to 11 from fuel oil and diesel, the principal fuelscompeting with it. According to PGN's experience under the ongoing gasdistribution project, this discount was needed to provide a sufficientfinancial incentive for potential customers to convert from liquid fuels tonatural gas. Once the customers have made the necessary investment inconversion equipment, installed gas burning boilers etc., they experiencefirsthand the advantages of natural gas over liquid fuels: lowertransportation and storage cost, improved security of supply, improvedcombustion efficiency, lower maintenance costs and increased cleanliness.In the long run, this permits PGN slowly to increase its gas prices foralready connected users up to, or even slightly exceeding, the prices offuel oil and diesel without losing customers.

4.3 Before FY87, when the Rupiah (Rp) was devalued by 452 against slheUS dollar, the gas price in PGN's supply contract with PERTAMINA wasUS$2.70JMMBTU (Rp 3,000/MMBTU). A new price of Rp 3,500 was subsequentlyagreed between PERTAMINA and PGN. At the same time, due to weakening wo-ldmarket prices, the domestic prices for industrial diesel and fuel oil werereduced by 9% compared with FY86 ievels,3/ thus reducing the price PGNcould charge potential industrial and commercial customers and still inducethem to shift from competing fuels to gas. These price movementseffectively reduced PGN's margins on gas sales by about 252, and in FY89PGN operations therefore yielded only a 1.42 return on revalued net fixedassets in operation against the 10% return covenanted under the ongoing GasDistribution Project (which improved to 2.6% in FY90). Without thisunexpected reduction in PGN's gas sales margin, the rate of return covenantwould have been met. The economic argument for increased domestic use ofgas is unassailable and the support for expanded PGN gas distribution is inline with the Bank's sector strategy. T'o provide PGN with the necessaryflexibility to expand gas sales rapidly in a competitive market, the Banktherefore agreed to PGN's request to postpone until FY95 the application ofthe 102 rate of return covenant under the ongoing project (Ln. 2690-IND).A monitorable program to ensure continued improvement of PGN's efficiency(e.g., closure of obsolete gas manufacturing plants, reduction of gaslosses and higher increases in sales than in operating costs) and financialperformance (e.g. interim rate of return targets) was reviewed and agreedduring the negotiations (para 4.18 and Annex 6.05).

3/ With oil at about US$18/bbl the domestic price of fuel oil is now about1OZ, above its international parity price and the domestic price ofindustrial diesel about 30% below.

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PGN's Past Financial Performance

4.4 At appraisal of the ongoing Gas Distribution Project in FY86, PGNwas an inefficient, small scale distributor of natural and manufacturedgas; its iivestments were financed by Government and it operated at a loss.Under the Gas Distribution project, PGN's rate of return on revalued netfixed assets increased from a negative 3.72 in FY86 to a positive 2.62 inFY90. PGN was able to achieve this result mainly by improving itsefficiency: the volume of gas sold increased by over 200Z between FY86 andFY90 and gas losses were reduced from 30Z to 6Z dur:.ng the same period.With the assistance of the twinning agency (British Gas) provided under theongoing project, PGN successfully implemented a flexible gas marketingstrategy that pernitted PGN to expand sales quickly at competitive prices,and procedures for maintenance and planning were improved. Theseefficiency improvements were necessary to protect PGN's financial viabilityafter the FY87 reduction in PGN's margin on gas sales.

4.5 PGN's income statements for FYs86-89 (Annex 6.02) are summarizedbelow:

Table 8

FY ending March 31: 1986 198/ 1988 1989 a/ 1990 b/--------------Rp billion---------

Gas Sales 18.9 26.0 34.2 44.8 61.3Cost of Gas Sold 13.6 17.4 25.1 33.5 38.8Other Expenses (net) 5.2 7.9 9.2 9.6 19.2Operating Income 0.1 0.7 0 1.6 3.4Non-operating Tilcome 7.9 (0.7) 0.6 1.0 0.9Profit after Tax 5.6 (0.1) 0.6 2.2 3.4

Ratios (Z):Operating Income/Sales 1 3 0 3.6 5.6ROR on Net Fixed Assetsin Operation:

Valued at Cost (8.6) 1.7 0 2.4 4.6On Revalued Basis (3.7) 1.0 0 1.4 2.6

a/ Unauditedb/ Provisional

4.6 Over the last five years, PGN's gas sales have increased by over302 p.a. while the percentage of gas lost has been reduced from dbout 30?to about 6Z. However, higher cost of gas and operating expenses,especially wages, consumed PGN's revenue increases causing operationsbarely to break even up to FY88. The impact of efficiency improvingmeasures, initiated under the ongoing project (pars 4.4), was reflectedonly in FY89 and FY90, when PGN's operating income increased from zero toRp 3.4 billion ($1.9 million) and PGN's rate of return on revalued netfixed assets in operation from zero to about 2.6? despite unusually largesalary increases in FY90.

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4.7 In the past, PGN's investments were funded by th: GovernmentDevelopment Fund (DIP) and PGN was able to accumulate some surplus fundsfrom its own cash generation; those funds were i4ivested in time depositsproviding a substantial non-operating income that was not taxed. As fromFY92, GOI will not provide PGN with new DIP funds and PCN will thereforehave to rely on its own cash generation and other external sources.

4.8 As from FY86, PGN pays 35Z in tax on its net income (excludinginterest on time deposits) and, as from FY87, PGN is not allowed to carryforward any tax losses to subsequent years. PGN also pays 55Z of after taxincome to GOI as a contributioni (DPS) instead of dividends. This leavesPGN with less than 301 of income before tax to be retained within thecompany.

Present Financial Position

4.9 PGN's unaudited balance sheet as of March 31, 1990 (Annex 6.03) issummarized as follows:

Table 9

Rp. Billion z

Net Fixed Assets in Operation 56.2 47Work in Progress 35.0 29Total Net Fixed Assets 91.2 76

Current Assets 20.5 17Less: Current Liab. (11.3) (9)Other Assets, net a/ 20.1 16Total Assets 120.5 100

Financed by:Equity 79.5 66Social Fund 1.2 1Long-term Debt 39.8 33

Total Liabilities 120.5 100

Current Ratio (times) 1.8Debt/Equity Ratio 33/67

a/ including time deposits

4.10 PGN's past investments have been financed largely by Governmentequity contributions from DIP funds and PGN has therefore, despite poorfinancial results from its operations, a strong financial position with acurrent ratio of 1.8, a debt equity ratio of 33/67 and over Rp 10.0 billionin time deposits. Nearly all long-term debt is to the Bank for the ongoingproject.

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4.11 PGN's plant and equipment were revalued in FY80 as required of allpublic corporations by the Ministry of Finance. The revaluation wasrecorded in PGN's books and the method was accepted by the Bank. In FY86,a revaluation of land owned by PGN as of FY85 was also recorded in PGN'sbooks, resulting in a Rp 18.3 billion increase, or about a doubling of thevalue of PGN's net fixed assets. PGN's old gas distribution networks,which are obsolete and nearly fully depreciated, are being replaced underthe ongoing and proposed projects. The average age of PGN1's fixed assetsis therefore re'latively low; in FY89 about 50X had been in operation forless than five years and in FY97 this percentage will be about 75Z. InFY89, the currency fluctuations and price increases since the FY80 and FY86revaluations were estimated to have increased the replacement cost of PGN4'sassets by 55Z and this percentage was used to revalue PGN's FY89 fixedassets for ROR calculations as agreed under the ongoing project. TheIndonesian accounting practices do not provide for regular revaluation offixed assets and the revaluation exercise was therefore done on amemorandum basis outside PGN's books; these arrangements are satisfactory.

4.12 PGN's FY90 fixed assets in operation may be overstated due totransfer of capital works to assets in operation before they were actuallyput into operation and capitalization of interest that should have beencharged against income. The distortion of PGN's asset values is notmaterial, steps are however being taken for future correction (para 2.2).

4.13 Under the ongoing project, it was agreed that the value of land(for gas manufacturing properties that will not be needed for PGN's gasoperations when manufactured gas has been replaced by natural gas or LPG)would not be included in the rate base for ROR calculations. Thisagreement will continue under the proposed project. For fixed assets otherthan such land, assurances were obtained from PGN during loan negotiationsthat PGN will revalue its fixed asse.s in operations annually according tomethods acceptable to the Bank and that this revaluation will be submittedto the Bank, together with PGN's unaudited financial statements (para2.20), within six months of the end of each financial year.

Financial Projections for PGN

4.14 PGN's budget for FY91 is based on a margin on gas sales of aboutRp 2,000/MMBTU between PGN's gas cost of Rp 3,500/MMBTU and an averagesales price of Rp 5,500/MMBTU would be sufficierLt to produce adequatereturns for an efficiently operated gas company of reasonable size. Underthe proposed Gas Utilization Project, PGN would achieve both the necessaryeconomies of scale and efficiency: the volume of gas sold would increasethree times from FY91 to FY96. Gas losses would be reduced from 6Z to 2X;and obsolete gas manufacturing plants closed and replaced by either naturalgas or LPG distribution. A program to achieve these objectives was agreedduring negotiations and will be closely monitored under the proposedproject (Annex 6.05). The income projections for PGN (Annex 6.02) indicatethat a 1O return will be achieved in FY95, reaching 17? in FY97, when allfacilities under the proposed project would be fully utilized. PGN wouldprovide all local project costs (except for GOI funded capitalizedinterest) out of its internally generated funds, after payment of alloperating costs, debt service, income tax, DPS contributions to Government

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and pensions; this would be satisfactory considering the rrpid pace ofexpansion.

4.15 PGN's projected financial statements for FYs9l-97 with notes andassumptions are given in Annexes 6.01 through 6.04. Some highlights arepresented below:

Table 10

FY ending March 31: 1991 1992 1993 1994 1996 1998 1997

Gas Sales: (Million M3) 360 540 690 850 1140 1320 1880(Rp Billion) 74.8 109.8 146.8 177.4 234.3 270.0 340.6

Operating Income/Sales (%) 10.8 16.8 17.7 16.0 20.2 21.7 23.8Net Profit/Sales (X) 8.6 8.4 8.8 8.6 9.5 10.6 12.2Rate of Return a/ on:

Book Value Bisis (%) 8.4 13.1 12.5 9.2 14.5 18.2 24.9Revalued Basis (%) 6.0 8.6 9.6 7.1 11.0 12.8 16.6Current Ratio (times) 2.3 2.3 2.8 3.1 3.2 3.3 3.4

Debt/Equity Ratio 42/68 68/42 66/35 86/36 65/35 64/36 59/41

Debt/Service Ratio(times)b/ n.a. 1.7 2.0 2.6 2.3 3.1 1.9

/ After income tax (35%) but before interest and DPS contributions, whichhave been treated as appropriation of after tax profits as indicated bythe Ministry of Finance.

b/ Defined as: internal cash generation divided by debt service (includingInterest charged to income). FY91 ratio is abnormally high as mostinterest will be capitalized and amortization of Ln 2690-IND and an EXIM Bank(Japan) loan start only in FY92.

4.16 These projections are based on a gas margin of about Rp 2,000 andgas sales projections according to PGN's plans, which have been worked outwith the assistance of the twinning agency (British Gas). As under theongoing project, PGN is expected to manage a quadrupling of its gas saleswith an increase of only about 20% in its staff; the new transportation anddistribution network will require less maintenance than the old ones, gasmanufacturing plants will be closed, gas losses reduced from the current 62to 22, staff will be trained, and offices will be equipped with moderntechnology, all to further improve PGN's efficiency. This efficiencyimprovement program is ambitious, but should be ach.evable judging from PGN'sperformance since FY86 under the ongoing project. During negotiations, theimplementation of an efficiency improvement program for PGN (Annex 6.05) wasdiscussed and agreed, including monitorable targets for: closure of gasmanufacturing plants; natural gas sales; gas losses; number of staff; and,training.

4.17 PGN's debt/equity ratio will increase during the project period to amaximum of 65/35 in FYs93 to 95 due to the new loans required to implementthe proposed project; as from FY97, this ratio will decline rapidly. A 65/35debt/equity ratio is acceptable, as gas distribution is a relatively stableand predictable business. In FYs9O and 91, PGN will receive part of an EXIM

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Bank (Japan) loan as government equity. However, GOI will not provide PGNwith new DIP funds for the project; and therefore PGN will have to fund localproject costs from internal cash generation as from FY92.

4.18 Under the ongoing project, a lOX ROR on net fixed assets inoperation was agreed for PGN as from FY89. Due to the FY87 squeeze on itsgas sales margins (para 4.3), PGN was unable to achieve this rate of returndespite a satisfactory performance in gas sales and efficiency improvements.PGN would first have to implement the efficiency improvement program (para4.16) before a ROR of 1OZ can be achieved. In FY95, at the end of theproposed project when most new gas users have been connected and producerevenues, financial projections indicate that PGN will produce a ROR over102, reaching 17Z in FY97. During negotiations, interim ROR targets wereagreed and assurances were obtained that PGN will take all necessarymeasures, including the implementation of an efficiency improvement program,to produce a rate of return on revalued net fixed assets in operation of notless than 42 in FY91, 52 in FYs92-93, 8Z in FY94 and 10Z thereafter. If GOIincreases the retail prices of fuels competing with gas, thus permitting PGNto increase its margins on gas sales, the date for application of the 1O0rate of return covenant will be advanced.

4.19 PGN's funds flow statements for FYs86-97 are given in Annex 6.04.The cumulative funds flows for the FYs92-96 project period are summarizedbelow:

Table 11

FY ending March 31: 1992 - 1996(Rp billion) (US$ million) (2)

Internal Cash Generation 285.0 162.8 126Less: Debt Service 111.5 63.8 49

Tax & DPS Payments 95.8 54.7 43Increased Working Cap. a/ 18.8 10.7 8Change in Other Assets, Net 39.4 22.5 17

Funds Used for Capital Works 19.5 11.1 9Proposed Bank Loan b/ 133.0 76.0 59IBRD Loan 2690-IND 8.8 5.0 4Other Loans c/ 64.0 36.6 28Total sources 225.3 128.7 100

Proposed Project d/ 195.3 111.6 87Other Capital Works 30.0 17.1 13Total Requirements 225.3 128.7 100

Debt Service Ratio (Times) 2.6 2.6 -

a/ Mainly accounts receivable and inventories; excludes current maturities,which are included under long-term debt.

b/ Excluding $10.0 million in FE for the gas technology center and studiesfor LEMIGAS/MIGAS.

c/ Includes capitalized interest during construction, which will be financedby GOI under the GOI/PGN on-lending agreements, $5.0 million for continuedtwinning to be financed by bilateral assistance, and GOI funding of ongoingworks.

d/ Project cost includes capitalized interest during construction, but excludesthe LEMIGAS/MIGAS component ($10.5 million), expenditures incurred beforeFY92 and twinning ($5.0 million) and training ($1.5 million), which areexpected to be charged against current income.

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4.20 In the past, GOI has provided PGN with equity contributions of DIPfunds for its investment program. As from FY92, however, GOI will notprovide new DIP funds to PGN and the financing plan for the proposed projecthas been made on this basis. Out of total capital investments, includingcapitalized interest during construction during FYs92-96, PGN is expected tocontribute US$11.1 million (or 92) from internally generated funds (thiswould cover all local project costs except for GOI funded capitalizedinterest), the proposed Bank loan US$76.0 million (or 592), Loan 2690-INDUS$5.0 million (or 42), bilateral assistance US$5.0 million (or 42), and GOIthe remainder (242, mainly for capitalized interest and ongoing works).During negotiations, assurances were obtained from PGN that by January 1 ofeach calendar year, it will prepare an annual investment program and submitit to the Bank for comment.

4.21 In addition to the capital expenditures for the proposed and ongoingprojects, PGN will in FYs91-96 repay an EXIM Bank loan of about US$13.5million equivalent, amortize the Bank Loan 2690-IND with about US$4.5 millionp.a. as from FY92 and pay taxes and DPS dividends to GOI totalling aboutUS$54.7 million equivalent. Even so, PGN is expected to generate $22.5million equivalent in excess of project needs; those funds will be investedto cover eventual social fund obligations. Now that PGN's operations arefinancially viable and earlier qualifications have been removed from itsaudit reports and its FY89 report is expected to be without qualifications,PGN has the option to issue obligations in its own name or make othercommercial funding arrangements. As from FY96, when the project will becompleted, PGN's financial performance and cash generation will improvesubstantially and PGN would be able to repay project financing at anaccelerated rate. During negotiations, assurances were obtained from GOIthat it will ensure that PGN will be provided with sufficient funds to carryout the project.

Risks in Financial Proiections

4.22 As in 1986, there is a possibility that PGN's margin on gas salescould be squeezed again by adverse movements in the cost of gas and thedomestic prices of competing liquid fuels. However, this risk is consideredminor, as GOI is considering an increase in domestic liquid fuel prices andthe conservative assumption (based on the Bank's commodity forecast for crudeoil) that prices of petroleum products will largely remain at today's levelsin real terms until the end of the century has been used for projectionpurposes. Project implementation may be delayed, which would lead to slowerthan projected growth of PGN's gas sales. This risk will be minimized byextensive use of turn-key contracting. The risk of delayed gas supplies willbe minimized by requiring the signing of supply contracts as a condition forloan effectiveness. Finally, efficiency improvements, e.g., furtherreduction of gas losses and closure of old gas manufacturing plants, may takelonger than planned. However, projections are based on what PGN has beenable to achieve under the ongoing project and the twinning agency (BritishGas or another experienced gas utility) will remain with PGN under theproposed project to assist as necessary. If, for unforeseen reasons, PGN'ssales margins were further reduced by about 20Z and project implementationwere delayed up to two years, PGN would still be able to raise its rate ofreturn to 102 by FY97.

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Project's Financial Rate of Return

4.23 The calculations of incremental financial rate of return (IRR) andprojected income statements for the main project areas (Surabaya and Medan)are given in Annex 6.08. Assuming a carrying charge of $0.23/MCF in Medanfor gas transported by PGN to PERTAMINA customers, a constant margin on PGNgas sales at current $1.14!MCF and including all taxes and duties in theproject capital and operating cost, the IRR for Surabaya would be 162 and forMedan 142. These IRRs are satisfactory and above PGN's cost of capital.

4.24 A sensitivity analysis of the IRRs was carried out with thefollowing results:

Table 12IRR Z

Surabaya Medan(a) Capital Expenditures + 102 15 12(b) Operating Cost + 10X 16 14(c) Revenues - 102 14 ;0(d) Combination of (a), (b), (c) 13 8

This analysis indicates that the IRR is sensitive mostly to changes inproject cost and revenues, but even in the case of combined adverse events,the IRR would be acceptable. A delay in project execution is likely to delaycosts and benefits at roughly the same rate, so the impact on the IRR wouldnot be substantial, even if the present value of the project would decline;the extensive use of turnkey contracts for the project should reduce the riskof delayed project implementation. The risks for lower IRRs due toinsufficient or late gas supplies and inadequate carrying charges and/or gasmargins will be minimized by requiring PGN and PERTAMINA to agree on thesevital project parameters before loan effectiveness (para 3.8).

V. PROJECT JUSTIFICATION AND RISKS

5.1 The primary justification for the proposed project are the fuel costsavings and potential foreign exchange earnings to be generated bysubstituting non-tradeable surplus gas for exportable petroleum fuels. Theabundance of gas reserves in East Java and North Sumatra which are accessibleto the major industrial centers at Surabaya and Medan has set a stageconducive to expanding the domestic energy market for natural gas. With theincremental cost of gas supply estimated to be lower than alternative energysources, the promotion of gas use in the power and manufacturing sectors hasbecome a cornerstone of GOI's energy diversification program. It is thusopportune that the gas sector in East Java and North Sumatra offers extremelyfavorable prospects for accelerating the diversification program and this hasprompted the GOI to accord high priority to the development of the proposedproject.

5.2 The project will serve medium-sized industries engaged in variousmanufacturing activities with significant demand expected from the steel andfabricated metals sector, glass and ceramic manufacturing, paper productionand chemical industries (Annex 2.01). The bulk of fuels to be replaced bygas among these industries consist of high value middle distillates. At the

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same time, the project will make gas available to PLN's power stations atMedan, and thus ensure stable and more economical fuel supply to meet theregion's growing electricity requirements.

5.3 By integrating the gas utilization programs of the industrial andpower sectors, and through the upgrading of the managerial and technicalknowhow in the gas industry, the project will promote optimization ofinvestments and greater efficiency in operation of the gas subsector. Inaddition, the project will lead to a reduction of environmental pollutionarising from the use of gas which is a cleaner fuel than the fossil and woodfuels it would supplant.

Economic Evaluation of the Project

5.4 In assessing the economic viability of the proposed Project, anevaluation of the costs and benefits to the country with and without theProject was undertaken and the associated economic internal rate of returnestimated. Essentially, this involved quantifying the value of liquid fuelsto be replaced by natural gas among potential users in the Surabaya and Medanservice areas. The net savings to the country resulting principally fromthis shift to gas use by r-GN's potential customers is estimated to reachUS$97 million annually, of which US$9 million is due to PGN's operations inMedan and US$88 million in Surabaya.

5.5 Project Economic Benefits. Benefits consist of the gas sales toPGN's industrial and commercial customers and supply deliveries to PLNthermal power stations. The projected gas sales attributable to the projectare as follows:

Table 13

Ey ending: 1993 1994 1995 1996 1997 1998 1999 2000----------------------MCFD-------------------

SurabayaInd./commercial 0 5 12 23 36 50 55 60Paper (;eces) 0 5 20 20 20 20 20 20Sub-total 0 10 32 43 56 70 75 800HedanIndustries 7 7 7 7 7 7 7 7PLN 18 18 18 18 18 18 18 18Sub-total 25 25 25 25 25 25 25 25

Grand Total 25 35 57 68 81 95 100 105

5.6 The benefits due to PGN's gas sales are valued in terms of theinternational market value of the tradeable petroleum fuels to be replaced.A survey of potential PGN customers in Surabaya indicates that thestructure of industrial fuel demand is such that approximately 43Z of gasdeliveries will substitute for industrial diesel oil (IDO), 202 for highspeed diesel (HSD), 182 for fuel oil and residual, 10X for kerosene and thebalance will replace LPG and wood fuel. A similar survey conducted amongindustries in Medan yielded an energy demand profile replaceable by natural

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gas consisting of 582 IDO, 20X HSD, 122 kerosene, 92 LPG and 1% fuel oil.In the case of the paper mill at Leces in Surabaya, 602 of gas use willsubstitute for HSD and 402 for fuel oil. But while the gas supply to PLN'spower plants will displace fuel oil, benefits attributable to the projectwere assessed only in terms of pipeline carrying charges to PERTAMINAassumed at US$0.23 per MCF in Medan. (For purposes of this analysis, PLN'sinvestments and operating cost savings associated with the power plantconversion and construction were excluded.)

5.7 The value of petroleum products to be replaced by gas was arrivedat assuming an average price of US$18 per barrel of Indonesian crude andapplying average price of petroleum products on the Singapore spot marketduring the last three years (Annex 7.03). Their equivalent gas values areas follows:

Table 14Equivalent

International Price Value of Gas(US $/Kl) (US $/MCF)

Kerosene 164 4.7Automotive Diesel 166 4.6Industrial Diesel 154 4.2Fuel Oil 112 2.9LPG ($Iton) 198 4.4

Applying the above values to the structure of liquid fuel demand to bedisplaced by gas, the estimated equivalent economic value of gas sales toPGN's industrial customers is US$4.1 per MCF in Surabaya and US$4.3 per MCFin Medan. The value of gas supply to the paper factory at Leces isequivalent to US$4.0 per MCF.

5.8 Since natural gas lends itself more readily to combustion than deliquid fuels, the resulting increased thermal efficiency is estimated toyield 52 to 10% more savings to industrial users in terms of fuel value,depending on the industry and type of burner used. For purposes of theanalysis, a 5% increase in benefits to medium-sized industries is imputed.Moreover, gas utilization affords lower operating costs to industries dueto reduced fuel handling and storage expense, as well as reduced risk ofpollution compared to the use of fuel oil and diesel. These added benefitswere not, however, quantified.

5.9 The present heavy reliance of industries on diesel compared tofuel oil is partly attributable to the absence of any domestic pricedifferential between the two products. The current price of Rp 200 perliter approximates the international price of fuel oil but is 25% to 33%below that for diesel products. If domestic diesel prices were realigredwith international prices, it is likely that many of the industries wouldopt to use cheaper fuel oil without having to disrupt their productionprocess. Still, a limited number may elect to continue using diesel andpass on the added costs to the consumers, depending on their nature of

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operations and produce mix. In any case, it is technically possible forall the industries concarned to shift to fuel oil. Accordingly, in theabsence of the natural gas option, the least cost scenario would be one inwhich fuel oil use would predominate among the industries in Surabaya andMedan. Against this scenario, the incremental benefits derived from theproposed project are reduced by 40?. To the extent that it may take sometime for GOI to correct existing domestic price distortions among petroleumproducts, the proposed project will mitigate the effects of thesedistortions by encouraging industries to accelerate their shift to a morecost effective energy source, in this case, natural gas.

5.10 Project Cost. The major cost components considered were:

(a) the capital cost of the Project excluding taxes and duties,with the cost of local materials subjected to a standardconversion factor (SCF) of 0.8;

(b) investments to be made by the new industrial and commercialcustomers for conversion of their equipment, assumed at US$10million for Surabaya; and

(c) operating expenses associated with gas distribution estimatedto be equivalent to 2.52 of the purchase cost of gas supply.

5.11 Natural gas supplies in East Java and North Sumatra which willfeed into PGN's d...tribution systems in Surabaya and Medan are consideredto be surplus to Indonesia's LNG export requirements and are thus non-tradeable. Accordingly, the cost of gas supply to the project is taken atits long run marginal cost plus depletion charge estimated on the high sideat US$1.5L per MCF. At this level, ample provision for depletion premiumhas been made not having accounted for the very recent large gasdiscoveries in Maduras Strait offshore East Surabaya which may result innegligible depletion charges.

5.12 Economic Rate of Return. Based on the aforementioned costs andbenefits, the Project is expected to yield an overall economic internalrate of return of 592. The project component in Medan is estimated toresult in a return of 154Z, while that in Surabaya is expected to yield areturn of 51Z. The high rates of return derived reflect the high value ofpetroleum products to be displaced as well as the relatively lowinvestments required for the transmission and distribution of gas to theestablished industrial centers at Medan ed Surabaya, further complementedby the low marginal cost of gas production in the region. To the extentthat the calculations exclude the net benefits attributable to PLN'sconversion of its power stations into gas-fed units, the rates of returnare underestimated. Even if PLN stations were not supplied through PGN'sproposed distribution system, the project's rate of return would stillexceed 50Z.

5.13 Relative to the least cost alternative scenario of correctingdomestic price signals for diesel such that the fuel structure to bereplaced by natural gas would be predominantly fuel oil, the derivedeconomic rate of return for the over-all project is 381. The rate derived

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for the Medan component is 882 and that for Surabya, 33Z. (Results ofthese ca.culations are given in Annex 7.04.)

.,

5.14 Sensitivity analyses indicate that the project remains viable evenunder adverse variations in market demand, relative value of substitutefuels, project costs and carrying charges. The results of the sensitivitytests are as follow:

Thble 15: Economic Rate of Return (Z)

Medan Surabay Total Project

Base Case 154 51 59Market Demand

Down 10 2 139 47 54Down 25 Z 116 42 44

Value of ,ompeting FuelsDown 10 Z 132 45 52Down 25 2 103 36 41

Project CostsUp 10 l 140 48 55Up 25 Z 124 44 51

Carrying chargeDown 10 2 152 51 57Down 25 Z 148 51 58

Project Risks

5.15 Among the major determinants of the project'b viability are a) thetimely availability of gas; b) build-up in gas sales; c) stable values ofpetroleum fuel to be replaced; and d) shortfalls in institutionalcapabilities to implement the project.

5.16 The supply of gas to Surabaya is expected to commence by June 1992at the latest based on the expectation that ARCO's proposed Kangean-Gresikpipeline would be completed within thirty months from the signing of thegas supply agreement between PERTAMINA and PLN. The latter is scheduled byend of 1989. On the other hand, gas supply in Medan from the JAPEX fieldsoffshore Brandan is expected to be provided by December 1991. A delay inthe aforementioned arrangements will affect the project's operationalschedule and reduce the Project's EIRR and present value of benefits; e.g.,a one-year delay in operation will result in the following:

Medan Surabaya Total ProjectEconomic IRR:Base Case 154Z 51% 59%One-year delay 832 40% 452Net Present Value at: 10% 12% 10 12% 10o 121(in million US $)Base Case 64 54 367 295 430 349One-year delay 55 46 316 249 371 295

To minimize the risk of delays in gas supply arrangements on PGN's project,close coordination with PERTAMINA and the gas producers is being undertakenby PGN. Moreover, the high priority given by GOI on the early

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commissioning of PLN's gas-fired power stations at Gresik and Medan isexpected to result in the timely conclusion of the gas supply contracts.

5.17 A second determinant of the project's success is the build-up ofdemand among the target industries. There is no foreseeable risk of aslowdown in this demand since based on the survey of existing industries,the demand to be met by the project is considerably lower than thepotential loads in the business districts of Surabaya and Medan. Further,based on PGN's successful track record in expanding gas sales under theBank-financed Gas Distribution Project, its marketing, pricing andtechnical service programs are deem3d responsive to customer requirementsprovided the competitive price of gas is sustained. In this connection,any reduction in PGN's sales margins would affect the financial performanceof PGN (para 4.22) but not the project's economic viability. Prospects forgreater gas demand become even more favorable should GOI, in the context ofthe on-going energy price review, decide to realign domestic prices ofdiesel (which account for the bulk of petroleum fuel to be replaced by gas)with the price it could fetch in the international market. The resultinggreater flexibility in gas pricing could significantly accelerate marketdemand for gas. Nevertheless, assuming actual sales were to fluctuatebelow the projected levels, the project can withstand a 502 reduction indemand and still be able to generate an acceptable return of 35? due to thehigh value of fuels being replaced by gas.

5.18 The risk of a decline in the international prices of petroleumproducts is considered minor in view of current Bank forecas's suggestinggradual increases of 22 per annum in international prices (in real terms'for crude oil between now and year 2000. Nevertheless, sensitivity testsindicate that, should there be downward movements in the internationalprices of petroleum products, say to US$11/barrel of crude, the prDjectwould still yield an acceptable rate of return of 28Z. Theoreticall7 sucha decline in the value of oil would correspondingly be reflected in adecrease in the depletion value of natural gas leading to a reduction inthe cost of gas supply to the project. Adverse impact on the project'seconomic viability would thus be minimized.

5.19 The risk of shortfalls in the institutional capability of PGN toimplement the Surabaya and Medan components of the project is minimizedthrough the proposed technical assistance (twinning) arrangement, whichwill be a condition of loan effectiveness. Similar risk in theestablishment of a Gas Technology Development Unit will be covered by thetechnical collaboration of LEMIGAS with a prominent gas technologyinstitute in Western Europe or North America, on terms satisfactory to theBank, and which will be a condition of disbursement of funds allocated forthe Gas Technology Development Unit under the Bank loan.

Fiscal Impact of PGN's Operations

5.20 Under the on-going and proposed Bank-financed projects, PGN'soperations will expind to a level which will allow the company to beginreaping the benefits of efficiencies and economies of scale. Amanifestation 3f these gains would be the reduced reliance of PGN on GOIbudgetary support and an increasing capability on PGN's part to contributeto the national treasury and thus support other development priorities ofGOI outside of the gas utility sector (Annex 7.05).

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5.21 During the period 1990 to 1997, PGN's operations are expected toresult in a total fund transfer to GOI of about Rp 305 billion consistingof debt service remittances (42Z), contributions to the DPS fund (25%),income tax payments (24Z) and customs duties and taxes associated withconstruction work under both the on-going and proposed Bank-financedprojects (9Z). On the other hand, GOI fund releases for PGN will totalnearly Rp 119 billion during the same period, assuming the foreign exchangerate remains stable at Rp 1,750 to US$l. The bulk (76Z) of these GOIoutlays constitutes debt service payments by the GOI as borrower of foreignloans relent to PGN. The balance represents GOI's final DIP equitycontribution of Rp 28 billion programmed for fiscal years 1990 and 1991.Thereafter. GOI outlays for PGN would be restricted to debt servicepayments. The resulting net fund transfer between PGN and GOI amounts toRp 185 billion in favor of the national treasury. However, should there bea devaluation of the Rupiah such that there is effectively no differentialbetween debt service levels of PGN and GOI, the net funds flow from PGN toGOI would be around Rp 147 billion.

Benefits from Institution Building

5.22 A salient aspect of the proposed project concerns thestrengthening of expertise within the gas subsector in the areas of long-term planning, growth management, formulation of cost effective standardsand appropriate codes of practices, and establishment of regulatoryframework for the safe utilization of gas. Although not directlyquantifiable, the benefits due to these institution building efforts aresignificant and far-reaching. Enhancement of planning capabilities willhelp ensure that the sector's long-term expansion will be based on a leastcost program. Accordingly, investments by various entities in the sectorcan be optimized thus avoiding duplication of facilities and resulting inbetter synchronization of their respective development activities. Theestablishment of standards for engineering design, equipment and consumerappliances which are tailored in the context of local requirements, willenable the gas sector to avail of greater economies in the domesticproduction of these goods and services. Development of zafety regulationswill protect the population and environment from potential hazards of gasoperations and will help sustain industry's credibility as a safe andstable source of domestic energy. The proposed marketing surveys andresearch on consumer preferences and behavior with respect to gas use, aswell as on inter-fuel demand, would go a long way in ensuring that the gasindustry is responsive to consumer needs. Consistency in customersatisfaction is a key gauge to m&rket growth and stability. Finally, thetechnology transfer and enhancement of managerial skills associated withthe project will develop the sector's human resources and add to the poolof experts needed to manage the growth of the gas industry. The expectedover-all impact of these institutional upgrading is the accelerateddevelopment of the gas sector on an economically rational basis thusexpediting the country's diversification from oil-based domesticconsumption and increasing its foreign exchange earning potential.

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VI. AGREEMENTS REACHED

6.1 Prior to negotiations, assurances were received from GOI that thequantities of gas required for Surabaya and Medan components of the projectshall be made available to PGN.

6.2 During the negotiations, agreements have been reached with GOIthat,

(i) it will provide PGN and LEMIGAS with necessary funds tocarry out the project (para 3.29 and 4.21);

(ii) it will prepare and furnish to the Bank, for its review andcomments, a proposal for the establishment of a GasTechnology Development Unit in LEMIGAS, taking into Accountthe recommendations of its ongoing planning study and theBank's comments, in accordance with a timetable acceptableto the Bank (paras 2.27, 3.22 and 3.33);

(iii) it will furnish the Bank with audited project accounts forthe Gas Technology Development Unit and the marketingstudies within nine months of the end of its each fiscalyear (para 3.29);

(iv) it will ensure that PGN obtains, in a timely fashion, thenecessary rights of way/way leave for the pipelines to bebuilt under the project (para 3.30);

(v) it will allow PGN to mainti.in its pay scale at a level asremunerative as that offered by similar public corporations(para 2.16); and

with PGN that it will,

(i) furnish the Bank with a detailed training program(including the component for efficiency improvement)according to a timetable acceptable to the Bank (para2.17);

(ii) provide the Bank with its unaudited financial statementswithin six months and the corresponding audited reportwithin nine months of the end of its fiscal year (para2.21);

(iii) prepare a rolling five-year plan covering its future gasrequirements, which will be updated each year and discussedwith GOI and PERTAMINA to form the basis for furthernetwork expansion (para 3.8);

(iv) submit to the Bank quarterly progress reports according toa format acceptable to the Bank (para 3.41);

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(v) revalue its fixed assets in operation annually according tothe method acceptable to the Bank and submit it to theBank, together with unaudited financial statements withinsix months of the end of each fiscal year (para 4.13);

(vi) implement the efficiency improvement program (para 4.16);

(vii) take all necessary measures to produce a rate of return onrevalued net fixed assets in operation of not less than4Zin FYs9l-93, 82 in FY94 and lOZ thereafter (para 4.18);

(viii) by January 1 of each calendar year prepare an annualinvestment program and submit it to the Bank for comment(para 4.20); and

6.3 Conditions of the effectiveness of the proposed Loan would be:

(i) the execution of gas supply contract, acceptable to theBank, for the supply of natural gas to PGN'9 Surabaya andMedan transmission and distribution systems covering theproject requirements (para 3.8);

(ii) the execution of a technical assistance agreement,acceptable to the Bank with an established gas utility inorder to assist PGN in the implementation of the projectkparas 2.15 & 3.21); and

(iii) the execution of a Subsidiary Loan Agreement, satisfactoryto the Bank, between the Borrower and PGN (para 3.29).

6.4 Condition(s) of disbursement of funds allocated for the GasTechnology Development Unit would be,

(i) the Borrower's approval of its organization as determined byits planning study, including ar. implementation schedule andreporting requirements satisfactory to the Bank (para 3.22);and

(ii) signing of a technical assistance agreement satisfactory tothe Bank, with an established gas technology instituate(paras 3.22, 3.33 & 3.42); and

for the marketing feasibility studies, it would be the Bank's approval of theterms of reference and expertise required for their conduct (para 3.24).

Recommendation

6.5 With the above agreements, the proposed project would be suitablefor a Bank loan of US$86 million, repayable over 20 years, including 5years of grace, at the standard variable interest rate, with the Governmentbearing the foreign exchange risk.

-47- Annex 1.01

INDONESIA

GAS UTILIZATION PROJECT

GAS SECTOR DATA - ESTIMATED GAS RESERVESAs of January 1. 1988

(In Billion SCF) .

REGION PROVEN POTENTIAL TOTAL

ACEH 16930 1070 18000

NORTH SUMATRA 800 1320 2120

CENTRAL SUMATRA 450 500 950

SOUTH SUMATRA 4224 880 5104

WEST JAVA 3148 2690 5838

EAST JAVA 2336 120 2456 a/

EAST KALIMANTAN 19620 7180 26800

CENTRAL KALIMANTAN - 6200 6200

NATUNA 36180 1570 37750

SOUTH SULAWESI 410 200 610

CENTRAL. SULAWESI - 220 220

IRIAN JAYA 200 210 410

TOTAL 84298 22160 106458

a/ Excluding potential reserves of about 2.5 TCFbased on recent discovery.

Source: MIGAS

INDONESIA

GAS UTILIZATION PROJECT

HISTORICAL GAS PRODUCTION(in Billion SCF)

PRODUCER 1981 1982 1983 1984 1985 1986 1987 1

Pertamina 103 184 199 215 218 229 240

MIGAS-CEPU 0.2 0.2 0.2 0.2 0.2 0.2 0.2

Contract of Work Contractors 70 69 75 20 20 22 21

Production Sharing Contractors 369 859 912 1,286 1,342 1,378 1,471

Total 542 1,112 1,186 1,521 1,580 1,629 1,732

Source: MIGAS

-49- Annex 1.03

INDONESIA

GAS UTILIZATION PROJECT

GAS PRODUCTION/UTILIZATION BALANCE. 1985-1987(in Billion SCF)

1985 1986 1987

A. Gross Production 1580.0 1628.9 1732.1

B. Own Use1. Gas Injection 253.7 245.7 249.72. Gas Lift 48.7 52.9 58.73. Fuel Gas 75.1 83.1 88.0

Subtotal 377.5 381.7 396.4

C. Net Production 1202.5 1247.3 1335.7

D. Sales1. Electricity (PLN) 0.1 2.8 5.22. City Gas 1.3 1.3 1.73. Fertilizer Plants 127.6 136.1 138.34. Cement 1.0 2.1 2.75. Cilamaya 1/ 66.7 76.5 77.86. Refinery 12.9 19.0 20.97. LPG Plants 47.1 41.0 24.58. LNG Plants 816.8 834.4 917.09. Gas Industries/Others 0.1 0.17 0.3

Subtotal 1073.5 1113.3 1188.3

E. Flared 129.1 134.0 147.3

_______________________

1/ Delivered to Kujang fertilizer plant, Krakatua Steel, Cibinong Cementand City Gas for Jakarta and Bogor.

Annex 1.04

-50-

INDONESIA

GAS UTILIZATION PROJECT

HISTORICAL GAS PRODUCTION BY REGION(in Million SCF/Day)

REGION 1984/85 1985/86 1986/87 1987/88 1988/89

Aceh 1,821 1,866 2,001 2,220 2,424North Sumatra 94 99 87 95 121Central Sumatra 83 86 91 92 85South Sumatra 316 323 339 342 365West Java 425 436 467 444 433East Java - 5 5 3 3East Kalimantan 1,450 1,484 1,497 1,550 1,687

Total 4,189 4,299 4,487 4,746 5,118

HISTORICAL GAS CONSUMPTION BY REGION(in Million SCF/Day)

REGION 1984/85 1985/86 1986/87 1987/88 1988/89

Aceh 1,190 1,200 1,332 1,542 1,702North Sumatra 16 22 18 19 42South Sumatra 165 174 174 173 174West Java 171 202 240 218 216East Kalimantan 1,289 1,277 1,272 1,312 1,479 r

Total 2,831 2,875 3,036 3,264 3,613Source: == ==…IG AS= =======

Source: MIGAS, July 1989

INDONESIA

GAS UIILIZATION PROJECT

COMPOSITION OF CURRENT* 1NDUSIRID.L DEUAND IN SURABAYA AND MEDAN(in Thousand Cubic Motor)

A. SURABAYA

Texti leArea 8aMetal Chem Food Class Others Pherm. Palo Oil Print. Rubber Wood Ceramic Pzpar Elect. Total

Kot 1 916 4031 3462 2 1 1301 1 939 4 0 0 0 10648

Dupak 0 0 0 0 0 0 0 0 0 0 0 0 0 0Tend.s 30312 477 0 0 2 0 281 0 0 0 0 0 0 31072

Si;o 6961 0 1123 0 0 0 0 0 3e7 0 0 0 0 7441

K. Pi;ang 2497 0 122 0 2700 0 183 0 1413 0 26772 14804 0 47361

Runokut 6287 263 2714 41830 8067 0 13602 0 61 0 0 381 0 74404

S.goroeadu 1903 0 0 0 0 0 0 0 0 0 0 0 0 1903

R-are 246 1643 426 0 778 0 434 0 0 0 27014 17230 0 47976

Driyorejo 117 27629 1260 0 7 0 0 0 92 0 0 31872 0 60967

Waru 14462 1222 9113 0 0 0 0 0 0 0 0 0 0 24617

Aloha 29623 2086 0 0 607 0 0 0 0 0 0416 0 3760 42380

Tuaa 17890 664 60246 244 0 0 0 0 0 9046 0 0 84078

Total 108211 36739 19435 101633 12397 1 16701 1 2872 4 68246 64147 3760 433036

As 3 of Total 261 8a 4X 23% 31 0% 4X 0 1% 0% 161 165 1% 1001

S. MEDAN

Area B.Mtal Chem Food Wood Text. Print. Phare. Class Elect. Others Total

Bolawan 22948 49348 8437 126 1743 700 1363 16236 200 6674 106763

sinjoi 1792 6966 47704 324 1660 392 0 0 0 24 68771

Tg. Morgue 2178 14613 711 660 0 0 168 8886 0 1118 28214

Total 26918 70946 66862 999 3293 1092 1511 26121 200 6816 193748

As a 1 of Total 14% 37% 291 1 2% 1i is 13% 01 4% 3001_- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

GAS DEMAND AND SUPPLY PROJECTIONS FOR S')RA8AYA AND MEDAN

(All Figures in MMCFD)

A. MELAN

DEMAND SUPPLY

P1) PLN PW N PGN Total Demand PlA PLN PGN PGN Total SupplyYear AV. MAX. AV. MAX. Total Demand MAX. AV. MAX. AV. MAX. Tota! Supply MAX.Ending DAY DAY DAY DAY AV. DAY DAY DAY DAY DAY DAY AV. DAY DAY

1991 61 94 10 12 71 106 30 40 6 a 36 481992 71 109 12 14 83 123 30 S0 5 6 35 so1992 85 131 1S 18 100 149 48 74 12 14 80 881994 91 140 17 20 108 160 48 74 12 14 s0 881995 106 162 19 22 126 184 48 74 12 14 80 881996 112 173 20 24 132 197 48 74 12 14 60 881997 132 204 22 28 164 230 48 74 12 24 60 881999 177 273 23 28 200 301 48 74 12 14 6o 882000 177 273 25 30 202 303 48 74 12 14 so 882001 177 273 27 32 204 306 48 74 12 14 6o 882002 177 273 28 34 206 307 48 74 12 14 80 882003 177 273 30 38 207 309 48 74 12 14 80 882004 177 273 30 36 207 309 48 74 12 14 s0 882005 177 273 30 38 207 309 48 74 12 14 so 882006 177 273 30 38 207 309 48 74 12 14 80 88

48 74 12 14 6o 88

8. SURABAYA

DEMAND SUPPLY

Total TotalMED. Size MED. Size Paper Paper MED. Size MED. Size Paper Paper Demand Demand

Year Industrial Industrial Loces Lecos Total Demand Total Demand Industrial Industrial Leces Loces AV. iAX.Ending AV. DAY MAX. DAY AV. DAY MAX. DAY AV. DAY MAX. DAY AV. DAY MAX. DAY AV. DAY MAX.DAY DAY DAY

1991 12 16 i8 20 28 38 0 0 0 0 0 01992 12 16 16 20 28 36 0 0 0 0 0 01993 12 16 16 20 28 36 0 0 0 0 0 01994 12 16 16 20 28 3S 6 8 5 6 10 141995 23 30 l 20 33 60 12 16 20 22 32 381996 38 42 16 20 62 82 23 27 20 22 43 491997 50 50 16 20 68 72 36 42 20 22 s6 841996 55 66 16 20 71 s8 60 S8 20 22 70 801999 60 72 16 20 76 92 S6 66 20 22 75 a82000 84 77 l 20 80 97 SO 72 20 22 80 942001 67 81 16 20 83 101 sO 72 20 22 SO 942002 70 84 18 20 se 104 60 72 20 22 80 942003 ?4 89 18 20 90 109 86 80 20 22 85 1022004 78 94 18 20 94 114 65 80 20 22 8a 1022005 82 98 16 20 98 118 70 84 20 22 90 1062006 8e 103 l 20 102 123 70 84 20 22 90 106 X

Note: AV. DAY = average day; MAX. DAY = maximum day. C

INDONESIAGAS UTILIZATION PROJECT

PGNExisting Organogram

r ------------------------------l ~~~~~~~~~~~PRE8BNT DIMCTtlUl

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INDONESIAGAS UTILIZATION PROJECT

PGNProposed Organogram

l ~~~~~~~~~~~~~~PR£SOENT DIRECTORI

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INDONESIA

GAS DISTRIBUTION PROJECT

ORGANIZATION OF MIGAS

DIRECTOR GENERAL

Dietr ,)rctr Director,

Director, Director, Director, Director, Director, Director,Exploration Exploration Technical Business Research and Human Resource& Production & Production Services Development Development Development Iof Oil & Gas Geothermal Centre for

Resources Oil & GasTechnology(LEMIGAS)

: 1

o . IA N*

INDONESIA

GAS DISTRIBUTION PROJECT

ORGANIZATION OF LEMIGAS

DIRECTOR

Divisional Head, Divisional Head, DivislInal Head, Divisional Head, Divisional Head, Divisional Head,

Research and Technical Ser- Research and Technical Ser- Data Collection General Affairs

Development in vices for Development in vices for and Analysis (Finance,Personnel I

Petroleum Petroleum Petrochemical Petrochemical and General Services

Exploration Exploration and Process and Process and Administration)

and Exploitation Exploitation Application Application

OFamo

wo0.FN N

57 Annex 4.01Page 1 of 9

INDONESIA

GAS JTILIZATION PROJECT

Implementation and Technical Management Assistance

Terms of Reference

I. Introduction

1.1 The Government of Indonesia (GOI) proposes to develop and expandnatural gas utilization in and around Surabaya and Medan. Perusahaan GasNegara (PGN), henceforth called the "Client", will be responsible forimplementing the project and operating the facilities. PGN is a publiccorporation placed under the supervision of the Ministry of Mines and Energy.It is already engaged in the transportation and distribution of natural gasand manufactured gas for power generation, industrial, commercial and domesticuse in these areas. Since the project would entail a manyfold expansion inPGN's operations, it requires institutional strengthening to enable it todischarge its expanded responsibilities efficiently. For this purpose PGNintends to enter into a long term technical collaboration (twinning)arrangement with a prominent gas utility, hereinafter called the "Consultant".

1.2 The proposed twinning arrangement will be characterized by a closerinvolvement between the two parties than is generally obtained in a standardclient-consultant relationship. It is intended that the twinning utilityshould identify itself fully with the needs and objectives of PGN, and wouldprovide PGN with continuing back-up services, advice, and experiencedpersonnel over a number of years.

The objectives of such twinning would be:

(a) to provide sustained technical and managerial support aimed atstrengthening PGN to the point where it can independentlyoperate all asnects of a complex gas distribution system;

(b) to assist in the development and implementation of the systemsrequired by a commercial gas utility, including:

(i) design of market development strategies and systems,including market surveys, pricing, and contractualarrangements;

(ii) planning and design of gas compression, transmission anddistribution systems;

(iii) material control and procurement;

(iv) construction of pipelines compression, pressureregulation, flow measurement, telecam/SCADA, andodorization facilities;

-58- Annex 4.01Page 2 of 9

(v) gas compression, transmission and distribution operationsand maintenance;

(vi) accounting, billing and collection;

(vii) management information and cost control;

(viii) long-term planning, investment appraisal and riskanalysis;

(ix) financial management and control;

(x) human resource development.

(xi) advisory service to customers on efficient and safeutilization of natural gas; involving design ofhouselines, selection of suitable gas firing equipmentand safety procedures;

(xii) preparation of all necessary standards and manuals forconstruction and maintenance of the gas systems; and

(xiii) to the extent requested by the Client, advice oninstitutional structure and personnel arrangements.

(c) to provide back-up support in day-to-day technical and financialoperations; and

(d) to provide conventional technical assistance services in supportof the design and execution of the proposed expansion project(the Project) as described in Section II.

1.3 The mechanisms for achieving these objectives would include:

- secondment of experienced professional personnel from theConsultant's own organization into parallel positions in theClient's organization.

- provision of back-up services from the headquarters organizationof the Consultant.

- design and implementation of a comprehensive training program,including training courses, on-the-job training, and theselective assignment of the Client's personnel to theConsultant's organization for the first-hand exposure tooperations.

- provision of specialist technical personnel and services toundertake discrete tasks as required.

II. The Project

2.1 Most of the activities of the Client over the next six years willcomprise of the expansionlrehabilitation of its gas supply systems for

-59- Annex 4.01Page 3 of 9

Surabaya and Medan. This project will be undertaken concurrently with theon-going Gas Distribution Project, which is due to be completed by July1991.

2.2 The main components of the Project are:

(a) Provision of Natural Gas Supply System in Surabaya and itssurrounding areas, involving:

(i) the laying of about 80 km of high pressuretransmission pipelines, 190 km of medium pressuresteel pipelines and 165 km of medium pressurepolyethylene pipelines;

(ii) the construction of about five gas metering, pressureregulating and odorization stations with associatedinstrumentation and about four pressure reducingstations on the pipeline networks; and

(iii) the construction of service lines, pressure regulationand flow aetering stations for 375 medium sizeindustries and 150 commercial enterprises and thepaper mill in Leces and conversion of consumer'sequipment (excluding PLN's) involved in gas usage.

(b) Expansion of Natural Gas Supply System for Medan involving:

(i) the construction of about 24 km of high pressuretransmission pipeline with associated cathodicprotection, pressure/flow monitoring facilities andthree pressure reducing stations; and

(ii) construction of service lines and pressure regulatingand flow metering stations for PLN power station atBelawan and conversion of consumer's equipment(excluding PLN's) involved in gas usage.

(c) Technical Assistance involving long-term consultancy for theenhancement of PGN's skills and efficient implementation of itsexpansion project;

(d) Studies: Feasibility studies for natural marketing in Palembang(South Sumatra), Jambi (Central Sumatra), Batam Island (Riau),and Balikpapan.

III. Scope of Consultancy Services

3.1 General. On assignment the Consultant will promptly plan and renderall necessary advice/assistance to the Client to achieve the objectives setforth in para 1 and 2 above within the time frame to be specified in thecontract. Such assistance will include but will not be limited to thefollowing:

-60- Annex 4.01Page 4 of 9

(a) back-up services from headquarters organization of theConsultant for systems development referred in para 1.2 (b);

(b) review of clients existing organization and submission ofrecommendations for changes as considered necessary forstrengthening the organization in the functions of (i)marketing/conversion/consumers service; (ii) systemsoperations/maintenance; (iii) systems planning/design; and (iv)project implementation/procurement of materials.

(c) assistance in the implementation of the systems referred to inSection I above, by providing the services of well-qualified andexperienced personnel from the Consultant's own organization.While the exact number of such personnel will be determined inconsultation with the Client, it is imperative that at leastfive such personnel be posted at the Client's head office toassist/advise the Client's management and ensure achievement ofthe objectives set forth above. These five personnel will cover(i) marketing/conversion/consumers services; (ii) cransmissionand compression systems design, operation/maintenance; (ii4)distribution system operation/maintenance; (iv) distributionsystem planning/design; and (v) project implementation/procurement of material; and

(d) providing, to fullest extent possible, on-the-job training tothe Client's staff at all levels, starting from the level ofsub-directors downwards. The four personnel referred to in (c)above will have as counterpart the respective sub-director ofthe Client's organization responsible for his particulardiscipline. The advisors will be responsible both for (i) thesuccessful implementation of the Project, and (ii) through thefull involvement of the Client's staff at all levels in theexecution of the Project, for building up the capability of theClient to discharge efficiently the functions of a modern gasutility upon completion of the Consultant's assignment.

3.2 The Consultant will carry out the assignment using modern up-to-datetechniques of gas industry. He will work in close cooperation with theClient's representative, henceforth called the "Manager', who will render allassistance to the Consultant in carrying out the assignment. The Consultantwill render to the Manager all necessary advice, including but not necessarilyconfined to, the items listed in this section, to ensure the successfulimplementation of the ;roject. It is understood that the Manager willseek/receive and the Consultant will promptly render/initiate all such advicein time; and also that in order to enable the Consultant to be heldresponsible for the assignment, the Manager will normally act upon the advicein time or keep the Consultant advised of the reasons to the contrary. Ingeneral, the Consultant will keep the Manager continuously informed onprogress of the project, particularly with reference to problems that couldcause delays.

Detailed Assignments

3.3 The detailed assignments of the Consultant have been specified inrelation to the Project to be implemented by the Client. However, in all

-61- Annex 4.01Page 5 of 9

aspects of his work, the Consultant's responsibility will be two-pronged,aiming both at a successful Project implementation and at transferring theknow-how involved to the Client's staff. The Consultant will, therefore, beexpected to organize the work in consultation with the Client's counterpartstaff and fully involve the Client's staff in the execution of hisresponsibilities, which will include but may not be limited to the following:

(a) Preparatory studies and engineering. The Consultant will reviewall existing studies, data, designs, and acquire additional dataif necessary to ensure that the expansion of the distributionsystems is carried out in a rational manner giving dueconsideration to long-term market prospects. He will, with theassistance of the Client's staff, fully design the project andestablish the criteria for its detailed design and construction;prepare the project master plan (CPM) and a project costestimate which will be continuously updated with the progress ofthe project.

(b) Project Management. The advisory services of the Consultantwill relate to the full responsibilities of the Manager. Inparticular the instructions to and reports of the varioussuppliers/contractors will be processed by the Consultant fornecessary advice. The Consultant may also render suchmanagement functions as may be mutually agreed with theunderstanding that he will be at all times and in all situationsdo so in the best interest of the Client. In general, theConsultant shall:

(i) provide the necessary progress and budgetarymonitoring control and information systems to keep allparties concerned adequately advised of progress,problems and developments;

(ii) periodically review and report actual and estimatedexpenditures;

(iii) issue a formal progress report covering all aspects ofthe project;

(iv) organize and coordinate the efforts of all othersparticipating in the design, construction andcommissioning of the project;

(v) establish effective communication procedures andmaintain liaison with the Client and other concernedparties;

(vi) advise the Client on insurance coverage;

(vii) advise the Client on regulatory framework andlicensing requirements for the distribution of naturalgas;

(viii) advise the Client on the gas purchase and gas salecontracts;

-62- Annex 4.01Page 6 of 9

(ix) prepare procedures for all activities involved in thedistribution of natural gas;

(x) utilize and cooperate with the Client's staff toprovide experience and on-the-job training for itspersonnel to the fullest extent practical.

(c) Project Engineering. The Consultant will be responsible fot thetimely preparation of all engineering design of the project.This will include all items necessary for the successfulconstruction and commissioning of the project such as:

(i) preliminary activities including data acquisition, routesurveys, systems evaluation, etc. depending on therequirements of each specific project components;

(ii) material and equipment specifications;

(iii) codes and standards requirements for construction andoperation of distribution system;

(iv) flow sheets, diagrams, construction and fabricationdrawings, and as-laid drawings;

(v) detailed cost estimates;

(vi) operation/maintenance manuals and inventory of spareparts for all the installation involved in thedistribution of natural gas;

(vii) lists of materials, equipment, material and equipmentrequisitions and technical portion of bid documents forpurchase, service and construction contracts;

(viii) construction, commissioning and start-up assistance asrequired.

(d) Procurement. The Consultant will advise and assist the Managerin establishing procurement procedures covering all activitiesand responsibilities from the requisitioning stage to thereceipt of contract services, goods and payment of invoices.The procedures will include:

(i) preparation of bid documelits and purchase orders,prequalification of bidders, evaluation of bids andquotations, recommendation for awards, placement oforders or contracts;

(ii) delivery status and controls;

(iii) inspection, testing and other quality control measures;

(iv) contract services, material and equipment receiving andstorage; and

(v) payments, accounts and records.

-63- Annex 4.01Page 7 of 9

(e) Construction Supervision. The Consultant will be responsiblefor the supervision of all construction activities and fieldservices. His responsibilities will include:

(i) advice on establishment of the necessary organization andphysical facilities to enable the execution of theseresponsibilities;

(ii) supervision and coordination of all work progress by theClient, suppliers/contractors and other concernedagencies with reference to the critical path, so as tomodify the respective bodies of delays, with advice onways to expedite matters;

(iii) establishing and executing all necessary inspection,testing and other quality control procedures andmeasures;

(iv) maintaining the necessary records, progress reports andother management information system;

(v) maintaining "as built" records, contractual variationsand change orders and negotiating settlements forchanges; and

(vi) certifying acceptance of invoices and contract servicescompletion reports.

(f) Commissioning and Operating Assistance. The Consultant will beresponsible for the commissioining and shake down of thefacility and for the first six months (or any other such periodthat the Client might wish to negotiate at a later date) ofcommercial operations. These responsibilities will include:

(i) preparing and assembling all necessary operating andmaintenance procedures and instructions and plant recordbooks;

(ii) organizing a start-up team. This team will start-up andshakedown the facility with the full participation of theClient's operating staff; and

(iii) designate and organize the operating and maintenanceteams that will assist the Client's staff to operate thefacilities.

(g) Conversion. The Consultant shall organize the conversion ofindustrial consumers to gas fuel and shall take all necessaryactions for this purpose in order to meet the schedule ofindustrial gas connections provided in the projectimplementation program. This will involve, inter alia, detailedsurveys of customers processes and plants, evaluation ofavailable engineering skill and know-how and estimation of gasfuel requ,rements; leading to the design of houseline,estimation of material requirements and recommendations on

-64- Annex 4.01Page 8 of 9

suitable type(s) of gas firing equipment. The recommendedequipment should be simple and robust in design so as tominimize the outage time and maintenance costs and it should beprocureable on competitive basis in order to make the conversionas cost effective as possible. As far as possible the servicesof local contractors should be used for installation ofhouselines and gas firing equipment.

(h) Administration. The Consultant will review the Client'saccounting, administrative, and personnel procedures and conductnecessary feasibility studies to advise the Client on suitableoffice machines, computer and software. The Consultant willalso assist the Client in writing specifications for hardwareand software to be procured and, after procurement, inimplementation of new equipment and procedures as necessary.

IV. Assistance to be Provided by the Client

4.1 The Client through the Manager will provide the following servicesand facilities to the consultant:

(a) administrative assistance in obtaining visa, customclearances and any other administrative permits required bythe Consultant in the performance of this assignment;

(b) existing data, maps, surveys and studies;

(c) office space, secretarial and other office staff inIndonesia;

(d) transport as required within Indonesia;

(e) liaison with go-ernment and local bodies; and

(f) any other assistance not readily available which theConsultant may reasonably request.

V. Project Schedule

5.1 The Consultant's proposals must be received by . Itis expected that the Consultant will be selected by and thata contract/agreement will bi signed by _ _ . The Consultant wouldthen be expected to mobilize and start work at the earliest date possiblebut not later than after the award of the contract so as tomeet the project completion date of _

5.2 It is expected that at least four basic personnel will have to beseconded to PGN head office for most of the Project period (para 3.1 (c)).However, this core team will have to be supported by a number of support-level engineers during the peak design/construction period. Moreover,provision should made for short-term specialized assignments to deal withsuch matters as design of MIS systems; review and planning of computer andoffice systems; preparation of standard documentation and manuals; tariffstudies; market studies; etc. The Consultant will provide a proposed workprogram detailing the timing of each assignment to be discussed and agreed

-65- Annex 4.01Page 9 of 9

with the Client. The proposed work program should provide for a phasedreduction in the size of the Consultant team assembled in Indonesia in linewith the objective of ensuring self-sufficiency of the Client in all majoroperational areas.

-66- Annex 4.02Page 1 of 4

PLANNING STUDY

GAS TECHNOLOGY DEVELOPMENT

CENTER IN INDOtESIA

TERMS OF REFERENCE

I. INTRODUCTION

Indonesia is embarking upon a major program to increase the domestic useof natural gas. The impact of such a program is far reaching and wouldnecessitate development of a whole new range of technical expertise for (a) planningand design of gas transportation systems and conversion equipment, (b) research ontransportation systems and conversion equipment, (c) preparation and promulgation ofcodes and standards for regulation of the gas industry and consumers for safe andefficient operation, and (d) measures to encourage private manufacturing industry tosupport domestic gas utilization. To successfully achieve these goals, there is aneed to form a central organization (a gas technology development center) to assistthe Government in the coordinated development and regulation of gas industry. Thiscenter will be organized within LEMIGAS whose statute permits it to undertake suchactivities.

II. MAIN FUNCTIONS AND SCOPE

The main function of the center would be:

a. research, development and compilation of standards and codes ofpractice, appropriate to the Indonesian environment, for allactivities, infrastructure, materials and equipment involvedin the transportation of natural gas and its usage;

b. studies and research in gas utilization, interfuel substitutionand energy conservatior. for suppliers, distributors and users;

c. analysis of fuels and materials for efficient gas utilizationand environmental protection;

d. human resource development;

e. dissemination of technical information.

The research on standards and codes of practice will cover all theactivities in the transportation of gas from the gas well to the consumer. Theseare broadly categorized as gas treatment, compression, transmission, distribution,measurement and corrosion control. It will involved both a review of and researchinto: (a) standards and codes of practice of major gas consuming countries of theworld; (b) current Indonesian standards, codes of practice, operational procedures

-67- Annex 4.02Page 2 of 4

and skills: and (c) environmental, social and industrial conditions specific toIndonesia. After thorough research, with the full participation of the gas industryand the consumers, the standards will be progressively formulated and submitted toMIGAS for approval and promulgation.

The studies in gas utilization will identify the potential for its economicdevelopment and appropriate scale and phasing of investments. The research ininterfuel substitution, combustion engineering and energy conservation shall beaimed at equipment and appliances. The Indonesian manufacturing industry. as wellas PGN, will be fully associated with this work. All studies and research paperswill be published. Processes and designs will be patented.

The direction and quality of research and studies for each research activitywill be controlled by a standing committee composed of the profe3sional staff of thecenter and professionals from MIGAS, PERTAMINA and PGN, together withrepresentatives of gas consumers and manufacturing industry.

The center's involvement in such research activities will give it a uniqueinsight into the gas industry's manpower expertise and skills and would enable it toprovide valuabie guidance in the industry's manpower planning. Its human resourcedevelopment function will be organized to perform the need analysis for the planningand upgrading of gas industry's manpower expertise and to design and conductappropriate courses for this purpose. These courses will support the training ofthose in the industry who need to develop specialized knowledge and skills. It willalso assist the country's technical universities in the development of curricula forcourses in gas engineering and technology.

A technical information service will be organized in the center for reliableand efficient dissemination of technical information on all aspects of gasdevelopment and utilization. It will perform this function through, (a) acquisitionof technical information and literature and by the setting up of a referencelibrary, (b, publishing the center's technical papers and reports, (c) organizingconferences and seminars and, (d) liaison with the news media and publishers oftechnical literature.

Through high quality research and reliable dissemination of knowledge, thecenter will establish itself as a primary and authentic source of technicalinformation on natural gas. Its principal interactions will be with:

- the government for legislation and human resource development;

- the gas producing and marketing companies for research on standards,materials and equipment;

- the universities for development of curricula for gas engineeringand technology courses;

- the manufacturing industry for manufacture of efficient materials,equipment and appliances;

- the market for interfuel substitution and energy conservation; and

- overseas research institutes for exchange of technical informationand expertise.

-68-Annex 4.02Page 3 of 4

III. Consultant's Scope of Work

The consultant is required to prepare a detailed plan and cost estimates for agas technology development center, which will include but will not be confined to:

- formulation of the institutional framework for the center, takinginto account manpower availability and national and legal policyrequirements;

- establishment of the center's charter and bylaws;

- recommendation of an appropriate organizational structure;

- preparation of position descriptions for seniors personnel;

- evaltdtion of professional staff requirement;(every professional staff position should be separately identified.Qualifications and experience, as well as a job description for eachjob should be written. Manpower availability in and outside Indonesia,should be evaluated for each job)

- preparation of an appropriate training program;(on the basis of staff requirement, educational and professionaltraining needs for each job alongwith a cos0 estimate)

- preparation of a work program for the center for the next fiveyears, in line with national energy policy for both the short andand long term;

- identification of special support to be provided by the center tothe gas industry for existing operations, and that needed fordevelopment of new operations to meet future needs;

- determination of the availability of foreign technical and manpowerresources to be used to support the center's activities;

- preparation of a conceptual plan for the center's building and physicalfacilities and utilities for laboratories, library and technicalinformation services; and

- preparation of capital and operating cost estimates for setting upthe center and its operation for a five year period and detailedprocurement specifications of all equipment and literature required.

IV Time Frame of the Study

The work by the Consultant should be finished not later than six months afterthe Service Contract according :o the following tentative schedule

-69- Annex 4.02Page 4 of 4

Elapsed Time from Project Start DateNumber of Months

1. Scope of Reports 12. Interim Report 3.53. Draft Final Report 5

- Program Plan- Organization- Implementation Schedule

4. Final Report and Plan 6

V. Reporting Requirements

All reports of the work should be in the English Language (25 copies to besupplied). There should be one interim report and one final report. The interimreport should contain the plan of work, explaining the steps to be taken by theConsultant. Such a report should also present the schelule of work, manning andfinancial requirements.

The Final report is to be submitted at the end of the sixth month, followed bya formal presentation.

VI. Budget Estimate for the Study

a. Direct Labor $200,000b. Local expenses in Indonesia 31,250c. Travel

5 RT tickets at $3,000 each 15,000d. Hotel expenses & per diem (70 days @ 150/day) 10,500e. Report preparation, communications &

presentation 10,000f. Fee 27,175g. Others 5,000

Total $300,000

VII. Communication

All communication related to this work is to be directed to:

The Secretariat of Gas Technology Development CenterAttention: Dr. WirantoLEMIGAS Cipulir Kebayoran LamaJakarta Selatan 12230IndonesiaPhone: 739-8276; 739-4422 ext. 247Telex: 47172 LMGB IA and 47150 LMGB IAFax: 716-150

-70- Annex 4.03Page 1 of 4

INDONESIA

GAS UTILIZATION PROJECT

Regulatory System for Safe Utilization of Natural Gas

Introduction

The ability to safely transport and distribute natural gas inhighly populous regions has been abundantly demonstrated in IesternEurope, North America and in several developing countries. The goodsafety record is the result of the industry's recognition that gasnetworks must be built of suitable materials to meet sound engineeringprinciples; it must be tested frequently to identify and rectify leaksor potential problems; and users must be educated to install and operategas-fueled equipment safely. In order to have an effective safetyprogram there must be a means of enforcing the regulations and a meansof taking corrective action when violations are found. In most casesthis would require that the safety regulations nave the force of law sothat violators can be dealt with by an administrative body or thecourts.

Safety regulations have been developed by the industry andgovernment agencies in many countries and, while the specific detailsvary to meet local conditions, all incorporate certain essentia'.elements. They should:

- establish guidelines for selection, testing and inspection ofmateriaus used in all parts of the supply system.

- define acceptable methods for installing pipelines, meteringand regulating equipment, and customer piping and equipment.

- set the requirements for periodic inspection and testing ofequipment and facilities.

The purpose of this paper is to outline the requirements for asystem of safety regulations which could be utilized by the Governmentof Indonesia and the gas industry in the development of the natural gasdelivery system downstream of the producing fields.

Scope

As currently envisioned, the r4gulations would apply to theselection of materials and equipment, installation and commissioning ofall pipelines, metering and pressure regulation equipment andappurtenant equipment used by the gas transporter to deliver gas fromthe field delivery point to the outlet of the customer's meter; and thepiping and equipment installed on the customer's premises.

-71-Annex 4.03Page 2 of 4

Objective

The objective of the work effort will be to establish alegislative, regulatory and technical system to assure that the naturalgas delivery system in Indonesia will continue to be installed andoperated in safe manner.

Regulatory System Requirements

The regulatory system must include a minimum of tbree components:

- The legislative basis for regulating the actions of privateor public entities. Legislative intervention is usually basedon the government's duty to protect the public health andsafety. In some instances existing safety laws may be amendedor reinterpreted and new legislation would not be required.

- Safety codes and regulations. These are general rulespromulgated by a governmental authority which define thelimits on materials to be used, performance and operationalrequirements. They may take the form of performance standardswhich set and define the function(s) a material must performsafely, or equipment standards which specify the equipment tobe used for each purpose. The former are more commonly used inindustrialized countries.

- Engineering standards. These are prepared by each individualcompany and used by engineers and operators to design, specify,install and operate the system. They must meet the minimumrequirements of the safety codes.

Each of these elements is discussed briefly below.

The first requirement for an effective safety regulation system isa legislative base. In most industrialized countries the natural gasindustry was, for many years self-policing. That is, the industryestablished technical standards and each company applied them accordingto its own interpretation. In the event of an accident, the injuredparty sought remedy via the courts. However, as the pipeline networkgrew and the potential for losses increased local and federallegislatures instituted laws setting minimum safety standards; providingfor administrative control and relief; and establishing penalties fornon-compliance. In the United States the Pipeline Safety Act, whichapplies to both natural gas and liquid products pipelines provides alegal foundation for regulating the lines; establishes the scope of theregulations; and delegates authority for implementation to the FederalDepartment of Transportation. Similar laws have been passed in otherindustrialized countries.

The second element is a set of regulations established by theresponsible government agency which define the minimum standards for

Annex 4.03-72- Page 3 of 4

selection, installation and operation of equipment. The regulationsusually define the inspection and control procedures which the agencyuses to assure compliance and reporting requirements. The regulationsare based on international engineering design standards and experiencein the use of specific equipment for natural gas delivery systems. Amethod for monitoring the industry's operations must be established.The minimum would be a method of periodic reports on operations andsafety related issues plus a program for periodic inspection offacilities and operations. Reporting procedures and forms would have tobe formulated and an administrative body established to receive, analyzeand follow-up reports and carry out a fie'ld inspection program.

The third element is the safety standards established by eachcompany. These detailed engineering design and operations standards mayvary from company to company but all must meet the minimum standardsmandated by the government agency. They should cover all aspects ofcompany construction and operation and should be updated periodically toincorporate technological advances. The agency should-also beresponsible for periodically revisvling the standards to assure that theyare adequate. Field inspect'ons would be conducted by the regulatingagency to assure that the standards are being met.

Work Plan

Preparation of a program appropriate for the conditions inIndonesia would require:

a. review of the existing legislation which provides thebasis for safety regulations to determine if it providesan adequate legal base for natural gas safety regulationsor if new legislation must be adopted.

b. identification of the issues which must be addressed bythe Indonesian natural gas safety regulations. These wouldinclude, but not necessarily be limited to legal issuesrelated to liability and procedures; technical issuesconcerning operational requirements, the operating environ-ment, the degree of public exposure; the institutionalrequirements for monitoring industry operations andadherence to regulations.

c. preparation of a draft of enabling legislation, or proposedamendments to existing legislation, if appropriate.

d. preparation of an outline of typical technical safetystandards which should be prepared by each company.

e. preparation of a plan for monitoring industry operations,including reporting requirements, inspection programs andthe plan for the administrative structure required toimplement the regulatory program.

-73- Annex 4.03Page 4 ot 4

Implementing Agency

HIGAS intends to develop and direct this program with theassistance from the proposed Gas Technology Development Center.

P64's PP02FCT FLARNINg AND l.PLEMENTATlON SCHEDULEFOR SURABSYA AND lECALN

APR "AR APR MAR APR CAR APR MAR

ACTIVITY FY 198/99 FY 1989/90 FY 1990/91 FY 1991/92 FY 1992/93 FT 1993/94 FY 1994/95 FY 1995/96

:MARKET SURVEY : ----------

:ROUTE SURYEY

:SYSTER DESIGN I ----------I

:FINANCIAL & ECONCOIC ANALYSIS: I--------I :

:APPRAISAL MISSION : : 1-1 :

:DETAILED ROUTE SURVEY AND : ::PERMISSIONS ------------I :

:DETAILED ENGINEERING : -----------------------------------------------------------1:

:LOAN NESOTATION : I--I : : : :

:LOAN EFFECTIVENESS : :

:PROCUREMENT I-------------------------------------------------------------------------------------------1:

:CONSTRUCTION : : -----------

:IMEDAN COMPONENT) : : : a :

:CONSTRUCTION I-------_------------------------------------------:

:(SURABAYA COMPONENT) : : :

FY - FISCAL YEAR ENDING MARCH 31.

- C 0 0 0 0 0 0 0 0 9, 09 00 C~~- - - - - - - -

- -9 .9 9Z , M :: n =1 i= :

ZZ 00%l.00. 90 00;Zoo0.-Z00Z9

Z N~~~~~~~~~~~~~~~~~~~~~~~~~~~- 9

o o o oZ 0I . - -9 - -0 -0- - 0 : 0

z s :: gz 09 0 0 0 0 9 0 0 4g g

- . ~ - 0 0 0 0 0 9 0 0 0 00ZoL,0p, -- 0- 0 0 00-0 0 0 0

0 00z z0 0 0 0 0 00Z0 0 0 0919 9

-76- Annex 5.03

INDONESIA

GAS UTILIZATION PROJECT

Estimated Schedule of Disbursement(US$ million)

TBRD FY and Disbursement Cumulative Indonesia Disbursement

Semester Ending During Semester Amount 2 Profile (Industry) 2

FY91: 12/31/90 3.0 3.0 36/30/91 6.5 9.5 11 20

FY92: 12/31/91 10.1 19.6 236/30/92 26.0 45.6 53 50

FY93: 12/31/92 20.8 66.4 776/30/93 9.0 75.4 88 77

FY94: 12/31/93 2.3 77.7 906/30/94 2.0 79.7 93 90

FY95: 12/31/94 1.8 81.5 956/30/95 1.8 83.3 97 98

FY96: 12/31/95 1.4 84.7 98 986/30/96 1.3 86.0 100 100

a/ Ref. Implementation Schedule (Annex 5.01), project planning anddetailed engineering has commenced.

Annex 5.04Page I of 4

INDONESIA

GAS UTILIZATION PROJECT

PGN's Progress Reporting Requirements

1. The following information is required to be reported from time totime in relation to the progress of work on the project and to the operationsof PGN.

2. During the construction of the project qu,:terly reports covering:

(a) technical progress;

(b) cost estimates, expenditures and disbursements; and

(c) management and operations

should be delivered to the Bank not later than 30 days after the end of eachcalendar quarter.

3. In addition, annual reports on thi fulfillment of certain agreementscontained in the loan documents and on the financial situation and prospectsof PGN shall be submitted to arrive in Washington not later than three monthsafter the end of the fiscal year.

4. Finally, PGN will be required to send, not later than three monthsafter the project completion date, a Completion Report summarizing theexperience with the project and the lessons learned.

5. The following describes the reports in question:

I. Quarterly Technical Progress Reports

6. The report should cover the following events:

(a) physical work accomplished during the reporting period;

(b) a comparison between the planned and actual progress ofconstruction;

(c) changes, events or conditions which would materially delaythe construction of the project or increase its cost andthe Borrower's proposed remedies, if any;

(d) changeR in key personnel;

(e) expected completion date.

-78- Annex 5.04Page 2 of 4

7. Such progress report shall concentrate on the main physicalcomponents of the project, broken down as follows:

1. gas pipelines2. pressure regulating stations3. conversion4. customer meter stations

Progress of construction should be covered in the text of the report andshown graphically in charts.

II. Construction Schedule

8. A chart showing planned and actual progress on each of theprincipal events referred to above shall be presented.

9. Simplified CPM or PERT diagrams car. be presented with the chart togive a comprehensive picture of the schedule.

III. Schedule of Orders and Deliveries

10. A schedule of orders and deliveries for major items of equipmentshall be presented in the following form:

Description of itemDate of bid invitationDate of orderName and address of supplierContract amountDelivery Dates

OriginalRevisedActual

11. The schedule shall list major items for which orders have beenplaced or bid invitations issued, and those for which bid invitations arescheduled to be issted in the next quarter. The amount in the currency ofthe contract shall be shown and its equivalent in US$ to be roundedto the nearest 4.J1000 equivalent.

IV. Quarterly Report on Cost Estimate, Expenditure and Commitments Statement

12. The report consists of one table, which should be submitted with,and cover the same period as the technical progress report. The figures oforiginal estimated costs should be those used in the corresponding tablessubmitted to the Bank.

13. The table should show any substantial changes in the cost estimatesthat have become necessary since the previous report. The reasons for suchchanges should be explained in the text of the report. Estimates should bereviewed and if necessary revised from time to time. Such revisions may benecessary after important contracts have been awarded.

-79- Annex 5.04Page J of 4

14. The table shall include the following:

(a) Foreign Costs

- Original estimate (1)- Revised estimate (2)- DisbursementsPrevious (3)This quarter (4)Total (5) - (3+4)

- Balance of outstanding commitments (6)- Total (7) - (5+6)- Remaining costs to complete project (8) - (2-7)

(b) Local CostsSame as in (A) above.

V. Quarterly Report on Management and Operations

15. This snould be a narrative report, supplemented by graphs orschedules if necessary. The subjects which should be included are:

(a) changes in key personnel;

(b) changes in organization of PGN;

(c) arrangements for financing project including overruns;

(d) development of training program for PGN staff and itsimplication; and

(e) any significant problems or development in PGN's generaloperations.

VI. Project Completic. Report

16. The project completion report is a comprehensive review of theextent to which expectations and objectives at the time the loan was madehave been, or show promise of being achieved. For each major projectcomponent the original cost estimate and construction time should becompared with the actual result, with comments on the reasons for the majordeviations. Non-physical objectives, such as the installation of newaccounting systems, etc., should also be reviewed and the degree ofaccomplishment described, with an analysis of the reasons for any delays orlack of success.

17. The report should also cover whenever appropriate:

(a) the major problems (physical, financial, management, etc.)which have arisen, why they arose, and what was done to solvethem or minimize their effects-

-80- Annex 5.04Page 4 of 4

(b) the performance of consultants and contractors;

(c) any unusual features of procurement or disbursemer.t;

(d) any unusual procedures of the Bank which gave rise toproblems;

(e) staffing and training aspects of the project;

(f) any deviation from the original financing plan and reasons;

(g) any problems or changes of an environmental or sociological;

(h) the financial results of operations during the projectexecution (sales, operating expenses, operating income, etc.)and the actual financial position and prospects of thecompany; and

(i) any actions which need to be taken in order to maximize thebenefits from the projects (associated investments, furthertechnical training or advisory services, etc.).

18. In brief, the report should review the appraisal of the project inthe light of events to date in order to determine if the original basicassumptions and judgements have turned out to be substantially correct.

-81- Annex 6.01Page 1 of 3

INDONESIA

GAS DISTRIBUTION PROJECT

Notes and Assumptions on Financial Statements

1. The financial projections are based on:

(a) Financial Statements for FYs85-88 as prepared by PGN andaudited by the State Board of Audits;

(b) Unaudited Statements for FY89 and provisional statements

(c) PGN's FY91 budget;

(d) PGN's long-term plan for FY92-97; and

(e) Current financial policies, amended for fut4re changes plannedby GOI and PGN.

2. The financial projections are expressed in current Rp, assuming anaverage inflation in 1991-97 of about 6X for domestic costs and about 42for foreign costs and a constant exchange rate of Rp 1750/US$,

Income Statement

3. Revenue projections assume an average gas sales price of about Rp5,500/MCF as from FY92, a PGN margin on sales of about Rp 2,000/MCF andsales volumes according to PGN's survey with minor modification by Bankstaff.

4. The currently discounted gas price of Rs 3,100/MCF is expected tobe increased and as from FY92 gas is assumed to be purchased from Pertaminaat RP 3,500/MCF.

5. Gas losses are expected to decrease substantially from currentlevel of 62 once new distribution systems are put into operation and areexpected to be about 2Z of total sales by the end of project period. LPGschemes are assumed to replace manufactured gas and gas manufacturingplants closed.

6. Administrative costs (mostly salaries and wages) are expected toincrease by 102 per annum as from FY92; about 62 due to general inflationand 42 due to real term increases and new staff.

7. Distribution costs are expected to increase by 152 per annum asfrom FY91; 62 due to inflation and 9Z in real terms due to increasedvolumes of gas distributed.

-82- Annex 6.01Page 2 of 3

8. Depreciation charges have been calculated at a rate of 10 perannum on year end net fixed assets in operation (declining balance method)according to currently prescribed procedures.

9. Interest has been calculated at 122 per annum of PGN's averageoutstanding debt for the first World Bank loan, 13Z for the proposed secondloan and other new funds and 61 for existing commercial loans (EXIM) inline with the subsidiary loan agreements.

10. PGN's surplus funds are expected to be held in time depositsRccording to current practice. As from FY92, no net retu.n has beenconsidered on these funds; the heading "interest received end others'includes pension payments, which should roughly equal the interest receivedfrom time deposits over the project period.

11. Income tax is calculated at a rate of 15Z for net income up to Rp10 million; 251 for net income between Rp 10 to 50 million; and 352 for netincome over Rp 50 million according to the Income Tax Law of 1984. Forprojection purposes, 35Z of net income before tax has been used. Underrecent Indonesia tax laws, tax losses cannot be carried over to subsequentyears.

12. Social fund contributions have been calculated at 20? of after taxincome according to PGN's statute; the social fund is carried by PGN as aliability and balanced by other assets.

13. Development fund (DPS) payment from PGN to GOI is treated as anappropriation of after-tax net income in accordance with PGN's statutes. Arate of 55? of after tax income has been used.

Balance Sheets and Sources and Applications Statements

14. Work in progress is assumed to equal capital expenditures for theyear.

15. Cash an' bank deposits are assumed to equal about Rp 10 billion,increasing at 62 per annum.

16, Accounts receivable are assumed to equal about 6.5Z of billing forthe year; other current assets and miscellaneous assets bave been assumedto increase at 6Z per annum.

17. Inventories are assumed to increase ac from FY92, in line with theincrease of fixed assets.

18. Existing long-term debt consists of IBRD and EXIM Bank (Japan)loans for the ongoing project. New debt as from FY92 is mainly from theBank for the proposed project. The repayment of existing long-term debt toEXII bank and World Bank starts in FY92.

19. Current liabilities exclude the current portion of long-term debt,which has been included under long-term debt.

-83- Annex 6.01Page 3 of 3

20. GOI has agreed to provide a major part of the EXIM Bank funds toPGN as equity contribution up to FY91; however, it is assumed that no newgovernment equity contribution will be made as from FY92 for the proposedproject.

21. The revaluation reserve remains constant throughout the project.Asset revaluations for the monitoring of the Bank's ROR covenant will notbe recorded in PGN's books.

22. Customer deposit remain roughly constant over the rroject life.

23. Accounts payable and miscellaneous liabilities increase in linewith inflation at 6Z p.a. over the project period.

25. PGN fixed assets in operation have for ROR calculation purposesbeen revalued up to FY97 according to the Bank's MWV index in dollarsterms, for imported assets, and with 6Z p.a. for local cost assets.

GAS UTIL:ZATIrN PROJsT

P28 I6CaE STAT8EWT FOR m 1986-1007 (Rp MILLION)

FP ending March 31: 1066 1987 1068 1980 lo0 1991 1002 1003 1994 1005 1006 1007

(AIDTED) (ALOITED) (A10TED) (tNADITED) (PROVYISIONL)(9CET) --------------- FAECASTT----------------------------------------

Coo Soles 17.528 24,10 31S,989 41,060 s7.30 70,028 104.800 134,000 165,000 221S300 256.300 326,200

Pipe & Meter Rontn 1,850 1,766 :,236 3,720 3,420 4,785 5.000 11,800 12,400 13,000 13.700 14,400

Total 4" Sales 16,807 2s.956 34,225 44,789 61.250 74,783 109.000 145.800 177,400 234.300 270.000 340,600

Coet Of a" Sold I0,761 14.419 22.147 30,854 36.564 42,861 66,700 85,200 105,000 140.800 163,100 207.600

a" Lost 2.706 2.907 2,928 2.098 2,194 2,052 2.000 1.700 2,100 2.800 3.200 4.200

Ore Margin On Ca. 5,810 6,540 9,10 11.237 22,501 S 0.170 41,100 88,000 70,800 90,700 103.700 1218.00

Soles t by Product. 108 188 200 16S 140 0 125 125 125 125 125 125

Ine telletlons 114 186 00 91 103 335 75 78 75 75 75 75

TtAl Oth,r Opereting Income 307 a36 200 254 342 335 200 200 200 200 200 200

Adaini-tration 2,286 2,80CC 4,742 4,079 9,935 11.363 12,500 13,700 15,100 le6.00 18,300 20,100

Distribution 1,551 2,162 1.914 2,025 6,188 7,169 3.100 SA500 4,100 4,700 5,400 6,200 ODoepr.ciation 1,680 3.268 2.793 2.887 3.204 3,869 6,s3 16.100 25,000 22,100 21.500 21.600 4O

Total Opeleting Coat 5.467 0,220 9.449 0,801 10.417 22.401 25,900 33,300 42,200 43a400 45,200 4'.900

Bpirating Incoe I10 647 0 1,600 3,426 8,104 17.400 25,800 28.300 47,800 o 8.7oo 81,100

Interoat Received £ eth*..... 7,942 0 577 900 925 806 2.000 2,000 2.000 3.s00 5,000 7.000

Inter-t, Charged To Income 0 (729) 0 0 0 0 8,300 8,000 6.00o 0 18.0c 19,700 24,200

Income SBfore Tax 8,072 (02) 577 2,580 4,351 8.970 14,100 19.800 23.400 34,100 44,00O 63,900

Income Tom (2.406) 0 0 (410) (974) (2.563) (4.900) (6,000) (8,200) ( 11.00) (15.400) (22,400)

loS Income After Teo 5.664 (82) 577 1,170 3,377 6,407 9,200 12.900 15.200 22, l0 28,600 41,500

Aepropriation,

OPS 0 0 (1.001) (317) (3,218) (1,857) (5.100) (7.100) (8,400) (12.200) (15.700) (22,800)

Sociel Fund 0 0 0 0 (1.170) (675) (1,800) (2,600) (3,000) (4,400) (5,700) (8,300)

Rmtained Earning A Rtea.r. 5.604 (82) (1.324) 1.653 (1.011) 3.875 2,300 3.200 3,800 5.000 7.200 10.400 D

Gas Sale (Million cu.-) 10 137 11 251 305 3s0 540 600 050 1,140 1.320 1,680 O

RaNt Baa, (a) At Cost 26.374 37.031 37,040 48,714 5S3.514 65,730 95.100 150,700 217,700 245.500 238,200 23s,300

(b) On Revalued Oasis 61.300 62.400 72,300 02,500 03,100 110.800 147,000 180,500 282,400 324.400 338.700 352.800

Ratios:

RIR eons8" (b)(S) -8.8 1.7 0 0 2 4 4.6 84 13.1 12.5 9 2 14 s 1s 2 24 0

ROR on Bee (b)(S) -3.7 1.0 0 0 1 4 2.6 5 0 8 5 9.5 7.1 11 0 12 8 16.6

GAS OTILIZATItO POJECTPIN'S lIAA11E SHEET FOR FYS 1986-1997 (Rp HILLION)FT eudia; Iatcb 31: 19B6 1987 1988 1989 199 1991 1992 1993 1994 1995 1996 1997

(WIODTEN) (AUDITED) (AUDITEOD) (OUIDITED) (PROVISIOMAL) INIET - ----- - -FOECES T---------------------------------------WETS --------- --------- --------- ~-- ----------- - --------~~ --------- --------- --------- --------- --------- ---------~~~~~

Laud 18,922 18,736 19,507 20,053 20,188 20,512 18,500 18,500 18,500 18,500 18,500 19,500Other Fiied Assets 31,670 33,983 41,160 47,693 56,259 78,827 128,900 216,400 302,000 317,000 331,000 354,400Les: s, .lepreciatioe (7,9921 (11,257) (14,049) (16,936) (20,22V) (24,098) (32,400) (48,500) (71,500) (93,600) (115,100) (136,700)

-- -- -- - -- -- -- -- --- -- -- -- --- -- -- -- --- -- -- ----- -- -- -- --- -- -- -- --- -- -- -- --- -- -- -- --- -- -- -- --- -- -- ----- -- -- -- --

*t Filed Assets 42,600 41,462 46,618 50,810 56,218 75,241 114,900 186,400 249,000 241,900 234,400 236,200fork ia Progress 517 2,451 4,153 31,117 34,973 50,055 87,500 85,600 15,000 14,000 23,400 24,500

Total Fiied Assets 43,117 43,913 50,771 81,927 91,191 125,296 202,400 272,400 264,000 255,900 257,800 260,700Casb A lank 2,965 3,617 8,686 9,445 11,604 17,989 12,000 12,700 13,500 14,300 15,100 16,100Accounts receivable,Net 3,614 3,578 4,001 5,435 3,745 2,100 6,800 8,700 10,700 14,300 16,600 21,100Prepaymeots 158 46 377 627 906 1,304 600 600 700 700 800 800Inventories 5,673 5,833 3,602 3,098 3,763 6,177 8,100 13,000 17,400 16,90\0 16,900 16,900Other Carrent Assets 961 614 969 514 486 677 700 800 800 900 900 1,000

- - - - .^- - -- -- ----- -- -- -- --- -- -- -- --- -- -- ----- -- -- -- --- -- -- ----- -- -- -- --- -- -- -- --- -- -- ----- -- -- ---- -- -- -- - --

lotal Correot assets 13,371 13,688 17,635 19,109 20,504 28,247 28,200 35,900 43,100 47,100 50,300 55,900 U

Tise Deposits 8,016 8,966 6,483 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000Niscellanenus 19 0 19,357 11,222 34,293 36,780 36,800 23,700 41,100 69,200 76,200 62,500

--- - -- - -- --- - -------- - -- - ----- --- -- - ---- ------- -- --- - -------- - -------- - - ---- --- --- - -- -- -- --

Totil Other assets 8,035 8,966 25,840 21,222 44,293 46,780 46,800 33,700 51,100 79,200 86,200 72,500- ----- -- ------ -- ------ -- ------ ------- -- ----- -- ----- -- ------ -- ------ ------- ------- -- -----

TOTAL ASSETS 64,523 66,567 94,246 122,259 155,9fl 200,323 277,400 341,500 358,200 382,200 394,306 389,100

LIABILITIES

Gov.Equity Contribution 7,451 9,894 12,015 25,544 29,125 53,605 53,600 53,600 53,600 53.600 53,600 53,600Retaited Earingq A Reserves 6,476 6,394 5,071 6,923 5,912 9,787 12,100 15,300 l9,100 24,700 31,900 42,300Revalantion Reserve 44,450 44,450 44,450 44,450 44,450 44,450 44,500 44,500 44,500 44,500 44,500 14,500

- - - -t- - -- -- -- -- --- -- -- -- --- -- -- -- --- -- -- ----- -- -- -- --- -- -- -- --- -- -- -- --- -- -- -- --- -- -- ----- -- -- -- --- -- -- -- ---

lotal Equity 58,377 60,738 61,536 76,917 79,487 107,842 110,200 113,400 117,200 122,800 130,C00 140,400Social Food 0 0 0 0 1,170 1,845 3,600 6,200 9,200 13,600 19,700 27,600Loin Term Debt 6,489 28,887 39,790 78,038 150,900 208,500 217,600 230,800 227,100 204,300Accounts Payable 2,113 4,874 3,985 5,326 5,426 5,426 5,800 6,200 6,600 6,900 7,400 7,800listellameoms 3,633 525 3,595 2,827 5,897 6,720 6,400 6,700 7,100 7,600 8,000 8,500

Total Carrent Liabilities 5,746 5,399 7,580 8,153 11,323 12,146 12,200 12,900 13,700 14,500 15,400 16,300Castoser kposit A Others 400 430 18,641 8,301 24,210 452 500 500 500 500 500 500

TOTAL LIARILITIES 64,523 66,567 94,246 122,258 155,908 200,323 277,400 341,500 358,200 382,200 394,300 389,100 o

latios: Crrent Ratio (Times) 2.3 2.5 2.3 2.3 1.8 2.3 2.3 2.8 3.1 3.2 3.3 3.4lebt/Equity Ratio 0/100 0/100 10/90 28172 33/67 42/158 58142 65/35 65135 65135 64/34 59/41

INDCNESIA

GAS UTILIZATION OJECT

PON'S SCRCQ APES FilRS 1986-1997 (Rp. i II ion)

Ft nding March 31: 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 :99 1997(AUDITED) (AUDrTE0) (AWITED) (UNALAITED) (PROVISIONAL) (8WGCET) ------------ FS T----------------------------------------

S 0 U R C E S

- Operateng Income 180 647 0 1,800 3,426 8.104 17,400 25,600 23,300 47,500 58,700 81.000- Depreciation 1,680 3.26b 2,793 2,887 3.294 3,689 8.300 16,100 23,000 22.100 21,500 21.600

- Internal Cash Oeneroticn 1.7b0 3.912 2,793 4,487 6,720 121,973 25.700 41.900 51.300 69.600 80,200 102,600

- Interest Reci.'ed a Others 7,942 0 677 980 925 866 2,000 2,000 2.000 3.500 5.000 7.000- Ooverent Contribution (DIP) 4,e68 2.443 2,121 13,529 3,581 24,480 0 0 0 0 0 0- Increase L.T Debt 0 0 6.489 22.398 10,911 36.240 82,800 70,500 22,000 26.100 4.400 0- Adjustents 0 0 0 0 (1) 0 1,900 s/ (100) 0 0 0 0

- Total Sourcs 14, 590 6.355 11,980 41.394 22,136 75,559 112,400 114,300 75,300 99,200 89,600 109,600

REQUIREMENTS:

00- Proposed Project 0 0 0 0 0 0 67,300 65,600 15.000 14,000 .3,400 0 i- Other Inveetment 5,066 4,061 9,680 84,044 12,SS7 37.974 20,000 0 0 0 10,000 24,500

- Total Capital tnveatasnt 5,066 4,061 9,650 34,044 12,S87 37,974 67,300 65,600 15,000 14,000 23,400 24,500

- Intrst Charged to Income 0 729 0 0 0 0 5,300 8,000 6,900 16,900 19,700 24,200- Amortization 0 0 0 0 0 0 9,900 12,9C0 12.900 12,900 6.10D 24,700

- Total Debt Services 0 729 0 0 0 0 15,200 20,900 19,800 29,800 25.800 48,900

- To 2,408 0 0 410 974 2,563 4,900 6,900 8,200 11,900 15.400 22,400- Che in working Capital 7,185 664 1,766 901 (1,778) 6,920 (100) 6,900 6,500 3,200 2,300 4,700- Chnge in Other Aasets (62) 981 16,674 (4.618) 23,071 2,487 0 (13.100) 17,400 28.100 7,000 (13,700)- Chnge in Other L;bilities (7) (30) (18,211) 10,340 (15,909) 23,756 0 0 0 0 0 0- CPS Cootrobutione 0 0 1,901 317 3,218 1,687 5,100 7,100 8,400 12,200 15,700 22,800

- Total Requirent 14.590 6,388 11,960 41,394 22,138 75,559 112,400 114,300 75,300 99,200 89,600 106,860 r

Debt Serv,;, Covarag (Times) - 5.4 - - - - 1.7 2.0 2 6 2 3 3 1 2 1

af Sa1l of land not needed for opsr-taonal purposee.

r U

-87- Annex 6.05

INDONESIA

Gas Utilization Project

Efficiency Improvement Program for PGN

1. To achieve its financial objectives at current margins between gassales prices and gas cost, PGN would have to further improve its efficiencyunder the proposed project. For this purpose, the following efficiencyimprovement program was identified:

(a) closure of obsolete gas manufacturing plants and replacementby LPG or natural gas distribution according to the followingschedule:

Bandung 1994Semarang 1993Surabaya 1993U. Pandang 1990

(b) increase in the volume of gas sold from the FY90 level ofabout 300 million cu.m. to 1,600 million cu.m. in FY97;

(c) reduction of gas losses from FY90 level of about 7Z to 2% inFY94;

(d) limit the increase in PGN's staff to 20% of current 1,200employees during the project period; and

(e) implement a staff training program not later than by December31, 1991.

2. For the monitoring of this efficiency improvement program, thefollowing performance indicators have been established:

1990 1991 1m 1993 1994 1996 1998 1997

Gas Sales (million cu.m.) 305 360 640 890 8so 1,140 1,320 1,680Gas Losses (X) 7 4 a 2 2 2 2 2No. of Staff 1,200 1,300 1,380 1,400 1,420 1,430 1,440 1440Rate of Return on

Revalued Assets (1) 2.6 4.0 6.0 6.0 8.0 10.0 10.0 10.0

DONESIA

GAS UWILZATINi PROJECTDCOE STATBe.! OF HED FtlR FYS 1986-1997 (Rp MILLION)

FY ending brch 31: 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 t(AUDITED) (AUDITED) (AUtMTED) (UND4AITED) (PROVISIONAL) (8lU) ----- FCST ---------------

Ca, Sales 787 2.324 4.467 6,838 10.193 11.605 12,000 26,000 26,100 26,100 26,100 26.100Pipe A Mtor Ronto 82 1.249 1.9 * 3,563 3,428 4.755 5,000 11,800 12,400 13.000 13,000 13.000T4tal Ga. S lo- 1.610 8.678 6.38* 10,401 13,621 16,360 17,000 37.800 38,500 39,100 39.lU0 39.100

Cost Of Gag Sold 542 1.769 3.806 5,724 7,662 8.126 8,600 17.600 18.000 18.000 18,000 18.000as Last 37 3 10 162 206 229 300 300 400 400 400 400

:'es Margin On Use 1.031 1.601 2.569 4,515 5,553 a. 8.100 19.900 20.100 20.700 20.700 20.700

By Products 0 0 0 1 0 0 0 0 C 0 0 0Instllmtions 10 32 4 11 1S 35 100 0 0 0 0 0Total Other Income/ 10 32 4 12 18 35 100 0 0 0 0 0

Administration 133 165 539 6W5 499 551 600 700 700 800 900 1.000

ODitribution 95 124 216 265 961 1.131 1,200 1.300 1.300 1,400 1,500 1.600 CODepreciation 54 639 516 497 811 823 1,100 6.200 9.600 8,600 7,800 7.000 OTotal Operating Cost 282 828 1.271 1,447 2,271 2.505 2,900 8,200 11.600 10.800 10.200 9.600 1

Operating Incmeo 759 1.005 1,302 3.a,o 3,300 5.535 5,200 11.700 8.5C0 9,900 10,S 11.100

Interst Receivd A Others 0 0 0 39 57 21 0 0 0 0 0 0Intereet Paid 0 0 0 0 0 0 (2.000) (2.000) (2.000) (3.000) (4.000) (4.000)Income Before Tom 759 1,005 1.302 3,119 3.357 5,556 3,200 9.700 6500 6,900 6,500 7.100Income Ta: 0 0 0 100 a/ 200 a1 600 a/ 1.100 3S400 2.300 2.400 2,300 2.500Incaee Aftr Tax 759 1.005 1.302 3,019 3,157 4.956 2.100 6.300 4,200 4,500 4.200 4,600

Appropriation:________________

OPS 0 0 0 0 a/ S0 */ 300 */ 1,200 3,500 2.300 2.500 2,300 2,500

*/ Estimated Madan ahdro, considering that other PON areas produce loses and thereby reduce tes payment and OPS.

all

0

DCmNEIA l

GAS UTILIZATION FROJ=TDiE STATBET OF StlAAVA lFO F'S 16-1997 (Rp MILLION)

FY ending March S1: 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997(AuDITWD) (AUDATD) (DWITD) (lMMITD) (PROVISIONAL) (5DGCU) ------------------ FD ASTT----------------------------------------

n-e Soles 1,295 1,319 1.198 1,581 2.046 1,840 1,900 2.000 20,100 64.200 86,400 112.400Pipe A toe Rents 247 224 101 35 0 0 0 0 0 0 0 0Total Ons Sole. 1.642 1.643 1,29 1.616 2.048 1.840 1.9C0 2,000 20.100 64,200 86,400 112,400

Cost Of Gas Sold 1,421 1,399 1.334 1.817 1,686 1.653 1,600 1,700 12,800 40,600 SS000 71,500ta Lost 185 148 198 208 81 4S 0 0 300 S0 1,100 1,400

Oross Margin On G(64) (4) (233) 404 281 242 300 300 7,000 22,600 30,300 39.5C0

By Product' 46 14 75 27 77 0 0 0 0 0 0 0Installations 14 47 3S 4 5 0 0 0 0 0 0 0Toal Other Income/Nt 60 121 110 31 82 0 0 0 0 0 0 0

Administration 210 256 326 420 409 430 S00 600 6S0 700 700 80ODistribution 275 316 349 464 1,112 1.097 1,200 400 1,600 1,800 2.100 2,400 20Depreciation 96 121 110 107 204 2*9 600 4,800 11.500 11,300 11,300 11.100 0Total Operating Cost S'l 693 784 991 1,725 1.766 2,200 6.800 13,700 13,800 14.100 14,300 t

Operating Inome (885) (876) (907) (1,364) (1,362) (1,524) (1,900) (6.300) (6,700) 8,600 16.200 25,200

Interest Received A Othera 39 1I5 93 149 235 812 0 0 0 0 0 0Interest Pa;d 0 0 0 0 (2,000) (5,000) (10.000) (15.000)Incom Before Tax (546) (441) (814) (1.215) (1.127) (1.012) (1.900) (6.S00) (8,700) 3.300 6.200 10.200Incom Tom 0 0 0 0 0 0 0 0 0 (1,100) (2.200) (3.600)Income After Tax (846) (441) (814) (1.215) (1,127) (1,012) (1,900) (6,500) (8.700) 2,200 4,000 6,600

Approriation:

WPS 0 0 0 0 0 0 0 0 0 (1,200) (2.200) (3,600)

0m0

Annex 6.08Page 1 of 2

INDONESIA

GAS UTILIZATION PROJECT

Financial Internal Rate of Return (IRR)

1. The financial IRR calculations are based on the followingassumptions:

(a) the capital expenditures include taxes, duties and estimatedcontingencies, but exclude technical assistance and other minorproject costs not related to gas utilization in Surabaya andMedan;

(b) the capital investments are expected to have a 20-year usefullife and no residual values have been taken into account afterthat period;

(c) incremental operating costs, mostly gas losses, have beenestimated at 2.5? of total gas purchases;

(d) all projected income taxes for PGN's Surabaya and Medanoperations have been considered incremental to the project;

(e) revenues are based on a carrying cl.arge of $0.23/mcf for 48MMCFD in Medan for gas transported by PGN to Pertamina customers(mainly PLN); PGN's current margins on sales to its owncustomers have been assumed to equal $1.14 throughout theprojection period;

(f) only gas volumes that will be distributed due to projectinvestments have been considered; future benefits from increasedgas d.stribution through low, marginal investments incompression have been ignored; and

(g) resulting IRRs have been reduced by a factor of 1.06 p.a. toreflect a projected constant inflation rate of 62 in Indonesiaas from FY92.

2. Based on the above assumptions, the following cash flows wereprojected in US dollar millions:

Annex 6.08-91- Page 2 of 2

Financial IRR - Suraoaya

Operating Income Net Gas NetFY Investment Cost Tax Revenues Cash Flow

1992 26.2 - - - (16.6)1993 26.5 - - - (_1.2)

1994 13.6 0.2 - 4.2 0.3

1995 9.4 0.6 0.6 12.5 7.81996 4.5 0.8 1.3 16.7 11.31997 - 1.0 2.1 23.4 20.3

1998 - 1.3 2.3 29.2 25.61999 - 1.4 2.4 31.3 27.52000 - 1.5 2.4 32.7 28.8

2001-11 - 1.6 2.5 35.0 30.9

IRR = 16.3Z

Financia) IKR - Medan

Operating Income Net Gas NetFY Investment Cost Tax Revenues Cash Flow

1992 7.0 - - - (4.0)

1993 - 0.1 1.3 2.9 (1.5)

1994 - 0.1 1.3 2.9 1.5

1995-2001 - 0.1 1.3 2.9 1.5

IRR = 14.0Z

IRR Z3. Sensitivity analysis: Surabaya Medan

(a) Capital Expenditures + 10Z 14.7 12.0(b) Operating Cost + 10Z 16.2 13.9(c) Revenues - 10X 14.2 9.7

(d) Combination of (a),(b), and (c) 12.6 7.9

-92- Annex 7.01

INDONESIA

GAS DISTRIBUTION PROJECT

Assumptions Underlying Economic Analysis

COSTS

Capital Costs: Project cost estimates, net of duties and taxes, withoutprice contingencies but including physical contingencies. Shadow pricefactors applied on local costs are 0.8 for materials, 0.65 for unskilledlabor, and 1.0 for skilled labor.Conversion Costs: $10 million for Surabaya and $1 million for Medan.System O&M Costs: Taken at 2.5 z of annual cost of gas supply.Cost of Gas Supply: Long-run marginal cost of natural gas estimated at$1.50/mcf.

BENEFITS

Volume of Fuel Replaced: Based on market surveys of potential industrialgas demand in PGN's proposed service areas in Surabaya and Medan, thefollowing profile of existing energy use for substitution by natural gas isassumed:Fuel Surabaya Medan Conversion Rate a/

(Z) (Z) (kcal/liter)

Industrial Diesel 43 58 9270High Speed Diesel 20 20 9063Fuel Oil 18 1 9766Kerosene 10 12 8840LPG 6 9 11220 per kgOthers 3 nilNatural Gas 8790 per cu.m.

Total 100 100

a/ Unadjusted for changes in combustion efficiency due to conversion.

Value of Fuel Replaced: Border prices of petroleum products to be replacedwere applied, as shown Annex 7.03

Value of PLN Sales: The benefit due to gas deliveries to PLN is taken tobe the value of transporting the gas through PGN's pipelines,i.e., $0.23per mcf in Medan.

Industrial 0 & M Savings: It is assumed that medium-sized industries willsave 5 Z in fuel value due to higher thermal efficiency. Benefits due tolower fuel handling and storage expense as well as reduced urban pollutionwere not quantified.

Annex 7.02-93- Page 1 cf 2

INDONESIA

GAS UTILIZATION PROJECT

ECONOMIC ANALYSIS - INTERNAL RAgE 2FRN. BY PJECT CENF(In LIS$ Thousand)

IFnA

Gas Sales (in mmefd) Gas Sales MarginConversion Operating Total Net

Year Total Costs Costs Costs PLN Industry Total PLN Industry Total Benefits

1991/92 5872 0 0 5872 0 0 0 0 0 0 -58721992/93 102 102 18 7 25 1511 7665 9176 90741993/94 102 102 18 7 25 1511 7665 9176 90741994/95 102 Ud2 18 7 25 1511 7665 9176 90741995/96 102 102 18 7 25 1511 7665 9176 90741996/97 102 102 18 7 25 1511 7665 9176 90741997/98 102 102 18 7 25 1511 7665 9176 9074until 102 102 18 7 25 1511 7665 9176 90742009/11 102 102 18 7 25 1511 7665 9176 9074

EIMR - 154.5X

S1JMAAYA

Gas Sales ,'n IACFO) 5as Sales MarginConverslon Operating Total Net

Year Total Costs Costs Costs PLN lrdustry Leoes Total PLN Indcstry Leces Total Benefits

1991/92 21176 0 0 21176 0 0 0 0 0 0 0 0 -211761992/93 21264 3000 0 24264 0 0 0 0 0 0 0 0 -242641993/94 10940 3200 146 14286 0 5 5 10 0 5110 4563 9673 -46131994/95 7356 1800 467 9623 0 12 20 32 0 12264 18250 30514 208911995/96 3580 1000 628 5208 0 23 20 43 0 23506 18250 41756 365481996/97 1000 818 1818 0 36 20 5$ 0 36792 18250 55042 532241997/98 1022 1022 0 50 20 70 0 51100 18250 69350 683281998/99 1095 1095 0 55 20 75 0 56210 18250 74460 733651999/00 1168 1168 0 60 20 80 0 61320 18250 79570 784022001/02 1226 1226 0 64 20 84 0 65408 18250 83658 824322002/03 1270 1270 0 67 20 87 0 68474 18250 86724 854542003/11 1314 1314 0 70 20 90 0 71540 18250 89790 88476

EIRR 50.7X--------------- ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

Annex 7.02-94- Page 2 of 2

INDONESIA

GAS UTILIZATION PROJECT

ECONOIIC ANALYSIS - INTERNAL RATW OF RETURN CALCULATIONS

I(0AN AND S9RASAYA GMI8INED(In LIS$ Thasand)

Project Investment Gas Sales (in mcfd) Gas Sales Margin------------------- Conversion Operating Total ---- -- Net

Year Forex Local Total Costs Costs Costs PLN Inrdstry Lecus Total PLN indastry Leces Total Bensefits

1991/92 24696 2352 27048 0 0 27048 0 0 0 0 0 0 0 0 -270481992/93 21000 264 21264 3000 102 24366 18 7 0 25 1511 7665 0 9176 -151901993/94 10500 440 10940 3200 248 14388 18 12 5 35 1511 12775 4563 18849 44611994/95 6300 1056 7356 1800 569 9725 18 19 20 57 1511 19929 18250 39890 299651995/96 3360 220 3580 1000 730 5310 18 30 20 68 15'1 31171 18250 50932 458221996/97 0 0 0 0 920 920 18 43 20 81 1511 44457 18250 64218 632981997/98 0 0 0 0 1124 1124 18 57 20 95 1511 58765 18250 78526 774021999/00 0 0 0 0 11i97 1197 18 62 20 100 1511 63875 18250 83636 824392001/02 0 0 0 0 1270 1270 18 67 20 105 1511 68985 18250 88748 874762002/03 0 0 0 0 1329 1329 18 71 20 109 1511 73073 18250 92834 915052003/04 0 0 0 0 1372 1372 18 74 20 112 1511 76139 18250 95900 945282005/11 0 0 0 0 1416 1416 18 77 20 115 1511 79205 18250 98966 97550

EIRR 58.9%-- -- - -- -- -- -- _-=

Annex 7.03

INDONESIA

GAS UTILIZATION PROJECT

Domestic and International Prices of Petroleum Products

Ratio ofShare of International Domestic Domestic

Category Consumption a/ Parity Price b/ Price 1989 to World Price(Z) (Rp/liter) (Rp/liter) (Z)

Aviation Turbo 2.6 270 250 0.92Gasoline Premium 0.9 296 440 1.49Gasoline Regular 18.2 278 385 1.38Kerosene 27 2 286 165 0.58Automotive Diesel 33.9 290 200 0.69Industrial Deisel 5.2 270 200 0.74Fuel Oil 11.9 195 200 1.02

/ 1987 data.

b/ Based on estimated average price of Indonesian Crude at US$ 18.00 perbarrel, converted at 159 liters per barrel Uses average price relatives ofpetroleum products in the Singapore spot market for the period May 1986 to May1989 plus transport and distribution costs.

Source: Bank estimates

Annex 7.04

INDONESIA

GAS UTILIZATION PROJECT

Economic Rate of Return Calculations Based on Least Cost Alternative

Economic Rate of Return (2)

Medan Surabaya Total Project

Assumes 10OZ of GasSales will Replace Fuel Oil 88 33 38

Market DemandDown 102 79 31 34Down 25% 66 27 30

Price of Competing FuelsDown 102 75 28 32Down 25Z 55 18 21

Project CostsUp 10 80 31 35Up 25% 70 29 32

Carrying ChargeDown 10% 85 33 37Down 25% 82 33 37

INDONESIA

GAS UTILIZATION PROJECT

Fiscal Impact

(Estimates of the FYs 1990-97 Fiscal Benefits of PON's Operations)

PGN Payments to GOI GOI for PGNCustom Income Debt DPS Total PGN DIP Debt Total GOI Pay- Net Fiscal

FY Ending Duties a/ Tax Service Payment F%Yment to GOI Contribution Service ments for PGN0 Impact

1990 1,389 974 0 3,218 6,581 3,581 2,328 5,909 (348)

1991 4,139 2,563 0 1,857 8,559 24,480 3,410 27,890 (19,331)

19m 6,730 4,900 7,000 5,100 25,730 0 6,802 6,602 17,128

1993 4,726 6,900 13,100 7,100 31,825 0 9,880 9,860 21,965f

1994 2,275 8,200 12,400 8,400 31,276 0 13,370 13,370 17,905

1995 1,488 11,900 21,900 12,200 47,488 0 15,085 15,086 32,403

1996f 2 490 15,400 26,800 15,700 69,390 0 18,450 18,450 40,940

1997 2,671 22,400 48,900 22,800 98,771 0 21,557 21,557 76,214

Total 25,886 73,237 129,100 76,375 304,598 28,081 90,662 118,723 105,875

(D

x-a0U'

-98- Annex 8.01

INDONESIA

GAS UTILIZATION PROJECT

List of Documents in Project File

1. Financial Statements of PGN for 1988/89 (unaudited, in Indonesian)

2. Approved Budget of PGN for 1989/90 (in Indonesian)

3. Financial Statements of PGN for 1988/89 (audited, in Indonesian)

4. Financial Statements of PGN for 1937/88 (audited, in Indonesian)

5. Financial Statements of PGN for 1986/87 (audited, in Indonesian)

6. Chart of Accounts of PGN, 1977 (in Indonesian)

7. General Accounting Principles of Indonesia 1974 (in Indonesian)

8. Exposure Draft - Indonesian Accounting Principles 1983 (in English)

9. Regulation of GOI No. 27 of 1984 on Conversion of the State Gas

Company into A Public Corporation: PGN Statute (in both English and

Indonesian)

10. Summary of Financial Report required by PGN Statute (in both English

and Indonesian)

11. Instruction No. I-84.24 about Calculation of Depreciation and

Bookkeeping since 1984 (in both English and Indonesian)

12. Instruction by Board of PGN on Accounting Method (in Indonesian)

13. Regulation No. 3 of 1983 on Procedure of Promoting and Supervising

Departmental Agency, Public Corporation, and Lim.ted Liability State

Corp. (in both English and Indonesian)

14. Current Tariff Schedule of Gas (in Indonesian)

15. Annual Volume of Gas Sales - City by City (in English)

IBRD 21723

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I N D O N E S I A

GAS UTILIZATION PROJECTGAS TRANSMISSION AND DISTRIBUTION SYSTEM

FOQr MEDAN

* GAS FIELDS

G PLN THERMAL POWER STSTION

PROPOSED TRANSMISSION PIPELINE

EXISTING TRANSMISSION PIPELINE

EXISTING PRINCIPAL DISTRIBUTION MAINS

m PRESSURE REGULATING STATIONS

St MEDAN URBAN AREA

+ AROI-1ABY-1

P. Susu

t SCG-1

SUMA TERA P Brandan

UTARA

\~~~~~~X x ~~~~~~Belawan

0 .0 20 30' ' ' - ' ~~~~~Wampu j\

KILOMETERS Paypas

THAILAND PIIIUPPINES MEDANN\Mv A BArUNEI PHILIPPINES g , MA L A YS~IA' PAPUA

& glNGAPORE GUNEWNSulawesi I abn b llS - tf

theraXrs no PVS,-I the tn,a use ofrm Wod ka SCttrntO

Jawa Bi_

Timor

APRIL 1990

MADURA ISL4ND

Cresik

N D O N E S I A

JA WA landes \ GAS UTILIZATION PROJECT1 , N *. \ GAS TRANSMISSION AND DISTRIBUTION SYSTEM

TIM O R RABAYA FOR SU%ABAYA AND ITS ENVIRONSPLN THERMAL PDWER STATION

Karangpilango PROPOSED TRANSMISSION PIFELINES

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