Report No. 10293-IND

IndonesiaSector ReportNatural Gas Development Planning StudyJuly 20, 1992

Industry and Energy Operations DivisionCountry Department IIIEast Asia and Pacific Region

FOR OFFICIAL USE ONLY

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Thisdocument has'a restrictied distribution and may be used by recipients

,*.in m t pedo.mance of thei official duties. Its contents may not otherwisebe,W,tsclosed without World Sank authoization.

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CURRENCY EOUIVALENTS(As of October 1991)

Rp 1000 5 $0.51Rp = Indonesian Rupiah

$ = US Dollar

WEIGHTS AND MEASURES

MMBTU = million British Thermal UnitsMCF thousand standard cubic feetMMCF = million standard cubic feetMMCFD = million standard cubic feet per day

MCM = thousand standard cubic meters

MMCM = million standard cubic meters

BCF = billion standard cubic feet

TCF = trillion cubic feetKi = kiloliterTOE = tons of oil equivalent (in heating valu

BOE = barrels of oil equivalent (in heating value

tpy = ton per year

BBLPD = barrels per day

Kwh = kilowatt hour

MW = megawatt

Km = kilometer

HP = horse power

CONVERSIONS

1 BOE = 5,800 standard cubic feet natural gas

1 TOE = 43,000 standard cubic feet natural gas

1000 BTU = 1 standard cubic foot of natural gas

10000 BOE per day = 58 million standard cubic feet of natur

gas per day

ABBREVIATIONS AND ACRONYMS

AIC Average Incremental CostBAKOREN National Energy Coordinating BoardBAPPENAS National Development Planning Board

CCPP Combined Cycle Power Plant

FY Financial Year

GDP Gross Domestic Product

GOI Government of Indonesia

HSD High Speed Diesel

IDO Industrial Diesel Oil

LNG Liquefied natural gas

LEMIGAS Research and Development Center for Oiland Gas Technology

LPG Liquefied Petroleum Gas

MIGAS Directorate General of Oil and Natural Gas,Ministry of Mines and Energy

PERTAMINA National Oil and Gas Company

PGN State Gas CorporationPLN State Electricity Corporation

PPTMGB Manpower Development CenterPSC Production Sharing ContractPTTBBA Bukit Asam Coal Mining Company

FOR OMCIAL USE ONLY

NATURAL GM DEVELOPMENT PLANING STUDY

TABLE OF OONTENTS

EXECUTIVE SUMMARY .L... . . . . . . . . . . . . . . . . . . . . . . . 1

S. THE ENERGY SECTOR * * . . . * . .. * * * * * .. .. * . 1Introduction ........a...............o............a.........a ..... 1Primary Energy Resources .................... 2Power Sector . .. o . . . . . . .. ........... 4Energy Consumption Patterne ................... 5

II. THE GAS SECTOR . . . . . . . . . . . . . . . . . . . . . . . . . . 7Background ..*.*...... .. . . . . . .. . . . . . . . . . 7rnstLtutional Arrang.mnts ..................................... 8Development of Gas Supply Infrastructuro . . . . . . . . . . . . 9Economic Cost of Gas ........................................... 9

Current Economlc Cost of Alternative Fuels * * * . . * * . . * . 12The Case for Expanded Dometic Use of Gas . .* . * .. a . . 12

III. GAS RESEREPS AND SUPPLY . . . . . . . . . . . . . ... . .. . 15Resources . . . . * . . . . . . . *. * . * * . * . * a . * . . isGas Supply Systems, Present Supplies and Planned Developments . . 17

Future CasLsupplies..................... 19

IV. NATURAL GAS UTILISATON . . . . . . . . . . . . . . . . . . . . . . 25Overvlew . . . . . . . . . . . . . 9 . . . * . . . . . . . a . . 25Power Sector . . & . . . . . . . . e . . . . * . . . . . . . . . 27Industria Ful Use .lUse. a * 0.0 o-*.* .......................... 29Feedstock Applicatlons . . . . . . .a. .. *. * *. .. * * * . . . 30Other Uses . - . . . . a . . . a . . . . . . e . . . . . . . . . 32Concluslon . . . . . . . . . . . . . . . . . . . . . 33

V. POLICY AND INSTITUTIONALZSSSSUES... ....... 35

InstitutLonal Apects . ................. 35

Pricing of Gas for Domestlc Supply . . . . . . . . . . * * . . * 35

Regulatlon . . . . . . . . . . . . . . . . . . . . . . . . . . 37

VI. STRATEGY FOR EXPANDED DOMESTIC USE OF GAS . . . . . . . . . . . . . 39Dom *tlocao Gupplps.Ls ..................... 0 0 ................. 39PrieLng Strategy .*. .9. 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 * * 40Instltutlonal and Regulatory Aspects 9. . . . . . . . . . . . . 40investment Expendltures and Their FLnancing . * . . . . . . . . . 44Medium and Long term Peropectlvso. . . . . . . . .. . . . . . . 45

IThis document has a restricted distribution and may be used by recipients only in the performance |of their offcial duties Its contents may not othorwi o be disclosed without World Bank authorization.|

ANNEXES

1.1 Commercial Energy Balance, 1990; Commercial Energy Balance, 1985;

Net Energy Consumption, 1985 and 1990

1.2 Coal Data and Characteristics

2.1 Pertamina' s Organization Chart

2.2 Levelised Comparative Power Generation Costs; Sensitivity Analysis

of Power Generation Costs

3.1-3.18 Regionwise Reserves, Production, Cost of Development, Gas Supply

Potential and Development Profiles

4.1 Natural Gas Utilization in Domestic Market, Base and High Cases

4.2 Netback Value of Natural Gas in Alternative Uses

4.3 Supply-Consumption Balance (1994-2004), Regionwise

5.1 Summary of Bank's Energy Pricing Review Recommendations dnd

and Present Status of Prices

5.2 Regulation

MAP: IBRD 23458

ACKNOWLEDGEMENTS

This report was prepared jointly by the Bank and the GOl. The Bankmission, which Tisited Indonesia in October 1991, consisted of Salahuddin Khwaja(mission leader), Ralf Dickel, Riaz Khan, Uruj Kirmani and Mihkel Sergo (WorldBank), and William Hollinger, Donald Keith, Vinayak Mahajan, Subodh Mathur, P.T.Venugopal, and Latif Zubair (consultants). The GOX participation was managed bya Steering Committee established by Indonesia's Minister of Mines and Energy.The Steering Committee consisted of:

1. Ir. Suyitno Patmosukismo, Director-General, MIGAS.2. Ir. A.K. Soejoso, President-Director, PGN.3. Ir. E.E. Hantoro, Director, Exploration and Production, Oil and

Natural Gas, MIGAS.4. Dr. Bawaang Purnomo, Head of the Electric Energy and Mining Bureau,

BAPPENAS.5. Dr. Umar Said, Head of tha Planning Bureau, Ministry of Mines and

Energy.6. Dr. Ing. Nengah Sudja, Head of the System Planning Division, PLN.7. Ir. Isworo Suharno, Head of Gas Development Service, Pertamina.

Substantive and fruitful discussions were also held with other seniorenergy-related officials in Indonesia, including Dr. Rustam Didong, DeputyChairman for Economic Affairs, BAPPENAS; Ir. Wijarso, Assistant to the Ministerfor Mines and Energy; Drs. Faisal Abda'oe, President Director, Pertamina; Ir.G.A.S. Nayoan, Director, Exploration and Production, Pertamina; Drs. H.Baharuddin, Director, General Affairs, Pertamina; Ir Kartijoso, Director,Shipping and Telecommunications, Pertamina; Drs. A. G. Suratno, Director of Oiland New Tax Revenue, Ministry of Finance; Ir. Marzuan, Secretary, MIGAS. Inaddition, the mission had extensive discussions with a number of officials fromthe Ministry of Mines and Energy, MIGAS, BAPPENAS, Pertamina, PGN, PLN, Ministryof Finance, Ministry of Industries, PTTBBA, Directorate of Coal, Batam IndustrialDevelopment Authority, British Gas, U.S. Embassy, and international oilcompanies.

The mission also wishes to acknowledge the assistance provided by the AsianDevelopment Bank (a companion study of LNG), LENIGAS (a companion study of theCNG market in Jakarta), PGN and British Gas (analysis of existing and potentiallevels of gas consumption; preliminary designs and estimates of gastransportation infrastructure).

A final draft of this report was discussed with the Government of Indonesiain 1992.

UprCUT!VW SUgmRy

Pur ead Scope of Study

1. The purpose of thli study is to formulate a devolopment strategy for theeconomlcally effLeLent domestLc use of natural gas Ln IndoneiLa. Gas supply andutilizatLon, LNG exports, infrastructure development and lnotltutlonal,regulatory and fLnanclil Lisues have been studied to the extent needed toestabllsh the ratlonale for and feasLbllity of expanded domestLc use of naturalgas.

2. The presentation of the study has been organLiod as follows:

- An executive summary;

- Chapter I gives an overview of the energy sector ln indoneia;

- Chapter II describes the gas sector and dLicusses the economicbeneflts of natural gas in various uses;

- Chapter III discusses the potentlal supply sources of gas and thecosts for field development and transportatLon systems;

- Chapter IV analyzes the- *xlstlng and potential levels of gasconsumption Ln the power, industrial and commrclal sectors and itsmerLts as compared with alternatlve fuels;

- Chapter V examines pollcy, LnstitutLonal and regulatory Lisues andgas prlcing, whlch would have to be addressed for the efficientdevelopment of the domestic gas market; and

- Chapter VI presents the conclusLons of the study and outlines astrategy for the development of domestic gas use.

Princical Conclusions

3. (l) Indonesias lndlcative goological reserves of natural gas areestimated to be about 217 TCF. Of these, about 67 TCF areclassLfied as provenl/ and 24 TCF as potential 1/ reserves.Among the proven and potential reserves, there are about 8.4 TCFP/recoverable reserves in structureo too small to support LNG exportsbut large enough to be exploited for the domestLc market, and it isestimated that further exploratlon could result ln the addltion of4 to 15 TCF in this category.

11 Of these, about 29 TCF have been developed and committed to long term (YAostlyL= export) contracts.

3] MIGAS's classification of potential reserves comprLses 50% of probable and25% of possLble reserves.

3/ Java 5.0 TCF, Sumatra 1.8 TCF and Kalimantan 1.6 TCF.

(ii) The economic cost of producing and delivering non-exportable gasfrom these reserves to bulk buyers in the major demand centers isestimated to range from $2.08 to $2.34/MCF, with a weighted averageof S2.25/MCF. The use of this non-exportable gas in powergeneration and industry is desirable because the economic benefit(netback values), with an estimated weighted average of $3.45/MCF,is higher than the economic cost of gas. Over a ten year period,this would amount to a net economic benefit of about $10 billion.

(iii) The projected consumption of gas for power generation and industryis sufficiently large to justify the development of a gas transmis-sion infrastructure. The proposed strategy is to t,&aet the projecteddomestic requirements of gas by developing the non-exportable gasreserves and the necessary gas transmission infrastructure.Initially, the infrastructure should be expanded to the size neededto deliver the undeveloped recoverable reserves of 8.4 TCF over theshort and medium terms (by 2004). As additional reserves areproven, further expansion of the infrastructure will be required tomaintain and expand the supply. As a fal2back option, theGovernment of Indonesia (GOI) should also consider the supply of LNGto Java from uncommitted reserves in Kalimantan or Natuna.

(iv) To implement the proposed strategy, adequate pricing andinstitutional changes are necessary to provide incentives to theproduction sharing contract (PSC) operators to develop the provenand potential reserves and to undertake fresh exploration. Theprices received by the PSC operators for the domestic supply of gasshould be determined on the basis of negotiations, as for LNGexports, and should be allowed to vary over time. A new entityshould be created with the specific mandate of handling gaspurchases from producers, gas transmission, and sales to bulkbuyers.

(v) The estimated total investment required for field development andtransmission and distribution networks is about $6.0 billion, ofwhich the share of PSC operators is $3.2 billion, Pertamina's $1.5billion, PGN's $0.6 billion and the remaining $0.7 billion the shareof the gas transmission company to be created. This investmentwould allow non-exportable gas to displace various fuels, between1994 and 2004, amounting to about 1,300 million barrels of oil on anenergy-equivalent basis, with a total value of about $21.5 billionin current prices. In particular, there would be a significantbeneficial impact on the balance of payments from the displacementof petroleum products in industrial uses, with an estimated value of$17.5 billion over ten years.4/ (see para 6.1, pp 38)

j/ It is assumed that in the power sector coal fired power plants would beconstructed if gas is not made available. For a cost comparison of gas vs. coalin power generation, see para 10, pp iv.

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Raltionale for Exanded Domestic Use of Gas

4. Even though the non-oil economy has experierced vigorous growth in the1980s, the oil and gas sector will retain a fundamental role in Indonesia'seconomy. In FY1991, the current account balance in the oil/gas sector isestimated at $6.9 billion, while tI'-'- . the non-oil sector is estimated at anegative $6.0 billion.

S. The Indonesian economy iq expe-Wed to grow at over 6% , .r year over thenext decade, and the demand for energy is expected to grow at an even higherrate. The World Bank's projections indicate that the oil and gas current accountbalance would decline to $1.9 billion by FY2001. A major reason for the declineis that rapid growth of domestic demand is reducing the exportable surplus of oilto the extent that Indonesia may become a net importer of oii. One of the policyobjectives in Indonesia is to satisfy energy demand, while minimizing thediversion of petroleum products from exports, by encouraging the use ofalternative sources of energy such as gas, coal and geothermal.

6. In 1990, Indonesia produced 2.16 TCF of natural gas, of which about 70% wasavailable for sale, after accounting for own use by operators, reinjection andflaring. About 80% of the marketable gas was exported as LNG, and only 20% usedin the domestic market mainly in fertilizer, iron and steel, petrochemical andcement plants.

7. The largest increase in domestic gas consumption is projected to take placein the power sector. Once the basic transmission infrastructure is in place tosupply combined cyc.le power plants (CCPPs), nearby industries can also besupplied. Expansion of the domestic gas utilization is justified by the loweconomic cost of developing a number of small and medium size gas fields, thatcontain a total of about 8.4 TCF of recoverable gas, but are too small to supportLNG exports. Estimates of the costs (AICs) of developing these fields andtransporting the gas to bulk buyers range between $0.97/MCF to $1.23/MCF,excluding past development costs, which are treated as sunk costs. It isestimated that additional exploration will add about 4 to 15 TCF of reserves.

8. The depletion premium is estimated at $1.11/MCF, as of 1991, with gas tobe imported as LNG from Natuna or Kalimantan as the backstop fuel. This estimateof the depletion premium is higher than earlier estimates, because the backstopfuel is relatively expensive and the fields are expected to be depleted in tenyears (by 2004), and not in 20 years, as normally assumed for depreciationpurposes. There is no risk premium associated with these small fields, becausethese reserves are already identified as recoverable, so the economic cost of gaswould be the sum of the AIC and the depletion premium, or between about $2.08/MCFand $2.34/MCF delivered to bulk buyers.

9. In the case of exportable gas, as LNG from East Kalimantan (and Natuna whendeveloped), the economic cost in domestic use would be the border price of LNG,plus either the LNG transportation and- regasification costs or the pipelinetransportation coste, whichever is lower. On this basis, the current economiccost of LNG delivered in Java or Sumatra is estimated to be about $3.7/MCF.Given this cost for the backstop supply, the economic cost of gas to bulk buyers

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is estimated to rime gradually from about $2.08-2.34/MCF at present to about$4.16/MCF j/ in 2004, when non-exportable reserves are assumed to be depleted.

10. The economic cost of gas has to be compared with the economic costs ofalternative fuels in particular applications. In power generation, withadjustments made for thermal efficiency and capacity costs, the unit cost ofgeneration with gau at $2.34/NCF in CCPPs is lower than other alternatives (para2.28, pp 13). Additional advantages of gas compared to coal are that the capital(unit capacity) costs of CCPPe are much lower than the capital costs of coalfired plants, and that CePPs can be brought onstream quicker than coal firedplants. This is particuldrly relevant in Indoresia, which has limited funds butneeds to add power generation capacity urgently. Also, the particulates and theenvironmentally damaging emissions from coal, or the coats of controlling them,would be avoided.

11. After 2004, when the 8.4 TCF reserves have been depleted, the CCPPsinstalled as part of the development strategy will be supplied with gas from theadditional non-exportable reserves that are expected to be proven as a result offurther exploration. In the unlikely event that further exploration does notresult in sufficient additional reserves, the CCPPe would have to supplied withgas from Kalimantan or Natuna, at a current economic cost of $ 3.70/MCF. Evenwith this high cost gas, it will still be cheaper to install CCPPe rather thancoal-based power plants because the benefits of cheap gas in the first ten yearsmore than compensate for the possible high cost of gas in the latter years(para 2.31, pp 13).

12. Exportable gas, with a current economic cost of $3.70/NCF, is competitivein power generation with coal, only if the economic cost of delivered coal isabove $43/ton or at lower coal prices if a cost is given to the environmentalimpact of burning coal. Thus, the economic competitiveness of exportable gas forpower plants to be installed after 2004 will depend upon (i) the amount of andthe economic cost of non-exportable coal that will be available for the domesticmarket, and (Li) whether or not the coal power plant will require flue gasdesulphurization and other environmental controls.

13. General industries such as textiles, metal, food processing are mediumscale consumers of gas in Indonesia. The netback values for general industry arehigher than the netback value of gas in power generation (Table 4.6). once a gastransmissLon pipeline reaches a power station or another large consumer, theindustry in the vicinity can be expected to shift to gas. By 2000, generalindustry could account for about 25% of the total gas consumption. The economicnetback of gas in the fertilizer industry is $2.62/MCF. Most new fertilizercapacity is planned in East Kalimantan, where the economic cost of gas is lessthan $2.27/MCF. Thus, given the planned location of the fertilizer industry,there is an economic justification for supplying gas to it. PT Krakatau Steel(i.TKS) currently gets gas at prices well below its economic cost. PTKS is

j/ This value of $ 4.16 is in constant 1991 dollars, and reflects annualescalation of the current LNG price of $3.10 plus transportation andregasification.

expanding its production capacity and converting to a more efficient process,which should enable PTKS to pay the economic cost of gas.

14. There are 79 small and medium size fields that can only be used to supplythe domestic market. While some of these fields, with reserves of at least 7 BCFeach, have already been taken up for development, a concerted drive to developthe remainder of the 79 fields is justified. It is recommended that all of thesefields be fully exploited over a ten year period, except where commitments forlonger production life have already been made. A shorter production life willmake available earlier the quantities of gas needed to meet the rapidly growingdemand for energy, and create a market for the additional reserves that areexpected to be found.

15. Until 2004, the development program as envisaged (including fields to comeon stream under ongoing contracts) is likely to add 8.4 TCF of new gas to the 2.5TCF of existing available supply. On this basis, additional consumption can beplanned to expand to 7.8 TCF. For the needs after 2004, exploration effortsshould be intensified. To encourage the PSC operators to develop proven reservesand explore for new ones, an adequate price for gas would have to be established.Considering the economic benefits oi developing these gas fields, it is desirablethat GOl and the PSC operators arrive at an early understanding of prices andterms acceptable to both parties.

16. In the unlikely event that new reserves have not been found by 2004, therehas to be a fallback position. Natuna provides it with its abundant gasreserves. Without diversion from exports, gas can be supplied to Java andSumatra either as LNG or by pipeline, whichever is the least-cost solution.

Policy and Institutional Issues

17. To facilitate expanded domestic use of gas, several policy andinstitutional issues have to be addressed. First, the producers' perception ofthe domestic market must change so that their interest extends beyond exportableoil and LNG. Changes are needed in the pricing method, and a ga~i transmissioninfrastructure must be developed so that producers are assured of domesticofftake of gas. Second, an entity for buying, transmitting and selling gas tobulk buyers should be created and it must acquire the relevant skills andexpertise to promote efficient large-scale domestic gas utilization. Third, anappropriate regulatory framework should be implemented, including safetystandards and guidelines for pricing and access to the pipeline system.

18. Producer Prices. Under the current GOl policy, producer prices for naturalgas are determined by negot: 'Ltions between Pertamina (as the agent of 001) andindividual PSC operators based on the costs of supply, the rate of returnrequirements, and the market for gas in specific locations. The price receivedby the PSC operator, is fixed in US dollar terms for the duration of thecontract. On this basis, the producer price of gas is different for each PSC.The policy to base prices on the cost of field development does not provideadequate incentives to drill wells to appraise a field, as the PSC operatorswould know the gas price only after the costs have been incurred. The PSCoperators would prefer a pricing formula that allows them to estimate the pricechey will receive before any appraisal costs are incurred. This could be done

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by linking the gas price to the effici.cncy prices of the fuels gas will displacein the domestic market.

19. Further, it is alroo international practice to allow price variations, basedon international market indicec. Without a provision to pass on internationalmarket price variations, the PSC operators would seek to cover expected costincreases due to general inflation and market risks through a fixed price thatis initially at least higher than a market based price, which would discouragethe expanded use of gas with the conoequent economic cost. A price adjustmentclause should therefore be built into the contracts and the price received by thePSC operators should be related to the efficiency prices of alte: 'tive fuelsdisplaced by gas. Based on the curront international prices c al oil andcoal, this would result in a gas price to the PSC operator of betv.en $1.85/MCFand $2.01/MCF. While this price may be less than the fixed prices currentlybeing negotiated, it would be more attractive to PSC operators given the linkageto international prices of competing fuels.

20. Consumer Prices. The consumer prices of diesel and kerosene are belowtheir efficiency prices even after the price increases instituted in 1991. Thisimplies a competitive disadvantage for gas, whose consumer prices will be basedon the principle of efficiency pricinge. Thus, in order to remove this constrainton the development of the domestic market for gas, it is recommended that theconsumer prices of energy products, in particular diesel and kerosene, be basedon the principle of efficiency pricing.

21. G=as Trangsission and Marketina Entitv. To implement this program ofinvestment and to capture the potential returns from an expanding domestic useof gas will require the creation of an effective link between producers andconsumers. An entity should be created with the specific mandate to focus itsfull attention on the development of the domestic gas market. This entity,referred to as Gas Transmission and Marketing Entity (GTME), should beresponsible for gas purchases, transmission, and sales to bulk buyers in thedomestic market. All bulk buyers of gas (PLN, PGN, fertilizer industry) arecurrently Government-owned and Government also has a major share of the gasproduction through Pertamina and the PSCs. It would, therefore, be difficult fora purely private sector company to initiate the development of the domestic gassector. GTME will, therefore, need to start as a public sector entity,preferably as a Persero, with representation in its Board of Supervisors fromPertamina, which is responsible for oil and gas in Indonesia, PLN, PGN andfertilizer industry, which are bulk '-iyers. To ensure efficient operations, GTMEshould enter into a long-term i hnical collaboration arrangement with acompetent foreign gas company well experienced in transportation and marketing.If the establishmsnt of a new Persero would substantially delay the developmentof the domestic gas sector, then PGN, which is already exclusively focused on thedomestic gas market, might have its mission redefined to get the process started.

22. Once commitments from gas producers and bulk buyers have been obtained andthe transmission and distribution systems designed, Government involvement shouldbe reduced and the influence of the private sector increased.

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23. Regulatorv Asgects. The gas clauses in the PSCc should be amended in thesame spirit as the liberalized provisions introduced for oil. Thus, for marginalproducors, th- contractor's share of profit gas should be greater, as iscurrently the case for marginal oil production. While it is expected that gasflaring would normally be eliminated when there is a market for the gas, suitablepenalties may be prescribed to ensure that disproportionate gas flaring isavoided.

24. There will be a need for improved and expanded environmental and safetyregulation of the domestic utilization of gas as the market develops. Further,the creation of a monopolistic GTME, be it public or private, would make itnecessary to ensure that it operates efficiently within the margins of reasonableproducer and bulk buyer prices and provides reasonable access to the pipelinesystem. For this purpose, MIGAS is considering the creation of a separatedirectorate for regulation of the domestic gas market.

Strateav for Expanded Domestic Use of Gas

25. Until about 2004, the strategy for the expanded domestic use of gas is todevelop the proven and potential non-exportable gas reserves, after adequateappraisal of the fields, and simultaneously encourage the acceleration of theexploration efforts. The prospect:5 for adding new supplies to meet the domesticgas requirements beyond 2004 are very good, especially in North Sumatra andoffshore East Java. In the unlikely event that these exploration efforts do notsucceed, a fallback position is provided by exportable gas from Natuna or evenKalimantan. This gas could be transported to Java/Sumatra either as LNG or bypipeline. The current economic costs justify the displacement of liquidpetroleum products with exportable gas in the domestic market, if this would berequired.

26. Supply of gas to the domestic market until 2004 would required three typesof investments. Erst, investments are needed for field development. It isestimated that the PSC operators would have to spend about $3.2 billion (in 1991prices), and Pertamina about $1.1 billion to develop the proven and potentialreserves (not including $0.4 billion being arranged for an offshore pipeline inEast Java). Given adequate gas prices, Pertamina may be able to enter into Jointoperation Agreements for gas of the same type used for oil field development.Second, investments are needed for expansion of transmission infrastructure andto rehabilitate and strengthen the existing pipelines. It is estimated that GTMEwill have to spend about $0.7 billion for this purpose. GTME may be able toraise funds from the private sector, bilateral agencies, suppliers' credits,commercial bank loans and bond issues, given the low-risk nature of itsoperations once the volumes and prices for gas have been agreed between concernedparties. hird, bulk buyers of gas, in particular PGN, will also have toundertake investments to expand distribution system at a cost of about $0.6billion. PGN would generate some internal funds, and would largely have accessto the same funding sources as GTME.

27. The total cost of the proposed strategy, of about $6.0 billion (by 2004)is substantially higher than the currently projected investments in domestic gasdevelopment of $1.5 blllion for the next 5 years. On the benefit side, theproposed strategy is projected to provide a net economic benefit of about $10

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billion over a ten year period (1994 to 2004) and to improve the oil and gascurrnt account balance in FY2001 from the $1.9 billion level (para 5) to $3.6billion.

28. Over the long run, the domestic gas consumption is expected to be about 35TCF over the period until 2020. Clearly, more gas reserves have to be proven tosupply the domestic requlrements. The prospect. for new gas finds aro good.Nevertheless, 00G should continuously monitor the situation to ensure thatadequate reserves of oil and gas are maintained. Exports may have to berestrained and domestic consumption curbed to achieve a satisfactory balancebetween reserves and consumption.

I. THE ENERGY SECTOR

Introduction

1.1 Indonesia is endowed with large and diverse energy resources includingcrude oil, natural gas, coal, hydropower and geothermal. In the early 1980s,most of the country's exports and the government's revenues came from oil andLNa. Following the collapse of oil prices in the first half of the 1980s,Indonesia began a series of fundamental reforms to restructure the economy, andincentives were provided for non-oil/LNG manufacturlng and non-oil/LNG exports.Consequently, between 1983 and 1990, non-oil/LNG real GDP grew faster than theoil/LNG sector. However, the oil/LNG sector still retains a fundamental role inIndonesia's economy. it is projected that in FY1992, the gross oil/LNG exportswill be $11.1 billion, constituting roughly two-fifths of gross merchandiseexports. For FY1992, the oil/LNG current account balance is projected to be $4.2billion, while the non-oil/LNG current account balance is projected to benegative $8.5 billion.

1.2 Indonesia's GDP is projected to increase at an annual average rate of about5.8% over the next decade, while the manufacturing sector is projected toincrease at over 10%. Thus, given the energy-intensive nature of themanufacturing sector, the demand for energy is also likely to increase at a rateabove the GDP growth rate. The World Bank's projections of balance of paymentsindicate that the oil/LNG current account balances will decline over the 1990oto $1.9 billion by FY2001. A major reason for this decline is the rapid growthof domestlc demand for petroleum products.

1.3 The domestic commercial energy sector in Indonesia is dominated by liquidpetroleum products, which account for about 78% of net energy consumed. Naturalgas is the second largest source of energy, with a share of approximately 10%.Even though the use of coal grew rapidly in the late 1980., its share remainssmall at approximately 4%. (See Table 1.1). Liquid petroleum products remain thedominant fuel for power generation (Annex 1.1).

*Indonesia: Developing Private Enterprise," World Bank Report No.

9498-IND, May 1991.

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Table 1.1: NET ENERGY USE IN INDONESIA, 1990

Quantitv Percentage(MMBOE)

Kerosene 50.6 21.9Gasoline 38.2 16.5Diesel (automotive) 67.5 29.1Diesel (industrial) 11.0 4.8Fuel Oil 9.1 3.9Jet Fuel 4.9 2.1

Total Liquid Fuels 181.3 78.3

Natural Gas 22.7 9.8Coal 8.9 3.8

Electricity 1/ 18.7 8.1Total 231.6 100.0

1/ Net, after own use, transmission and distribution losses. The fuelsneeded to generate this capacity have not been included in the consumptionof diesel, gas and coal. For details, see Annex 1.1.

Source: MIGAS

1.4 Overall commercial energy consumption in Indonesia has been growing rapidlyin recent years. Electric power consumption grew 14% annually over the last tenyears. Liquid petroleum product consumption is currently increasing at about 13%per year after having grown at an average of 9.9% from 1979 to 1989. Gas saleshave shown a 9% annual increase from 1984 through 1990. Liquid petroleumproducts and natural gas were the two leading fuels and contributed to about 90%of the commercial energy consumption in 1990, with shares of 80% and 10%respectively. At the same time, oil and natural gas were also major foreignexchange earners with net earnings of $2.3 billion and $1.6 billion respectivelyin FY1990.

1.5 One of the objectives of economic policy in Indonesia is to satisfy therapidly growing demand for energy while minimizing the diversion of liquidpetroleum products from exports. This requires efficient use of resources, thereduction of demand pressures, and the development of alternative energyresources that can economically substitute for domestic petroleum use. Thesealternative resources include coal, natural gas, geothermal, and hydropower.

Primary Enerav Resources

1.6 Oil. Indonesia's proven and potential reserves of oil have been estimatedto be about 11 billion barrels. The production of crude oil and condensates in1990 was about 530 million barrels, which implies a reserve-production ratio of

approximately 20:1. Further, Indonesia has the potential to explore for and

discover new reserves. International oil companies (IOCs) remain interested in

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production in effect in 1990, and new onea being added regularly.

1.7 To encourage lOCs, particularly as the prospective discoveries of oil arelikely to be in medium and small size fields, the Government of Indonesia (GOI)ham been liberalizing the terms of the production sharing contracts. In 1990,59 wildcat wells were drilled and it is reported that 31 were successful, withoil found in 21 wells and gas in the other ten wells.

1.8 Of the 530 million barrels of crude oil and condensates produced in 1990,about 274 million barrels were refined within the country (see Annex 1.1). Thebalance of about 50% of the total production wao exported.

1.9 Coal. Indonesia's total coal reserves are estimated to exceed 32 billiontons, located primarily in Sumatra (23 billion tons) and Kalimantan (9 billiontons). (See Annex 1.2). The "measured reserves" are 4.2 billion tons, which isequivalent to roughly 18 billion BOE, divided nearly equally between Sumatra andKalimantan.

1.10 Indonesia's current annual coal production is about 11 million tons, (about46 million BOE), of which about 60% comes from Sumatra and the remaining amountfrom Kalimantan. Thus, the ratio of measured reserves to annual production isabout 400:1. Besides one state enterprise 2, a dozen foreign contractors sharein joint ventures and in further exploration and exploitation activities. Coalproduction is expected to exceed 30 million tons by 1994 and reach 50 milliontons by 2000.

1.11 The technical characteristics of Indonesian coal are shown in Annex 1.2.in general, Indonesian coal has low sulphur, low ash, high moisture, and a highlevel of volatile matter. Thus, Kalimantan coal is suitable for steamgeneration, and to a limited extent, also for industrial processes such as steel-making. While the calorific value of Indonesian coal is high on an air-driedbasis, the moisture content of Sumatra coal is high and the calorific value islow on an as-received basis. These characteristics make it difficult to exportSumatra coal, though a trial shipment of Bukit Asam coal to Japan has taken placein 1991. In contrast, Kalimantan coal is generally exportable and of a highquality.

1.12 The production rate of the Bukit Asam mines in South Sumatra is expectedto increase from the current level of 5 million tons to 5.7 million tons byFY1993, and the Muara Tiga and Banko mines in the Bukit Asam area to begin

production in 1994 and reach an annual output of 5 million tons by 1999. Mostof the coal from these mines has already been committed for the Suralaya powerstation in West Java and some local industries in Sumatra.

2 This enterprise, PT Tambang Batubara Bukit Asam (PTTBBA), was formedin 1990 by merging two earlier enterprises. PTTBBA operates the coal mines atBukit Asam (now renamed Tanjung Enim) and Ombilin in South Sumatra, and managesthe contractors who operate coal mines in Sumatra and Kalimantan.

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1.13 Thus, under the current production plans, only limited quantities ofincremental uncommitted coal are expected from Sumatra. In contrast, Kalimantancoal production is expected to rise rapidly, and be available to meet incrementaldemand.

1.14 Coal exports in 1990 amounted to 4.2 million tons and indications are that18 million tons will be exported in 1994 and 30 million tons in 2000. Thefacilities for loading 150-180 thousand DWT vessels are being commissioned, whichwould enable Indonesia to compete even for coal exports to Europe.

1.15 Natural Gas. Natural gas resources and their use io discussed in detailin Chapters III and IV of this report. Briefly, the recoverable proven andpotential reserves are about 91 TCF, the current annual gross production is 2.16TCF, and the reserve-production ratio is 42:1, which is high by internationalstandards. About 57% of the gas production is devoted to LNG/LPG, which areexported. Domestic sales absorb about 14% of the production, with the balancebeing accounted for by own use of operators or flared (Table 2.1).

1.16 Geothermal. The potential for geothermal energy is estimated to be about16,000 MW, of which about 8,000 MW is in Java. A 140 KW plant has been inoperation in Java since 1988. Following successful exploration by two foreigncompanies in joint venture with Pertamina, two new 55 MW power units have beenscheduled for commissioning in 1993 and 1994.

1.17 At present, the geothermal capacity of 140 MW is minuscule, compared toPLvNs 8,500 MW total installed capacity, and additional captive non-PLN 7,900 MWcapacity. However, given the substantial geothermal potential in Java, thereappears to be a case for pursuing this option further in the future because somecountries have found geothermal steam-based power generation to be competitivewith other sources.

1.18 Hydro2gy_er. The hydroelectic power potential has been estimated at about75,000 MW, consisting of 22,400 MW in Irian Jaya, 21,600 MW in Kalimantan, 15,000MW in Sumatra, 10,200 MW in Sulawesi, 4,200 MW in Java and the rest in NusaTenggara, Bali and Malaku. While Indonesia's hydropower potential is large, itsdevelopment is limited by its geographic distribution relative to demand. Java,accounting for about 80% of the electricity consumption has less than 6% of thetotal potential. Hydropower plants of about 1800 MW have, however, been set-upin Java. Further development has been constrained by environmental and landtenure problems.

The Power Sector

1.19 Indonesia is facing a shortfall of electricity due to inadequate powergeneration and transmission capacity. About 50% of the demand (about 27,700 Gwh)in 1990 was provided by PLN and the rest by the private sector. The industrialsector installed captive power plants because, in part, PLN could not provide thepower, and, in part, because of an ability to generate power at costs comparablewith those of PLN due to the availability of subsidized diesel fuel.

1.20 Java is the or.ly island with a large interconnected grid. Outside of Java,PLN operates about 660 small systems mostly supplied with electricity by diesel

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generators. PLN's power devolopment program provides for its own installedcapacity to go up from the present 9,100 MW to about 26,000 MW in 2000. At thesame time the private sector has been invit-d to supplement PLN'o program byconstructing major power generation plants under Build-Operate-Own (BOO) schemes,and about 6,600 MW of coal fired plant. until 2000 have been earmarked for thispurpose.

1.21 A beginning has been made with bids having been received for two 600 MWplants at Paiton in East Java, in addition to the two units of 400 MW which PLNwill build. A private sector power team has been created within the governmentto act as a focal point and clearing house for private bids to generate power.The regulatory framework needed is expected to be evolved soon.

Enerav Consumotion Patterne

1.22 The consumption pattern in 1990 is presented in the commercial energybalances for 1990 and 1985 (Annex 1.1). The industrial and transportationsectors dominate modern energy consumption in Indonesia, accounting for about 38%each of the net energy consumed. The household sector accounts for about one-fourth of net energy consumption. This pattern is similar to that present inIndonesia in 1985, exccept for a gain in the share of the transportation sector,largely at the expense of the household sector.

1.i3 Industrial Sector: Not energy use in the industrial sector has grown atapproximately 7% per year over 1985-1990. Petroleum products provide about halfof the industrial sector's energy needs. The largest source of energy for thissector is diesel oil, with a share of about 42%, followed by natural gas (26%),electricity (12%), fuel oil (10%) and coal (10%).

1.24 The energy consumption patterns in the manufacturing sector provide someindication of the potential domestic market for gas. These patterns for Java'smanufacturing sector indicate that there is extensive use of liquid petroleumproduct fuels in ovens, kilns, boilers and heaters (Table 1.2). In the future,this substantial market for energy could be served by natual gas.

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Table 1.2: ENERGY CNSUMPTION PATTERNS IN JAVA'S MANUFACTURING SECTOR jj

Road Gensets Boilers Others /b Total FeedstockTransport Energy

------- …-------------'000 BOE per year---------------------

Natural Gau 0 0 1,345 4,241 5,587 6,040Gasoline 362 0 0 18 380 0

Kerosene 0 121 36 398 555 0Diesel 386 4,778 3,482 3,856 12,002 0Cokes 0 0 0 139 139 0Coal 0 0 0 784 784 0Others LQ 0 6 1,592 2,625 4,230 579

TOTAL 748 4.905 6.455 12 Q61 23,677 6.619

/a Based on GUE 1998 survey and BPS 1987 surveyib Includes kilns, ovens and dryersiL Includes fuel oil and industrial wastesSource: "Study of an Integrated Gas Transmission System on Java," GasunieEngineering BV, PT Ciprocon and PT Goode Pataka Alam, Jakarta, October, 1990.

1.25 Trans2ortation Sector: Net energy use in the transportation sector hasincreased faster (at about. 9% per year over 1985-1990) than any other sector.The main sources of energy for this sector are diesel oil and motor spirit,which provide approximately 45% each of the energy needs of this sector. The useof diesel oil has grown at over 10% per year over 1985-1990.

1.26 Household Sector: Net energy use in the household sector has increasedrelatively slowly at about 3% per year over 1985-1990. The bulk (90%) of thehousehold sector's energy needs are provided by kerosene 3/, but the use ofelectricity in this sector has been growing rapidly at about 12% per year.

3/ The official data indicate that all kerosene is consumed by the householdsector. However, there is evidence that kerosene is also used for powergeneration and as a substitute or supplement (adulterant) for gasoline, fuel oiland diesel. See Table 1.2 and "Indonesia: Energy Pricing Review" (1990), WorldBank Report No. 8684-IND, page 11.

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II. THE GAS SECTOR

Backaround

2.1 In 1990, Indonesia's gas production was 2.16 TCF. The use of this gas isshown in Table 2.1. Over 71% of produced gas was sold, with about 57% exportedand 14% consumed domestical'y, flaring accounted for about 8% and the rest wasused in field operations.

2.2 The exports of LNG started in 1977 following discoveries of very large gasfields in North Sumatra and East Kalimantan. In 1990, the LNG exports amountedto about 21 million tons (equivalent to about 1 TCF). The exports go to Japan,Korea and Taiwan. Indonesia is the world's largest exporter of LNG, accountingfor about 40% of the world LNG exports and about 55% share of Asian LNG market.In the Asia/Pacific region Indonesia competes with Malaysia (supplying about 6million tons), Brunei (supplying about 6 million tons) and Abu Dhabi (supplyingabout 2 million tons). The exports from Australia and Alaska though currentlysmall, are expected to grow in volume.

2.3 The domestic market accounted for approximately 20% of total gas sales in1990. Four large fertilizer plants, situated mostly near LNG sites, accountedfor about half of the domestic consumption. The remaining domestic consumptionwas made up of a variety of projects clustered around the transmission pipelinein West Java and oil refineries, power stations7 cement plants, paper mills andcity distribution systems in other parts of the country.

Table 2.1: NATURAL GAS PRODUCTION AND UTILIZATION, 1990

Share of Gross Share-Ouantit Production of Sales

(BCF) %

Gross Production 2,133 100

Non-sale Disposition 618 29Producers' Own Use 448 21Flared 170 8

Total Gas Sales 1,515 71 100

ExDorts 1,211 - 80LNG 1,076 -LPG 135 - -

Domestic Sales 304 - 20Power Generation 12 - -General Industry a/ 22 - -Fertilizer Plants 176 - -Steel Manufacture 46 - -Cement Plants 6 - -Refineries 32 -

Petrochemicals 10

Source: NIGAS

^/ includes sales to residential and conmercial customers.

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Institutional Arrancements

2.4 The Minietry of Mines and Energy (MME) is the principal agency responsiblefor the development and implementation of Government policies in the energysector. Within the Ministry, there are four Directorates-General, of which threehave energy responsibilities. The Directorate General, Oil and Natural Gas(MIGAS) is responsible for the petroleum lndustry. Within MIGAS, LEMIGAS is anoil and gas research center which monitors crude and product specifications, andPPTMGB is a manpower development center. The Directorate General of Mining,supervises development activity in the mining industry, including all state coaloperations. The Directorate General of Electricity and New Energy resourcesoversees the operation of PLN, the State Electricity Corporation.

2.5 Pertamina is the key operating organization in the petroleum sector,including natural gas. 4/ Pertamina's Board of Commissioners, headed by theMinister of Mines and Energy, formulates policy guidelines and providessupervisory control over Pertamina's activities. Among the other members of thisBoard are the Finance Minister and the Head of the National Development PlanningBoard (BAPPENAS). The Board oversees Pertamina's operations including budget,project execution, creation of subsidiaries and joint ventures, and major salescontracts.

2.6 Pertamina is managed by a President-Director, who is the Chief Executiveofficer, and a Board of six full-time Directors with specific functionalresponsibilities. The President-Director and the Directors are appointed by thePresident of Indonesia for renewable terms. The organization chart of Pertaminais given in Annex 2.1. The six Directors look after Exploration and Production,Processing and Refining of oil and gas, Domestic Supply, General Affairs andForeign Marketing, Finance and Accounting, and Shipping and Telecommunication.While Pertamina has a number of oil and gas fields under its direct operation,Production Sharing Contracts (PSCs) with international oil companies representthe dominant share of its petroleum activities. Pertamina deals with the PSCoperators through a special office, the BPPKA or foreign contractors'coordinating body.

2.7 At present, there are 53 oil companies operating in approximately 100contract areas. Their interest in exploring in Indonesia continues at a highlevel because the GOI has adapted the terms of the production sharing contractsto changing circumstances. Until the mid-1970s, oil companies were primarilyinterested in oil, not natural gas because there was no domestic market for gas,and gas exports were not feasible. However, the oil price increases of 19708,and the development of the technology to liquefy gas and export it in tankers asLNG increased the PSC operators, interest in gas. Indonesia entered the LNGtrade in 1977 with the export of about 0.5 million tons of LNG which increasedto about 13 million tons in 1986 and to about 21 million tons in 1990.

2.8 The development of gas fields for the domestic market is characterized bya case-by-case approach within a broad policy. This policy, announced inFebruary 1989, indicatee that the price received by the gas supplier will bebased on "field development economics." Under this policy, a PSC operatorinitiates a proposal to supply the domestic market either when the gas discoveryis not large enough to support export or when a bulk buyer of gas identifies a

I/ Pertamina was created in 1968, and its current basic charter was laid downby Law No. 8 of 1971. This Law made the company responsible for exploration,production and marketing of Indonesia's oil and natural gas.

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potential source of supply. Pertamina, au the mole agency responsible for gasmales, has a dual role at that stagel it buys the gas from the operator and sellsit to the bulk buyer. In general, Pertamina in responsible for the pipelinesneeded for the transmission of the gas from the fields to the bulk buyers.

2.9 While Pertamina is the main operating organization in the petroleum sector,PGN, the state gas corporation, has a significant and rapidly expanding role inthe gas subsector. PGN was created in 1958 as a Government agency to take overforeign interests in the manufacture and distribution of town gas in the largerIndonesian cLties. In 1984, after natural gas had become available fordistribution, GOI converted PGN to a Government Corporation and it nowdistributes natural gas to medium-size industries, commercial and householdconsumers in Java, Sumatra and Sulawesi.

Development of Gas Supply Infrastructure

2.10 Generally, in a developing country the economic justification for thedevelopment of natural gas transmission infrastructure is provided by the demandfor gas from a few large consumers, who are connected by transmission pipelinesto gas fields. Reticulation of the system follows when other consumers seek touse natural gas. In Indonesia, so far the large consumers of gas have been thefertilizer and steel industries. However, as indicated in Chapter IV, their useof gas is expected to grow slowly and the economic netback values of gas in theseuses are relatively low, so that these industries cannot provide the economicjustification for further expansion of gas infrastructure.

2.11 In contrast, power generation, which uses limited amounts of natural gasat the present is expected to expand rapidly and could use large quantities ofnatural gas in gas turbines or combined-cycle power plants. In the next fiveyears, PLN, the State Electricity Corporation, plans to establish combined cyclepower generation facilities of 4,500 MW capacity in East and West Java. Theseplants will annually consume about 260 BCF of gas, equivalent to about 5 TCF ofgas over 20 years.

2.12 If a gas transmission infrastructure is developed to supply the powersector, industries that are located (or can locate) close to the transmissioninfrastructure will also consider using gas. It is likely that industries suchas food and beverages, textiles, wood and furniture, paper and pulp, rubber andplastics, minerals and metal and others, would use gas if supplies were madeavailable to them. Thus, in Indonesia, the economic justification for theexpansion of the gas supply infrastructure would come from the power sector andthe general industry, depending on the economic cost of gas and the economicbenefits of using gas in these sectors.

Economic Cost of Gas

2.13 The economic cost of gas depends on the characteristics of the gas fields.If the gas field (or cluster of fields) is too small to support an LNG facility,5/ then the gas from that field is non-exportable. Given the need to sustainexports from the oil and gas sector, it is desirable to primarily consider thepossibility of using non-exportable gas in the domestic market, reserving the

j/ A rule of thumb is that a gas field (or a cluster of fields) of at leastapproximately 2.5 TCF is required for an LNG facility to be viable.

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exportable gas for export. For non-exportable gas, the economic cost of gasincludes the average incremental cost (AIC), I/ a depletion premium, and a riskpremium; for exportable gas, the economic cost of gas is based on the FOB borderprice of LNG. In either case, the cost of transmission to the bulk consumer hasto be added to derive the full oconomlc cost of gas.

2.14 At present, IndonecLa has both exportable and non-exportable gas reserves.As dLscussed ln Chapter SIU, there are a number of gas fLelds onshore andoffshore Java and Sumatra that are too small for the gas to be exported. Thelarge gas flelds Ln North Sumatra and East Kallmantan are already engaged ln LNGexports; gas from Indonesia's largest gas field, Natuna, wlll be exported whenthe field li developed.

2.15 The AICs for non-exportable gas fLilds have been calculated for dLfferentregions, each of which would be served by a transmLssLon system. The ATCsreported in Table 2.2 include the tranumLssion costi to bulk buyers. Table 2.2also shows the incremental gas supplies avallable from these fields for theperlod 1994-2004, if the development program outlined ln Chapter III islmplemented. (Data contained ln Annexes 3.10 to 3.18 wlth adjustment in caseswhere concrete development plans for specLfic fields were obtained have beenused.)

Table 2.2 AVERAGE INCREMENTAL GAS COSTS AND SUPPLIES

Total Gas Average Supply AIC /ARegion (TCF) (MMCFD) (S/MCF)

East and Central Java 2.78 760 1.14West Java Lk 2.24 614 1.23South and Central Sumatra L2 1.47 238 1.02North Sumatra 0.28 65 1.13East Kalimantan 1.59 435 0.97

Total 8.36 2,112 1.14

LA These are the estimated costs at the city gate and do not include the pastexploratLon costs, whlch are treated as sunk costa.

/k From a number of clusters of fields./2 It is assumed that 0.4 TCF of thLs gas will be transported to West Java.Sourcet Mission estimates

2.16 Exploratory and some prelimlnary development works have already beenundertaken for the fields considered, so there would be no further exploratloncosts.

2.17 For gas that is exportable as LNG, the border prlce of LNG can be used toestimate the economlc cost. Thus, gas from North Sumatra, Bast Kalimantan orNatuna used ln the domestlc market, would have an economlc cost of approximately$3. 10/MCI, whlch would be the LNG price at an average IndonesLan crude oil prlce

J The AIC is the dlicounted present value of the estimated capital and varlablecosts dlvlded by the dlicounted present value of the quantity of gas likely tobe produced.

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of $19.2/bbl. If this exportable gas is brought to Java by LNG tanker,the transportation and re-gasification cost would add approximately $0.60/MCF.Thus, the economic cost of exportable gas delivered Ln Java is approxLmately$3.70/MCF. 7/

2.18 Availabillty of Gas for Domestic Use. Thli estimate of the economic costof exportable gas at $3.70/MCF ia based on current Lnternatlonal prices.However, at present, the exportable gas from Sumatra and Kallmantan cannot bedellvered to Java, since there are no LNG receivlng terminals ln Java.

2.19 The development of the Natuna flold is a major undertaklng, wlth a longlead perLod. Consequently, gas from the Natuna fleld Ls unllkely to be avallablebefore 1999. It is unlikely that gas will be available from the North SumatraLNG operatLons because these gas fields have reserves just adequate to meet thecurrent LNG export commitments. However, there should be gas available fromKalLmantan for domestic sales, beyond the term of the current export contracts,but GOI intends to extend the contracts. Thus, only the gas from onshore andoffshore Java flelds and small and medLum fLelds Ln other islands is availablefor domestic sales in the next ten years -- unless exploration results in thedLacovery of new gas fields.

2.20 Depletion Premium: The backstop fuel for the non-exportable gas to beutilized Ln the domestlc market, whlch is projected to be depleted by 2004 underthe development program recommended in this study, L exportable gas from Natunaor other large fields. The current value of the depletion premium Ls estimatedto be $1.11/MMBTU 8/. This estimate Ls higher than earller estimates becausethe back-stop fuel is relatively expensive, and the fields are expected to bedepleted in the ten years and not in 20 years, am normally assumed fordepreclatLon purposes. If exportable coal is used as the backstop fuel, thedepletlon premium La slightly lower than $1.11/MMBTU. Nevertheless, the higherestimate is used in this analysls to ensure that the use of natural gas isjustified under stringent conditions.

2.21 Total Economlc Cost: With a depletLon premlum of $ l.ll/MMBTU, theeconomic cost of non-exportable gas is in the range $2.08-2.34/MMBTU at the pointof dellvery to a bulk buyer along the transmLsslon system.

V It is possible to transport gas by pipeline to Java instead of as LNG, whichhas to be regasified. One drawback to pipeline transmission is that pipelineinvestments are lumpy, and all of the investment is required upfront, whereas LNGinvestment would be phased, train by train. Further, the common costs of LNGtransportation would be incurred when the first LNG train is put up for LNGexports. LNG transport is also a more flexible solution than a gas pipeline asa delivering facility can serve various receiving terminals. Nevertheless, ifdetailed calculations show that pipeline transmLssion is cheaper than LNGtransportation, then the cheaper option should naturally be selected.

NJ In the calculation of the depletion premium, the current FOB LNG price of$ 3.10/MMBTU is escalated, in real terms, by 1% per year untll 2004, and a 10%discount rate is used. The freight and regasification costs of $ 0.60/MMBTU arenot escalated.

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Curr-nt Fconomic Cost of Alternative Fuels

2.22 Economic Cost of Coal: At prevent, PLN buys coal from Bukit Asam, Sumatrafor Rp. 66,000/ton, and there are indications that this price may be raised toRp. 77,000/ton. However, the economic cost of this coal, delivered to PLNfspower plant at Suralaya is only Rp. 58,000/ton, which in approximately equal to$29/ton. Thus, the economic cost of Sumatra coal is taken to be $29/ton. Asdiscussed in Chapter I, only limited amounts of coal from Sumatra may beavailabl- for additional coal fired power plants.

2.23 Since Kalimantan coal in exportable, its economic cost can be derived fromthe border prlce. The average Kalimantan export price has been $40/ton, FOB, butthe calorlflc value of this coal is approximately 7,200 klIocalorLes/kg. On astandard coal basLi of 6,000 kilocalorLes/kg, the economlc cost of Kallmantancoal is approximately $33/ton, FOB. Assuming transportation, storage and othercosts of $8/ton, the current economlc cost of Kalimantan coal, based on exportprlce, li approximately $41/ton, delivered to bulk buyers in Java.

2.24 It is possible that the economic cost for the domestic use of coal may belower than the current border price if there is a limit to the quantity ofKalimantan coal that can be exported at the current price. In this case, theeconomic cost of coal will be given by the sum of the AIC and the depletionpremium for Kalimantan coal. Since the Kalimantan coal reserves are vast, thedepletion premium is negligible. The AIC was estimated to be $24/ton, in 1986prices, delivered to bulk buyers in Java.2/ In 1991 prices, this estimateamounts to $30/ton. Thus, on the basis of the costs of productLon, the economiccost of Kalimantan coal is $30/ton.

2.25 Economic Cost of Fuel Oil: The economic cost of exportable liquidpetroleum products such as diesel and fuel oil is given by their border price,plus any transportatLon costs to the consumer. Based on this consLderation, thecurrent economic cost of fuel oil is $16.50/bbl.

The Case For Expanded Domestic Use of Gas

2.26 The rationale for the expansion of the domestic sales of natural gas isthat gas has a slgnificantly lower economic cost than alternative fuels in anumber of applications, partlcularly power generation and general industry.Further, the environmental attributes of natural gas as a clean burning fuel,with low emissions of pollutants make natural gas more attractive than coal orliquid petroleum products.

2.27 Power Generation. At present, the principal fuel options for incrementalpower generation are offshore and onshore Java and Sumatra gas, Sumatra andKalimantan coal, and fuel oil. Annex 2.2 gives a comparison of costs of powergeneration usLng gas in combined cycle power plants (CCPPs), coal and fuel oilin steam power stations.12/ In this comparison, the initial economic cost ofgas is $2.34/MCF, with an escalation of 1% per year in real terms. The initialeconomic cost of coal is $30/ton, with an escalation of 0.5% per year, and the

/ mIndoneia: Energy Options Review," World Bank Report No. 6583-114, 1987,page 20.

IV This table uses the technical assumptions made in "Prospects for Gas-fuelled Combined Cycle Power Generation in the Developing Countries," IndustrySeries Paper No. 35, The World Bank, May 1991.

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initial economic cost of fuel oil is $16. 50/barrel, with an escalation of 1% peryear in real terms.

2.28 The levelized unit generation cost of electricity is ¢4.03/Kwh for gas,¢4.54/Kwh for coal without desulphurization and about 05.19 with desulphurizationequipment and ¢5.79 /Kwh for fuel oil. Thus, natural gas is the cheapest sourceof electricity, followed by coal and fuel oil. Gas has three distinct advantagesover coal and fuel oil. First, the capital costs, per Kw of installed capacity,for natural gas are signifLcantly lower than the capital costs associated withcoal and fuel oil. Second, gas-based power plants can be brought online in asignificantly shorter time than coal- or fuel oil-based plants. Third, incontrast with coal and oil, gas-based power generation does not adversely effectthe environment. These advantages are particularly relevant in Indonesia, whichis facing both a shortage of capital funds and a shortage of power supplies.

2.29 The overall pattern of relative costs is robust; for example, it holds evenif the current economic cost of coal is reduced to $25/ton, while gas is held at$2.34/MCF. (See Annex 2.2) The economic cost of coal has to be les than$18.2/ton for coal to be cheaper in power generation than gas with an economiccost of $2.34/MCF.

2.30 Thus, on economic efficiency grounds alone, it is clear that gas should beused in preference to coal and fuel oil. Further, both coal and fuel oil areexportable, while gas is not exportable from the small and medium fields offshoreand onshore Java and Sumatra that are considered in this report. If there is anypremium attached to export earnings, this reinforces the case for using gas inpower generation. Further, this cost comparison does not take account of thecapital costs associated with flue gas desulphurization equipment, which isusually installed on coal fired plants to control pollution. If these costs areincluded, then the cost differential between coal and gas would rise.

2.331 These cost comparisons are based on the assumption that after 2004, whenthe reserves of 8.4 TCF have been depleted, the CCPPs installed as part of thedevelopment strategy will be supplied with gas from the additional non-exportablereserves that are expected to be proven as a result of further exploration.However, in the unlikely event that further exploration does not result insufficient additional reserves, the CCPPs would have to be supplied with gas fromKalimantan or Natuna. The current economic cost of this gas is $3.70/MCF, andwill rise to $4.16/MCF in 2005, based on a 1% annual real escalation in thecurrent LNG price of $3.10/MCF, and a constant real $0.60/MCF cost fortransportation and regasification. Under the assumptions that the CCPPsinstalled in the 1990s (i) will use non-exportable gas for ten years, with acurrent economic cost of $2.34/MCF, (ii) this economic cost will increase overthe ten years as the depletion premium increases, so that there is a smoothtransition in the economic cost of gas from non-exportable gas to LNG, and (iii)after 2034, the economic cost of gas supplied to these CCPPs will be $4.16/MCF,the levelized generation cost of these CCPPs will be ¢4.48/kWh, which still ialess than the coal-based generation cost of *4.54/kWh. Thus, even using highcost gas after 2004, it will still be cheaper to install CCPPs in the 19905rather than coal-based power plants.

2.32 For the future power plants that cannot be supplied even initially withnon-exportable gas, the choice of fuels may be between exportable gas (fromKalimantan or Natuna) and exportable coal from Kalimantan both of which arecheaper than exportable fuel oil in power generation. The cost comparisonbetween exportable gas and exportable coal is significantly affected by whetheror not the coal-based power plants are required to install flue gas

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desulphurization (FGD) equipment. At an economic cost of $41/ton for exportablecoal, gas is cheaper than coal in power generation provided the economic cost ofgas is less than $3.61/MCF, without FGD, and less than $4.45/MCF, with FGD (seeAnnex 2.2).,1/ Since the economic coat of exportable gas is 53.70/MCF,exportable gas is competitive with exportable coal in power generation only ifcoal-based power plants are required to install FGD equipment.

2.33 The estimates of the economic costs of exportable gas and coal may changein the future in response to changing international market conditions. Further,the need for FGD equipment may also change in the future. For these reasons, thedecision about the choice between exportable gas and coal should be made in thefuture, and not at present.

2.34 General Industry. The netback values for general industry are higher thanthe netback value of gas in power generation (Table 4.6). Further, in theseapplications, coal is not a viable option, so the choice is between gas andexportable fuel oil. After depleting the non-exportable gas reserves, the choicewill be between exportable gas and exportable fuel oil. Given the estimate ofS3.70/MCF for the economic cost of exportable gas, the use of this gas should belimited to those sectors of general industry where the netback value exceeds thiscost.

2.35 The economic cost of producing non-exportable gas and delivering it to bulkbuyers in major demand centers is estimated to range from S2.08/MCF to $2.34/MCF,with a weighted average of $2.25/MCF. The use of this non-exportable gas as fuelin power generatLon and industry is desirable because the economic benefit(netback values, Table 4.6), with a weighted average of $3.45/MCF, is higher thanthe economic cost of gas. Over a ten year perlod (1994-2004), this would amountto a net economic benefit of about $10 billion; involving the displacement ofvarious fuels amounting to about 1300 million barrels of oLl on an energy -equivalent basis, with a total value of about $21.5 billion in current prices.In particular, there would be a significant beneficial impact on the balance ofpayments from the displacement of products in industrial use, with an estimatedvalue of $17.5 billion over tha ten year period.

AL/ This comparLson includes a 1 % annual real escalation in the economic costof gas, and a 0.5% a.nual real escalation in the economic cost of coal.

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III. GAS RESERVES AND SUPPLY

Besources

3.1 Geological Backaround. over 60 sedimentary basins of tertiary age,covering an area of 2.3 million km2, with a potential for hydrocarbon discoverieshave been identified in Indonesia, and 36 basins have been drilled and explored.Of these, 14 basins have been developed, and eight basins remain to be developed.Exploratory drilling continues to be met with success. In 1990 it resulted in asuccess ratio of approximately 50%. 12/

3.2 Apart from the remaining 24 tertiary basins to be axplored, there are alsopre-tertiary prospects where indications of hydrocarbon presence have beenencountered recently. For example, there is a gas find estimated at about 0.5TCF in Irian Jaya. However, in view of the vast amount of reserves remaining tobe explored and proven in the tertiary basins, the focus in the near term willbe on the tertiary basins.

3.3 Non-associated and associated gas deposits occur in tertiary limestone andclastic reservoirs in horizons 600-3,000 meters deep. Most of the non-associatedgas deposits have been found in limestones of Miocene age.

3.4 Gas Reserves. Indonesia's indicative geological reserves of natural gasrouerves are estimated to be about 217 TCF. Approximately 20 to 40 TCF areestimated to be in the North-West Java basin, about 10 to 20 TCF in Sumatra,about 50 TCF in Natuna and Kutai basins and the balance scattered in the rest ofthe 60 tertiary basins. The accumulations in some Sumatra and East Kalimantanfields are large enough to support LNG exports, but most other accumulations arein small and medium structures, which cannot support LNG exports.

3.5 As of January 1, 1990, Indonesia had recoverable proven and potential gasreserves of 91 TCF, 67 TCF in the proven category and 24 TCF in the potentialcategory.1l/ The estimated reserves of 217 TCF indicate that there is scopefor a large accretion to the proven and potential categories. The estimatedreserves are contained in over 140 structures with a distribution as shown inTable 3.1.

Table 3.1: STRUCTURE SIZE AND RESERVE DISTRIBUTION

Reserves % of Total Structures(BCF)

0.5 to 10 2210 to 50 2750 to 100 16100 to 300 27above 300 8

Source: MIGAS

3.6 The distribution of reserves indicates that there are two types of gasresources in Indonesia. First, there are large structures that contain enoughgas to sustain LNG exports. Second, there are small and medium structures thatare too small to sustain LNG exports, but which can be exploited for the domesticmarket.

1aj/ MIGAS reported that out of 59 wildcat wells drilled in 1990, 31 weresuccessful, with 21 oil finds and 10 gas finds.

13/ MIGAS'* classification of potential reserves comprises 50% of probablereserves and 25% of possible reserves.

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3.7 In the past, systematic efforts have been made to explore for and exploitthe large structures, but the small and medium structure- have not beensufficiently addressed. However, two recent agreements with a PSC operator fordevelopment of offshore gas in East and West Java, M/ particularly thelatter, which would involve development of a cluster of small fields, point theway for a number of similar agreements to follow.

3.8 The geographical distribution of the proven and potential reserves of 91TCF is shown in Table 3.2.

Table 3.2: DISTRIBUTION OF RESERVES IN DIFFLRENT REGIONS

Proven Potentialdeveloped & proven

Region undeveloped Total % of Total

-(TCF)…-------------

North Sumatra 10.39 3.95 14.34 15.7Central & S. Sumatra 3.19 1.47 4.66 5.0West Java 2.74 2.24 4.98 5.4East Java 0.02 4.29 4.31 4.7Z. Kalimantan 12.89 10.05 22.94 25.1Natuna (South China Sea) 0.10 39.49 39.59 43.4Sulawesi & I. Jaya 0.01 0.62 0.63 0.7

Total 29.34 62.11 91.45 100.0

Source: MIGAS and Pertamina

3.9 Gas Availability. The proven developed reserves awaiting production of29.34 TCF consist of 7.4 TCF of associated gas and 21.9 TCF of non-associatedgas. Almost the whole of the proven developed gas is committed in long termcontracts. Except to the small extent that some of these reserves areuncommitted, for example onshore Java and offshore NW Java, new markets for gasas considered in this study will draw gas from the potential and provenundeveloped fields. These fields have a recoverable reserve of 62. 11 TCFcomprising 3.3 TCF of associated gas and 58.8 TCF of non-associatod gas.. Thisquantity of gas has to cater to new LNG commitments, such as the extension ofcurrent LNG contracts expirLng ln stages between 1999 and 2008, as well as thenew domestic gas requirements.

3.10 Likely Results of Gas Exploration. It is likely that gas exploration willresult in significant additional flnds of gas in small and medium structures.For example, in the near term, ma3or successes in exploration are expected fromARCO's efforts offshore NW Java and Kangean prospects in Est Java offshore,which could result in gas deliverabillty of 500 MMCFD and 600 MMCFD,respectively. Similarly, Asamera's efforts ln North Sumatra and South Sumatracould establish a few TCF of reserves in one or two years' time. Based ondiscussions with international oil companies in October 1991, it is estimatedthat at least 4 TCF, and as much as 14.6 TCF, of reserves could be establishedsoon (See Table 3.3).

gIl The agreement with a PSC operator for the development of a cluster of 15to 17 small and medium fields offshore West Java is still under discussion, butthe terms and price being discussed Lndicate a change in the motivation of PSCoperators to supply gas to the domestic market.

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Table 3.3: ESTIMATED RESERVE ADDITIONS FROM EXPLORATION FOR GAS

Region Gas ReservesLow Case High Case

------------BCF------------

West Java 600 2,800East Java 1,400 4,900Central Java 100 300South Sumatra 1,000 2,800North Sumatra 1,000 3,800

Total 4,100 14,600

Source: Mission estimates.

Gas SuoRlv Systems. Present SupDlies and Planned Developments

3.11 West Java SupplV Svstem: The three supply sources are Pertamina's L-Parigioffshore field, Pertamina's onshore fields and the offshore Ardjuna fieldsoperated by ARCO. A gas transmission system was installed, by Pertamina, in thelate 1970s to collect gas from the two offshore sources and the onshore fields,take the gas to Cilimaya, 160 km east of Jakarta for dehydration and compression,and then supply to the various consumers in west Java. At present, 180 MMCFDflows from L-Parigi, 20 MMCFD from Pertamina's onshore fields and 35 MMCFD fromArdiuna.

3.12 The transmission pipeline grid is a modest one, totalling about 5SO km inlength from Cirebon in the east to Cilogon in the west with a downgraded capacltyof about 250 MMCFD. The main consumers are Krakatau steel which uses 137 MMCFDof gas, Pupuk Kujang Fertilizer which uses 60 MMCFD and medium-size industries,commercial consumers in Jakarta and Bogor using about 50 MMCFD. The section ofthe pipeline leading to Pupuk Kujang is to be looped for adding a further supplyof 50 MMCFD expected from the development of a cluster of offshore fields byARCO.

3.13 PGN operates a distribution system of high and medium pressure pipelines,totalling about 700 km in length, for supplying the aforementioned 50 MMCFD tomedium size industries, commercial and household consumers in Jakarta and Bogor.

3.14 East Java SupplY System: There is no supply system at present. As part ofARCO's Pegerungan gas development, a 28 inch diameter 400 km long plpeline willcarry gas from the offshore field to Surabaya. PGN will complement he systemwith a distribution grid in and around Surabaya.

3. 15 South Sumatra System: The system has two sections, one a 6 to 8 inchdiameter 270 km long pipeline and the other a 12 to 24 inch diameter 220 km longpipeline, both connecting a number of Pertamina and Stanvac fiolds to PUSRIfertilizer and supplying presently about 150 MHCFD of gas.

3.16 North Sumatra System: The system serves to feed Arun field gas to the ArunLNG and LPG plant, the Asean Aceh/Iukander Muda fertilizer plants, the RertasKraft Aceh paper factory. A Pertamina infrastructure of transmLssion pipelinesserves PLN power stations and PGN (medium-size industrLes) in and around Medanwith a current supply of about 35 MMCFD from the onshore fields.

3.17 East Kalimantan: Kaltim fertilizer units receive about 185 MMCFD of gasdirectly from the operating companies.

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3.18 The more important gas development projects presently under way to augmentgas supply are shown in Table 3.4. A map of Indonesia showing the locations ofthe fields under development and proposed for development in subsequentparagraphs is attached to this report.

Table 3.4: GAS FIELDS DEVELOPMENT PROJECTS IN PROGRESS. 1992-1994

Region Quantity OperatorIMMCFD2

W. Java offshore 260 ARCOW. Java onshore 50 PertaminaS. Java offshore 392 ARCOE. Java offshore 40 Kodeco8. Sumatra 125 PertaminaS. Sumatra 25 Enim OilN. Sumatra 60 Pertamina

Total 952

Source: MIGAS and Pertamina

3.19 West Java ARCO is at an advanced stage of negotiations with Pertamina,to supply 210 WMCFD to combined cycle power plants to be installed by PLN atMuara Karang (450 MW) and Tanjung Priok (900 MW) from January 1994. Also 50 MMCFDof gas is to be supplied to Pupuk Kujang II fertilizer plant from about the sametime. The offshore pipelines will be laid under PSC terms. Pertamina willdevelop its own Cicauh, Gantar and Pasirjadi onshore fields to provide 50 MMCFDbetween late 1991 and mid 1992.

3.20 East Java: ARCO, after negotiating over five years for a contract forsupply of Pegerungan offshore field in East Java with GOI/Pertamina, is about toimplement the project. Gas is expected to reach landfall at Gresik during 1994.The contract provides for supplies to PLN (242 MMCFD), PGN (96 'MCFD) andPetrokimia (54 MMCFD). In all, 2.135 TCF of gas is to be delivered until 2010.The transmission line of 28 inch diameter and 400 km length is being plannedunder arrangements outside of the PSC, with the producers of gas being requiredto pay an agreed transmission fee. Since gas will be sold by the producers toPLN, PGN and Petrokimia, the net realization on sale will be less by the amountpaid as transmission fee. While the sale prices have been determined at aconstant S2.53/MM8TU to PLN, S2.16/MMBTU to PGN and $2.00/MMBTU to Petrokimia(average of $ 2.38/MCF), the weighted average net sale realization at the fieldwould initially amount to $1.66/MMBTU.

3.21 Kodeco's KE-5 project is nearing completion and production would startduring 1992. At that time, 40 MMCFD of gas would be delivered directly at Gresikthrough a 14 diameter 60 km long pipeline.

3.22 PGN, under a World Bank financed project, is to build a distribution systemin and around Surabaya, consisting of about 450 km of high and medium pressurepipelines for supply of 96 MMCFD gas to general industry.

3.23 South Sumatra: Portamina is developing its own Lembak, Musi-I1, Beringin,Prabumenang and Sengeti fields in South Sumatra to supply 125 MMCFD of gas toPUSRI fertilizer expansion in phases from 1992 to 1994. A pipeline expansionproject is also being executed so as to raise the capacity for transmission toPUSRI and Plaju to 270 MMCFD.

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3.24 Enim Oil's Harimau gas field project will capture associated gas of about25 MHCFD which is flared and supply it to PUSRI fertilizer plant, commencing inthe third quarter of 1992.

3.25 North Sumatra: Pertamina's project in the Medan area will consist ofdrilling of wells, laying of a new pipeline and construction of an LPG plant. Thegas supply would be about 60 MMCFD. Simultaneously, PGN will expand itsdistribution network in Medan.

Future Gas Supplies

3.26 The future gas supplies available for the domestic market depend upon thegas reserves that can be exploited, the rate at which they are depleted, and thecommitments for LNG exports.

3.27 LNG Export. In 1990, Indonesia's LNG exports constituted over 50% of themarket of about 40 million tons per year in the Asia-Pacific Region. The demandin this market is increasing, and it is estimated that it will more than doubleover the next 20 years. Indonesia operates 11 trains for LNG production, sixtrains in North Sumatra for processing gas from Arun and three smaller fields,and five trains in East Kalimantan for processing gas from Badak, Nilam, Attaka,Tunu, Handil and four other fields. A sixth train is to be commissioned in EastKalimantan in January 1994. Current contracts for LNG exports from North Sumatrawill expire between 1999 (for 3 trains) and 2008 (2 trains in 2007 and 1 in2008). These contracts will use up almost all of the reserves presently harnessedfor LNG exports and would only leave about 3.5 TCF (of provqn and potentialreserves) for contract extensions. For a rollover of the contracts to 2020 beyondthe current dates of expiry, the requirement of gas is about ll.i TCF. In EastKalimantan the existing contracts which expire in phases from 1998 to 2010 wouldleave unused about 11 TCF (of proven and potential reserves) for futurecommitments. This would facilitate all current contracts in East Kalimantan tobe rolled over to 2020.

3.28 GOl's plans for LNG exports are first to run the 11 trains in operation andthe 12th train to be added in 1994 to maximum capacity at about 28% over nameplate capacity. If that is done LNG exports could go up to 27 million tons fromthe present 20.6 million tons. In East Kalimantan, the full exploitation of thepotential of the trains will be poesible since 11 TCF of gas is remaininguncommitted and over and above that the exploration efforts under way indicatefirm possibilities of at least 3 more TCF being found. In North Sumatra, it hasalready been noted that the uncommitted reserves are inadequate for contractextensions as they expire in stages between 1999 and 2008. Nevertheless,exploration for gas in new areas of North Sumatra is in progress, and the seismicreadings have been positive. In about two years an assessment can be made of theextent of success of the efforts.

3.29 Natuna Gas Develooment. In this context, the Natuna gas field in the SouthChina Sea, located roughly 650 km east of Singapore, assumes critical importance.Esso, the PSC operator finds that it is technically feasible to develop the highcarbon dioxide (CO2 content of 71%) infused Natuna gas field. The developmentplan calls for reinjection of most of the carbon dioxide and for venting of avery small part.

3.30 The contract for the D-Alpha block, where the Natuna field is located,is not a standard PSC but is executed by a Joint Operating Body, with Pertaminaand Esso Indonesia Inc. as 50:50 partners. However, standard PSC terms apply toEaSEO's 50% sharo. Negotiations between GOI/Pertamina and E3so have been inprogress for several months. Primarily Esso appears to be seeking terms betterthan are normal in a standard PSC.

3.31 The investments in Natuna are going to be extremely large, about US$16-19billion for initial field development and 3 LNG trains on Natuna Island accordingto one estimate, given the reserves at 40 TCF (proven and probable) but mixedwith carbon dioxide in a quantity of 101 TCF and a water depth of about 500 feet.

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3.32 There are several development options related to the Natuna field. Theseir.lude direct LNG exports from Natuna, transmission by a 2000 km pipeline toArun, fTorth Sumatra for LNG exports from the trains already present there, andsupply to Java, either by pipeline or LNG tankers.

3.33 Natuna gas development would involve a gestation time of about seven yearsand the LNG trains are likely to be installed one each year probably commencingin 1999. In Chapter II, it has been shown that Natuna (or any exportable gas),if shipped to Java as LNG, will on regasification in Java be more economic to usethan fuel oil. Also it is likely to run close to exportable coal in powergeneration under present assumptions in regard to export prices of LNG andIndonesian coal.

3.34 It appears that the Natuna field can be developed at a cost within theprices for LNG as prevail in the world market. Thus, an early settlement of theoutstanding issues between GOI/Pertamina and Esso is desirable, both from thepoint of view of sustaining LNG exports at the present or an increased level andsupply to the domestic market.

3.35 Medium-Term Supolv to Domestic Market.For the medium-term (1994-2004) asmall pool of gas is available within the proven developed category which isalready largely committed to sales. This comprises that part of associated gasthat is now being flared over and above technical compulsions and some non-associated gas (for example, Maxus operated fields in Southeast Sumatra and ARCOoperated offshore NW Java fields). The larger part of the supply will be fromthe proven and potential undeveloped reserves if taken up for systematicexploitation. Selected fields in the different regions as sources of supply areconsidered in the following paragraphs.

3.36 The regions reviewed are (a) onshore west Java, (b) offshore west Java, (c)onshore central and east Java, (d) offshore east Java, (f) onshore central andSouth Sumatra, (g) onshore north Sumatra, (h) east Kalimantan and (L) Sulawesiand Irian Jaya. 0Wer 150 reservoirs in these regions are covered. The gasreserves in these reservoirs, as reported by HIGAS, range form 0.5 BCF to over1,500 BCF and include both associated and non-associated gas. To formulate arealistic development scenario, reservoirs with less than 7 BCF of reserves havebeen excluded unless these are contiguous to larger fields. On this basis, 79fields would warrant development. In a first step, reserves in these fields mustbe converted to proven developed after drilling the appraisal wells. Thedomestic gas requirements call for these fields to be drained in a ten yearproduction profile in preference to a longer profile such as of 20 years. Asdeclines in production would occur, compression will be required and theassumption is made that compressors will be introduced in the sixth year ofproduction. Well drilling, field development and associated pipeline costs havebeen estimated in order to assess the magnitude of investments as well as theaverage incremental costs (AICs) of production. Annexes 3.1-3.18 contain detailsof the review and a summary of the analysis.

3.37 While the AIC values can be used to provide the economic justification fordevelopment of a field or a group of fields, the PSC operator is interested inthe project's financial rate of return (ROR). At this time, the GOI's pricingpolicy does not provide any indication of the price that the PSC operators willreceive, since this price will be based on the development costs associated witha particular field. However, with no changes in the current systems, it may bepresumed that the price and other terms will be similar to those being agreed toin a contract for development of a cluster of offshore West Java fields. on thispremise and going by the standard PSC accounting principles pertaining todepreciation, investment credits, profit sharing and taxes, financial rates ofreturn can be estimated for the groups of fields which each operator will developin each region. Most ROR estimates indicate attractive returns on current basLifor PSC operator"i Pertamina's own fields tend to have higher RORs as all profitswill be retained by Pertamina.

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3.38 Table 3.5 summarizes the results of the proposed developments to facilitatecomparisons with the base case consumption scenario discussed in the nextchapter. Annexes 3.9 through 3.18 contain supply and consumption projections ona year by year basis. It is to be repeated that the supply is on a ten yearproduction profile (except for Pegerungan in east Java where the contractprovides for a 20 year supply) and the fields considered will be depleted in thatperiod. Other fields to be discovered have to be exploited to continue with thesupplies or the fall back will be gas from Natuna or other exportable gas.Table 3.5 shows the economic cost of development in line with the principlesdiscussed in Chapter II.

Table 3.5: SUMMARY OF RECOMMENDED DEVELOPMENT OF GAS FIELDS(1994 to 2004)

Region Present New Gas Incremental Total EconomicAvailable. Supply Consumption Investment CostSupply La (BCF) Base Case ($ millLon)/b ($/ MCF)(BCF) (BCF)

E. & C. Java 0 2,772 2,452 1,759 2.25West Java 800 2,240 2,219 2,032 2.34S. & C. Sumatra 650 1,470 1,437 653 2.12North Sumatra 340 283 281 144 2.24East Kalimantan 675 1,590 1,464 806 2.08

Total 2,465 8,355 7,853 5,394 2.25

JA The present supply will meet the present level of consumption. Newi supplyis to match incremental consumption during the ten year period.

,b The total investment, in 1991 dollars, includes the cost of the followingtransmission lines: East and Central Java - $575 million including $172million for transmission to Semarang; West Java - $15S millLon; South andCentral Sumatra - $251 million; North Sumatra - $4S million, andKallmantan - $44 milllon (it is assumed that Kalimantan gas wlll be usedinternally, and not transmitted to Java).

Sources Mission estimates

3.39 It will be seen that except in North Sumatra, where the base costrequirement will not be met (unless reserves from Mobll operated fields can bedrawn on), Ln all other regions the base case gas requirements will be met withinthe limits of the economic costs as above and the netbacks to gas in the main enduses as descrlbed Ln the next chapter.

3.40 Some Lmmedlate steps will have to be undertaken for the executLon of theten year program of gas fLelds exploratLon and development proposed above.

- Confirm that the fLelds LdentifLed for development have the reservesand re-categorize the reserves to proven by appraLsal drilling,production testlng and other measures; prepare techno-economicstudies for development. Key operators Lnvolved are Pertamina forEP Units Ir and III, Ln South Sumatra and West Java, respectively,and ARCO (Kangean field, offshore East Java).

- Draw development plans for draLning the ldentified fields Ln aperiod of ten years; ARCO operated west Java fields could declLneafter eleven years and ARCO operated Pagerungan fLeld appears likelyto have a plateau of twelve years, productLon lLfe.

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Upgrade the infrastructure to transport higher volumes of gas,examplect possible addition of compression equilpmnt to the pipelinefrom Pegerungan to Surabaya to onable more gas being carried,looping of sections in the west Java transmisclon system, continuingreplacement of weaker pipeline sections in south and north Sumatra.

Prepare a contingency plan to bring Natuna gas in 2003 toJava/Sumatra, examine alternatives for transport such as shipping asLNC or carrying gas by pipeline.

Examlne alternatives to supplying Java if field development programsin view do not yield adequate results; should a gas grid extend fromeast/ central to west Java or should gas be transported fromSumatra?

3.41 Reaional Analysis of Available Gas Suotlies. The techno-economic analysisof the groups of fields recommended for development or already under developmentin east and central Java is shown in Table 3.6.

Table 3.6: TECHNO-ECONOM!C ANALYSIS. EAST AND CENTRAL JAVA GAS FIELDS

InvestmentiS Million)

Operator Field Supply Field Pipeline AICMMCFD Development to Shore (S/MCF)

Pertamina (Onshore fields) 80 106 - 1.16

ARCO Pagerungan La 392 373 420 1.18 /c

Rodeco RE-5 /b 40 110 20 1.57

Mobil SD LA 150 360 le 1.28

ARCO Terang ld 80-100 82 La 0.58

Mobil MD /d 80-100 116 /e '0.74

/a A contract has already been executed for this field. Transmission tolandfall is not part of PSC and a fee has to be paid by ARCO. Theinvestments shown here are those that will be undertaken in the future. Inthis contract, the average price at the field is estimated to be aconstant S 1.66/ MCF in the initial years of the contract.

/b A contract has already been executed for this field.

LI This AIC is low because substantial expenditures have already beenincurred in the past.

Ld To tie in with the Pagerungan-Gresik pipeline,.

Sources Mlssion estimates

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3.42 The techno-economic analysis of the groups of fields re3ommended fordevelopment or already under development in West Java is shown in Table 3.7.

Table 3.7: TECHNO-ECONOM1C ANALYSIS. WEST JAVA GAS _FELDS

Operator Field/Contract supply Investment AICArea (MMCFD) (S million) ($/MCF)

Pertamina EP Unit III/Gr 1 92 202 1.04Onshore

Pertamina EP Unit III/Or 2 210-240 350 0.94onshore

ARCO ARJUNA/1 260 825 1.22Offshore

ARCO ARJUNA/2 137 430 1.54offshore

Maxus Offshore 15-29 70 1.49SE Sumatra

Note: Credits for condensates/propane/butane have not been included.

Source: Mission estimates

3.43 In West Java, the transmission network has to be rehabilitated,strengthened and compressors added. These investments would total to about $155million over 1993-95.

3.44 In South and Central Sumatra, Benuang, Lembak, Beringin, Kuang, Musi-2 andPrabumenang fields in Pertamina Unit EP-2 and Lemtang and Suban fields operatedby Asamera will add to the domestic supply not only in South Sumatra (98 MMCFD),but a portion of the gas (110 MMCFD) could be transmitted to west Java from 1994through a 24 inch diameter 600 km long pipeline. The transmission network inSouth Sumatra has to be strengthened at a cost of about $ 51 million includinginstallation of additional compression. The South Sumatra-Java pipeline isestimated to cost $200 million. Excluding the tariffs involved for use of thesetransmission facilities, the AICs work out as in Table 3.8 in respect ofdevelopment of the fields mentioned.

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Table 3.8: TECHNO-ECQNOMIC ANALYSIS. SOUTH SUMATRA GAS FIELDS

Field/Contract Area Pertamina EP Unit II Corridor

Operator Pertamina Asamera

Supply MMCFD 197-210 so

Investment ($ million) 307 95

Transmission ($ million) ---------------------51------------------

Trunk PipelLne toWest Java ($ million) --------------------200------------------

AIC ($/MCF) 0.71 1.17(excluding trunk pipeline)

AIC (S/MCF) -------------------1.02------------------(including trunk pipeline)

Note: If trunk pipeline to Java is included in the investments of Pertamina andAsamera, the combined AIC works out to $ 1.02/MCF, showing that it iseconomic to transmit gas to Java; only the share of the pipelineinvestments and tariffs have to be agreed between Pertamina andAsamera.

Source: Mission estimates

3.45 Pertamina EP Unit I fields at Kuala Simpang, Serang Jaya, P. Tubuhan Baratand P. Tubuhan Timur in North Sumatra are recommended for development and withan investment of about $99 million are expected to yield a supply of 60 MMCFD ofnatural gas, at an AIC of $1.13/MCF. Mobil operated uncommitted proven andpotential reserves of about 3.5 TCF are presumed as not available for domesticutilization, but kept in custody for export as LNG when the current LNG contractsfor the first three Arun trains expire in 1999. On the other hand, GOI/Pertaminashould investigate Lf a part of these resources may not be applied towards theinterim domestic requirements, and Mobil agrees that it too does not stand tolose in the earlier offtake of a part of the accumulations. The supply availablein north Sumatra without the Mobil operated resources will run far short of thedemand.

3.46 In East Kalimantan, VICO operated Nilam, Badak, Semberah and Mutiaraonshore fields and Total operated Tambora and Handil offshore fields havecapability to deliver all of the additional supplies of gas required -- from 186MMCFD in 1995 to upwards of 400'MMCFD from 2001 -- at an AIC of $ 0.97/MCF,involving an investment of $762 million. Transmission lines would cost anadditional $ 44 million.

3.47 Sulawesi and Irian Jaya have limited needs. But gas supplies (BP and UTPoperated fields in Sulawesi and various small fields in Irian Jaya) are availableto cater to the nascent market that is developing.

3.48 Lono-Term SuoDlV of Gas. In the long-term (2004-2014) the availability ofgas for domestic market will depend upon the gas reserves that can be exploited,the rate at which these are depleted, the commitments for LNG export and the newgas discoveries made over short and medium term (1994-2004). A concerted effortwould have to be made to look for new gas in an aggressive exploration campaign.The incentives that could be offered to the oil companies are examined in ChapterVI.

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IV. NATURAL GAS UTILIZATION

Overview

4.1 The market for natural gas ln Indonesia comprises a wide variety ofexisting and potential end-users. Table 4.1 shows the actual level of gasconsumption in 1990 and the Base Case gas consumption scenario for 1994 and 2004.The volume of gas sold in the domestic markets was around 304 BCF in 1990, overhalf of which was used for feedstock purposes in the fertilizer industry. Steelproduction in West Java utilized around 45 BCF in 1990, while power generationand city gas systems accounted for another 34 BCF. About 33 BCF was sold torefineries and LPG extraction plants. Other small consumers of gas includecement and petrochemical industries.

Table 4.1: NATURAL GAS UTILIZATION IN INDONESIA(BCF)

Xctual Base Case ProiectionsCategory 1990 1994 2004

Export 1,210.9 1,272.3 1,407.9LNG 1,076.0 - -LPG 134.9 - -

Domestic 303.7 742.8 1,202.8Electricity 11.5 151.7 309.6General Industry 22.4 Ia 77.9 319.9Fertilizer 176.2 238.9 296.4Iron & Steel 45.8 50.0 50.0Cement 5.6 5.8 6.1Petrochemicals 9.5 44.6 57.0Refinery/LPG /b 32.7 41.9 47.3Residential 5.7 10.3Other (Duri) 126.3 106.2

Total 1 514.6 2,015.1 2-610.7

Ia includes residential and commercial customers

Source: Mission Estimates

4.2 Two gas consumption scenarios, a Base Case and a High Case, have beenpresented to indicate the medium- and long-term trends in the consumption ofnatural gas under different economic conditions. In addition, a ten-year (1994-2004) slice of the Base Case has been used to assess the adequacy of availablenon-exportable gas reserves to meet the projected level of consumption in themedium-term. The consumption scenarios have been developed from analyses ofmarket conditions, investment plans of the large bulk consumers, and the relativeprices of alternative energy sources. In cases such as power genuration, wherethe fuel choice is also influenced by the consumer's perception of gas supplyconstraints, additional availability of gas at a competitive price is likely toincrease gas consumption beyond the levels projected in the Base Case. The BaseCase scenario assumes non-oil manufacturing growth in excess of 9.0% p.a. throughthe 1990s, and utilizes production profiles and netback value of gas in specificmarkets to project medium and long-term consumption trends. Additionally, thelong-term (after 2004) uncertainty in the economic competitiveness of gas vis-a-vis alternative sources of energy in power generation and steel industries isassumed to be resolved in favor of coal in the Base Case. Since coal is assumedto be the least-cost generation option when compared to exportable gas, noadditional consumption of gas is projected for the power sector after 2004 in theBase Case. The High Case scenario differs from the Base Case in the following

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assumptionss

(i) the non-oil manufacturing sector is expected to grow at 11-12% p.a.Iand,

(Li) exportable gas, instead of coal, is assumed to be the least-costoption for electricity generation, particularly when FGD equipmentcosts are included. Hence, the relative merits of gas vis-a-viscoal in power generation is projected to result in the installationof additional gas-fired plants after year 2000 in the High Case.

4.3 In the Base Case, domestic consumption for gas is projected to increasefrom around 300 BCF in 1990 to about 742 BCF in 1995 and 1204 BCF in 2004. Therate of growth in gas consumption is particularly high in the early years (inexcess of 20% p.a. during 1990-1997) due to the large-scale capacity expansionamong new customers in power and general industry. The primary impetus to theinitial surge in gas utilization comes from the power sector, where gasconsumption is projected to increase from negligible amounts to 151 BCF in 1994and 310 BCF in 2004. After.2004, the utilization of gas in the power sector isprojected to level off since the long-run comparative economics of fuel choiceis assumed to favor coal in the Base Case. Subsequent reticulation of gas toindustrial fuel users is expected to provide a large source of gas utilization,particularly after 1995. The annual consumption for gas in the industrial fuelmarkets is projected to rise to over 300 BCF by 2004 and nearly 600 BCF by 2010.On the other hand, the share of industrial feedstock use of gas, which accountedfor over 76% of domestic gas consumption in 1990, is estimated to drop to 45% by1994 and 33% by 2004. Thus, underlying the rapid increase in domestic gasutilization is the large shift in the structure of gas consumption away fromfeedstock applications and towards fuel use in industry and power generation.

4.4 Policy Issues: The wholesale prices of natural gas to bulk buyers aredetermined by GOI on the basis of Pertamina's recovery of the producer price plusits own delivery costs, and the GOI's policy to subsidize certain energy-intensive industries. The distortions in the structure of gas prices underminethe efficient use of gas in domestic markets. The main issue identified by theEnergy Pricing Review (EPR) is that domestic gas prices "do not, in most cases,appear to cover the economic cost of supply.."l5/. In particular, "thepreferential rates for the fertilizer, steel and petrochemical plants are farbelow the economic cost of supply, particularly if one takes into account thedepletion premium for gas in Java, where most incremental demand is concentratedand reserves are relatively limited."l6/ The GOI intends to link the priceof gas to the economics of the individual fields, rather than the existingstructure of wholesale prices based on categories of usage. The gas consumptionscenarios are developed under the assumption that GOI will promote efficientutilization of gas on the basis of a tariff structure that takes into account theeconomic cost of gas and the consumer's "willingness to pay" (netback value17/).

4.5 End-use Analysis: The large number of existing and potential consumers ofgas in Indonesia reflect the diversity of end-uses to which it can be applied.Hence, a series of end-use case analyses were undertaken to evaluate thecompetitive position of gas when compared to an alternative optLon from aneconomic perspective. The relevance of many consumer-specific factors (e.g.,

15/ Indonesia: Enerav Pricina Review (EPR), Report No. 8684-IND, May 1990, pp iv.

),j/ EPR, pp 15.

17/. The netback value of gas is the maximum a buyer is willing to pay for gasbased on either the price of the next cheapest fuel (adjusted fordifference in capital and operational costs) or the net revenue from thesale of the final product, whichever is lower.

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end-use technology and costs, unit consumptlon, fuel and product prices etc.)calls for a sufficiently disaggregated analysis. In each instance, the economicvalue of gas (as reflected in the netback value) indicates the upper bound of theconsumer's willingness to pay for gas in a particular end-use. Should theeconomic cost of gas be higher than the n-tback value for a given consumer, thenthat particular stream of consumption is not economically viable and noconsumption is assumed to take place.

Power Sector

4.6 For PLN, natural gas constitutes an economic source of primary fuel. Anumber of factors have led to a greater interest in gas-based power generationin Indonesia, among these the recent technological advances which have enhancedthe design, performance and economics of gas-fired comblned-cycle plants, thecleanliness of gas as a fuel, and the shorter construction time of gas-firedpower plants.

4.7 PLN's long term generation plans take into account the possibility of usinghydro, natural gas, coal, geothermal and nuclear power plants as future expansioncandidates. However, nuclear and geothermal are not seen presently as economicaloptions. In 1990, PLN's installed capacity of about 9,100 MW was mainly basedon three major resources - hydro, coal and oil. Oil/diesel accounted for aboutone-half of the capacity with hydro and coal sharing the balance almost equally.There are also a large number of captive plants installed and operated byindustries for their own use with an aggregate capacity of about 7,100 MW, ofwhich almost two-thirds is diesel fired.

4.8 Given the abundance of coal within Indonesia and its econ nic advantageover oil, PLN's future expansion program includes the installation of severalcoal fired steam plants. The coal fired steam plants will be put up by PLN aswell as private entrepreneurs. As for gas, particularly installation of CCPPs,PLN is planning for 4,500 MW of capacity to be commissioned over the next tenyears. The limitation to 4,500 MW is due to the uncertainty about theavailability of greater supply. PLN has already signed a contract with Pertaminafor the delivery of gas to the 1,500 MMW CCPP at East Java. For another 1,500 MWof capacity in West Java, a contract for gas is in the final stages ofnegotiations. PLN would next negotiate a gas purchase contract for CCPP inCentral Java. Beyond these, PLN would plan more CCPPs, as the domestic gasdevelopment program makes progress and more gas is made available. Table 4.2below gives a summary of the Java-Bali system.

Table 4.2: GENERATING CAPACITY IN JAVA-BALI SYSTEM

YMae_ 1990/91 1995/96 2003/04(MW) (MW) (MW)

Steam (Coal) 1,600 3,000 13,800(Oil) 1,400 1,200 900(Gas) 400 600 600

Gas Turbine (Oil) 565 370 40(Gas) 80 80 700

Combined Cycle (Gas) 0 2,360 4,500Hydro 1,965 2,080 3,993Geothermal 140 360 360Diesel 6 6 6

Total §} 256 10 056 24,899

Source: PLN

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4.9 Economic Value of Gas. A common approach to the evaluation of alternativegenerating units consists of the calculation and comparison of unit generatingcosts, i.e., annual capacity charges (Lncluding O&M) and fuel charges at a givenload factor, divided by the annual Kwh generated during the year.18/ Detallsof the calculation are given in Chapter II. Based on the unlt cost comparisonsof alternative generating options, natural gas currently yields a netback valueof about S3.20/MMBTU (in combined cycle power plants) compared to coal as analternative fuel.

4.10 Natural Gas RecuLrements. To sustain generation in gas fired plants inaccordance with the power development program in Table 4.2, the annual gasrequirements are estimated as follows:

Table 4.3: GAS RZOUIREMENTS FOR POVER GENERATION I

Base Case 1992/93 1995/96 2003/04(BCF) (BCF) (BCF)

West Java 25.4 61.6 90.7East Java 37.2 82.4 84.3Central Java - - 71.9North Sumatra 16.1 32.2 32.2South & Central Sumatra 5.0 5.0 1.9Kalimantan 3.8 8.5 12.7Rest of Indonesia /a - 13.9 16.1

total 87.5 203.6 309.8

HLah Case

West Java 25.4 61.4 205.5East Java 37.2 82.4 138.4Central java - - 105.3North Sumatra 16.1 32.2 32.2South & Central Sumatra 5.0 5.0 1.9Kalimantan 3.8 8.5 12.7Rest of Indonesia a- 18.4 30.5

Total 87.S 207.9 526.5

/e Includes Batam, Sulawesi and Irian Jaya.Sources: Mission Estimates.

4.11 Table 4.3 above has presented a High Case scenario as well, which differssignificantly from the Base Case only from 2003/04. The power developmentprogram outlined in Table 4.2 may have to stay firm on fuel mix until 2000 ascommitments for coal fired steam plants have to be made by 1995. After 2003/04,additional use of gas will be determined by the relatlve economic merits ofLnstalling a gas-fired CCPP as opposed to a coal-fired steam plant. In the BaseCase it is assumed that coal is the least-cost option when compared to exportablegas, and no additional consumption of gas in new CCPPs is projected for theperiod after 2004. In the High Case, exportable gas is assumed to remain theleast-cost option vis-a-vis coal, particularly if equipment costs for flue gasdesulfurization is included in the comparison. Hence, gas requirements in thepower sector ie projected to increase to 520 BCF by 2004 as additional 1,200 MWCCPP are commissioned annually from year 2000.

IV/ As for the end-use analysis of other gas markets, the approach is ag&in oneof average or levelized cost analysis.

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Industrial Fuel Use

4.12 Since 1983 the government has undertaken a series of measures to adjust tothe gradual decline in the value of liquid petroleum products by stimulatingindustry to produce more exportable goods. This resulted in average annualgrowth rates during 1983-1990 of GDP at 5.5%, non-oil GDP at 6.2%, and non-oLlmanufacturing at 12.3%. The outlook for the future until 2000 is projected asfollows: GDP at 5.5 to 5.6%, non-oil GDP at 6 to 6.7% and non-oil manufacturingat around 9% p.a. New investments are directed at exports, particularly intextiles, paper, agro-processing and wood-processing industries.

4.13 Spurred primarily by economic growth, commercial energy consumptionincreased on average by 6.8% p.a. in the second half of the 1980s. Industrialconsumption of energy grew by 7.1% p.a. durlng this period. Over half of theenergy consumed by industry in 1990 was derived from liquid petroleum productfuels. Natural gas accounted for 25% of industrial energy, and electrlcityanother 12%. If industrial feedstock requirements are excluded, liquid petroleumproduct fuels account for nearly 90% of energy consumed in industry. This highdemand for petroleum products is largely the outcome of increased production andtransportation of goods and services in the economy, and the current structureof petroleum products prices which encourage growing utilization of petroleumproducts in place of alternative fuels such as coal and natural gas.

4.14 The penetration of natural gas as an alternative energy fuel in industrialmarkets is considered attractive for several reasons. The manufacturing sectoris a rapidly growing domestic energy market in which natural gas carries a highnetback value when displacing exportable fuels. Natural gas users can alsobenefit from lower operation and maintenance cost of energy equipment(particularly when compared to coal), and from the fact that gas-firingeliminates the need to carry fuel inventories. In a number of heat processes gasenjoys additional technical advantages (clean combustion, better flame qualityand ease of use/heat control) that enhance the quality of the end product.

4.15 Economic Value of Gas. Natural gas is expected to compete primarily withfuel oil for general industrial uses throughout the forecast period. The currentuse of diesel oil in stationary combustion is largely a function of the existingdistortions !n its price which, once corrected, should lead to a rapidsubstitue.ion away from diesel oil and towards fuel oil and, if available, naturalgas. The use cf coal in general industry is largely confined to cementproduction where coal enjoys specific technical and economic advantages overalternative fuels, including gas. The possibilities of coal utilization inexisting steam boilers is constrained by the difficulties and high expense ofconverting oil or gas based boilers to coal. Similarly, the use of coal in newboilers or furnaces in industry is constrained by the lack of adequateinfrastructure for coal handling, pulverizing, ash disposal and other fuel-related facilities. Hence, large-scale utilization of coal for steam raising ingeneral industrial markets does not appear likely during the forecast period.

4.16 The netback value of gas in general industry has been estimated for anumber of industries which represent existing or potential consumers of gas, andcover a variety of applications, including steam raising, direct process heatingand cogeneration of steam and power. The relative fuel prices utilized in thenetback analysis are based on international market prices. This assumption isin line with GOI's stated policy to price all fuels at economically efficientlevels. In general, the netback value of gas in new processes range from$3.99/MMBTU to $6.32/MBTU when evaluated against fuel oil, and between $ 5.61-8.91/.MMBTU when diesel is the alternative fuel. The netback value of gas inconversions range from $2.98-3.50/MMBTU, indicating that conversion from oil togas burners may be attractive in some instances (see Annex 4.2 for details).

4.17 tUatural Gas Consumption. In West Java, gas is already supplied in limitedquantitLes to industries through the existing city gas distribution systems. Theutilization of gas as fuel in general industry is projected to grow rapidly inWest Java, from around 17 BCF in 1991 to over 40 BCF in 1994 and 170 BCF by 2004.

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In East Java, a distribution system will be in place by 1993 and the consumptionof gas in industries is projected around 19 BCF in 1994 and 69 BCF by 2004.Outside of Java, gas use has the potential to grow in Medan (North Sumatra) fromaround 5.7 Bcf in 1990 to 25 BCF by 2000. With the development of industrialestates in Batam, and similar proposals for Riau and Palembang areas, theconsumption of gas for general industry in South Sumatra is also expected to growfrom zero at present to 12 BCF by 2004. Some small scope for industrial gasutilization is also foreseen in Sulawesi and Irian Jaya.

4.18 The potential use of gas is highest in the paper industry. It is estimatedto increase from 3.2 BCF in 1990 to nearly 110 BCF in 2004. Over half of thisconsumption is expected to be in East Java where existing plants are activelyseeking gas to replace fuel oil after 1993. The utiliz&tion of gas bymanufacturing industries other than paper is mostly concentrated in West Java.The largest consumers are in the basic metal and textile industries where totalgas consumption is estimated to exceed 120 BCF by 2004, mostly in new plants.Other existing and potential consumers of gas are in food processing (e.g.,sugar), mineral products, plastic products and other small and medium-scaleindustries.

4.19 Cement production in Indonesia is based on coal, although some gas is usedto produce special white cement. While natural gas use is technically feasible,it is cheaper to use coal under the current fuel prices. There is also anexisting government decree mandating the use of coal in cement production. Thenetback results indicate that the industry can afford gas only at less than$2.00/M)BTU instead of the current price of $3.00/MMBTU. The use of gas is,therefore, limited to the production of white cement at three cement plants inWest Java.

Feedstock Aoolications

4.20 Feedstock uses of gas currently account for over 70% of domestic gas salesin Indonesia, although this share is expected to drop to 33% by 2004. Thelargest source of feedstock use of gas is the fertilizer industry, with six gas-dedicated plants whose total consumption is about 180 BCF annually. In Java, thesingle largest customer is the Krakatau steel plant which uses gas as feedstockin iron production. Natural gas is also used as the primary feedstock in avariety of chemical products, most prominently methanol.

4.21 Urea production in Indonesia has benefitted from the availability ofnatural gas at low preferential rates to the industry.20/ Natural gas soldto the fertilizer industry is priced uniformly at $l.00/MMBTU,21/ thusindirectly subsidizing urea production in some locations. In particular, theprice of $1.00/MMBTU is lower than the economic costs of supply in Java andimposes a major constraint on the availability of additional gas for fertilizerplants in Java, which is otherwise a favorable location for new urea capacity.Similarly, the price of gas charged to PT Krakatau Steel ($ 0.65/MMBTU forfeedstock gas and $ 2.00/MMBTU for fuel) is far below the economic cost of supplyin West Java. It is assumed that incremental supply to these consumers will bedetermined by the price of gas, which would have to be set at a level in linewith the economic cost of gas supplies.

4.22 Economic Value of Gas In primary feedstock applications, the netback valuemay be treated as the cost of another feedstock, or the price that could be paidfor gas that would result in a manufacturing cost less than the cost of importingthe product. The netback value of gas in fertilizer, chemical and steelproduction have been evaluated against the import option. The netback value of

20/ The possibilities of gas application in fertilizer products other than ureaare minimal and therefore not considered here.

21/ With the exceptlon of the recently negotiated price of $2.00/MCF for gas tothe Gresik plant in East Java.

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gas in fertilizer production has been estimated for sites with existinginfrastructure, using urea price assumptions outlined in Annex 4.2. The n-tbackvalue of gas is estimated to be around $2.62/MCF when evaluated against theprevailing international price of urea fertilizer. The estimated netback valueof gas in iron and steel production is $2.49/MCF. Given the variety of products,the netback estimate has been calculated only for methanol which accounts for thebulk of gas sales in the petrochemical sector. In methanol production, gas isestimated to have a netback value of $2.47/MMBTU against imports. This netbackvalue of gas is below the price of $3.0/MMBTU to the industry, thus limitingextensive use of gas.

4.23 Natural Gas Consumvtion. The domestic fertilizer industry has played animportant role in Indonesia's successful drive to expand foodgrain production andmaintain rice self-sufficiency. At present, there are six fertilizer companiesoperating 13 plants with a combined capacity to proditce 6.8 million tons per yearof fertilizer products (mostly urea and small quantities of ammonia sulphate andTSP). In addition to meeting domestic requirements; the industry has also beensuccessful in marketing surplus urea in exports. The production of urea inIndonesia grew at a rate of 10% per annum between 1980 and 1989, and is estimatedto grow at an average rate of 5% p.a. over the next ten years. The productionincrease will be achieved through additional investments for plant optimizationand efficiency improvements, as well as capacity expansion at existing sites.Urea production levels are projected to rise from around 4.6 million tons in 1990to over 9 million tons per year by year 2003/04.

4.24 The fertilizer sector accounted for over half of the natural gas consumeddomestically (176 BCF) in Indonesia in 1990. The average gas use over the periodi,8O-1989 has been estimated to be around 34-38 MCF/ton of urea produced. Futuregas consumption per ton of urea is likely to be lower (21-26 MCF/ton based onresults at Kaltim III) because of efficiency improvements and new technology.The Base Case projections point to sharp increase in gas requirements in thefertilizer industry over the next five years as a result of capacity expansion,replacement and plant optimization investments at PUSRI, Kujang II, IskanderMuda, Kaltim and Gresik. Three new units will also be added between 2000-2004.Following these investments, production capacity is expected to remain fairlyconstant for the next 10 years. Gas consumption in tha Base Case increases fromto 240 BCF in 1995 and 290 BCF in 2004. In the High Case scenario, the inclusionof plans for additional capacity expansion in Kalimantan imply that thefertilizer industry would consume nearly 330 BCF by 2003/04.

4.25 The effect of changes in the price of gas is likely to be limited in thefertilizer industry. This is particularly true if the adjustment in the priceof gas is carried out in conjunction with the removal of price controls in thedomestic urea markets. The ongoing dialogue between the Bank and GOI has focusedon making the fertilizer sector more responsive to market signals by graduallyphasing out all subsidies. The price of natural gas, in turn, would be correctedin conjunction with the adjustment of ex-factory urea prices to export paritylevels. Thus, little or no change in production levels, and gas consumption, isexpected as a result of changes in gas prices, particularly if the domestic ureaprice controls are relaxed.

4.26 The iron and steel industry in Indonesia comprises one large producer (PTKrakatau Steel) and several small factories.22/ The steel industry is a majorconsumer of energy, with the largest share of energy consumed during theproduction of iron. The current production capacity at Krakatau Steel is 2.0million tons per year (tpy) based on four HYL I units, although the gas supplyconstraints have led to the under-utilization of existing capacity. Efficiencyimprovements at the existing facilities is estimated to increase production from

21/ The primary use of gas is in the production of sponge iron at Krakatau Steeland the proposed new plant at Ispat Indo. This section estimates gasrequirements for only these two plants.

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1.3 million tons in 1989 to 2.5 millon tons in the year 2000, while using thesame amount of gas. Additional investments in new capacity, based on either gasor coal, is expected to further increase production to over 5.0 million tpy inthe same period.

4.27 The Base Case projections are prepared under the assumption that there willnot be any additional consumption of gas on the basis of investments in new gas-based facilities. The total annual consumption of gas (including thermal andpower uses) in estimated to remain between 45-50 BCF until the end of the plantlife of existing processes. If the coal option proves viable, an additional 3.0million tpy of steel products will become available in 1995. This will not onlyhalt any further increase in gas consumption, but probably lead to a gradualphasing out of gas use at Krakatau Steel. In the High Case scenario, it isassumed that additional gas requirements for MIDREX-based capacity at KrakstauSteel and Ispat Indo materialize within the context of an economically efficientprice of gas, raising total gas consumption to 138 BCF by 2003/04.

4.28 Natural gas can be utilized in the production of Detrochemical Droductsas feedstock and energy source. The two main applications of natural gas are (i)in the production of methanol from methane, and (ii) the ethane, propane andbutane components to produce such products as ethylene and propylene. Naturalgas requirements are estimated for 27 petrochemical products by multiplyingforecast output by estimates of gas use per unit of output. At present, theprimary use of gas iY in the production of methanol in Bunyu, East Kalimantan.A new methanol plant is proposed for Bontang, which if installed may render Bunyuoperations obsolete. Of the 45 BCF of gas consumption projected for the industryin 1995, about 22 BCF will be used at the proposed methanol plant at Bontang, andan additional 10 BCF could used at the methanol plant at Bunyu.

Other Uses

4.29 Residaential: The residential and commercial market for natural gas islimited to those customers connected to PGN's city distribution systems. Theresidential consumers consume less than 0.1% of the total gas produced inIndonesia. In light of the small share of the market and the high cost ofconnecting individual customers to the supply system, the residential andcommercial market is expected to offer little or no additional gas loads comparedto the larger users in power and industry. The prospect for additional gas usein residences will depend on (a) the social premium attributed to gas because ofits cleanliness and ease of handling; and, (b) the magnitude of consumer anddistribution costs. In the absence of heating needs, the quantities of gas usedin households are quite small, and the total cost of supplying the gas areprohibitively high when compared to the alternate fuel.

4.30 Refineries a LPG Plants: There are eight refineries in Indonesia, withtotal installed capacity of around 830,000 barrels per day. A new export-oriented refinery (EXOR I) is to be built by 1993 in West Java to process anadditional 125,000 barrels of crude/day. Over 75% of LPG production (over 2million tons/year) takes place in the two plants constructed at the LNGfacilities at Arun and Bontang. LPG production from the other plants has beenon a gradual decline from 878,000 tons in 1984. The gas use in refineries/LPGplants is projected to increase from 32.7 BCF in 1990 to 41.9 BCF in 1994.

4.31 Transport Fuel. Natural gas lends itself to use in compressed form (CNG)as fu-; iLn motor vehicles. In USA and Europe, CNG has been in use for over adecade. In Indonesia, CNG was introduced on an experimental basis in 1986 withconversion of a few taxis to dual fuel firing-gasoline and CNG. At the end of1990, about 500 taxis in Jakarta had been so converted and five CNG servicestatLons were in operation. The conversion kits for the vehicles were importedas also the equipment at the service stations.

4.32 LEMIGAS carried out a study for the Bank in November 1991 with a view toassessing the scope for expansion of CNG use if concerted efforts were to be madefor the promotion of CNG. The study was confined to Jakarta with its

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concentration of motor vehicles numbering about 0.8 million not includingmotorcycles. These vehicles consume about 8.2 million barrels of gauolLne/dieseloil per year. Surveys undertaken by LEMIGAS, based on consumer responses,availability of land for service stations and other factors showed that at bestabout 0.3 million barrels of gasoline/diesel could be replaced by CNG over a 5-year period and a further quantity of about 0.3 million barrels ofgasoline/diesel over the succeeding five years. This would translate to gasrequirement of about 25 MMCFD of natural gas at the end of 5 years, it will beseveral more years before CNG would penetrate the market, given the need for aCNG service station to dispense to a certain minimum number of vehicles, to stayin business and the range of less than 100 miles that a vehicle will operate withone fill of CNG.

4.33 An assumption made in projecting the figures of CNG consumption in Jakartais that the financial prices of the relevant fuels will be revised to attaininter-se parity as prevails in respect of their economic prices. Primarily theprice for diesel oil has to move upwards. On economic prices, the data from theLEMIGAS study indicate that in Jakarta, CNG will be slightly more economic foruse in transport than gasoline and marginally more economic than diesel oil.Among various end uses of gas, CNG does not appear to have a high economicpriority. A more detailed economic analysis of all costs involved, namely inconversion of vehicles to use of CNG, in operation of CNG service stations andin PGN's distribution of natural gas to the CNG service stations is howevernecessary. This should be undertaken by GOI/MIGAS as soon as possible.

4.34 While expanded use of CNG is recommended, subject to verification of theeconomic advantages, it should be noted that it will not make a significantdifference to the consumption of petroleum products in the transport sector.Indonesia consumed 78 million BOE of gasoline and diesel oil in the transportsector in 1990. Expansion of CNG use is likely to result in replacement of about0.6 million BOE of this consumption in course of time as explained in para 4.32.

4.35 CNG is a desirable fuel to use in motor vehicles from the environmentalaspect. It is superior to gasoline or diesel oLl particularly in a city likeJakarta with its heavy traffic and pollution, as shown in Table 4.4.

Table 4.4: AIR EMISSIONS IGRAMS/MILE)

Gasoline Diesel Nat. Gas

Hydrocarbons 0.68 1.15 0.25Carbon Monoxide 3.63 2.55 0.10Nitrogen Oxides 1.37 1.95 0.50Sulfur Oxides 0.45 0.80 -

Suspended Particulates 0.06 0.70

Source: LEMIGAS

Concluoionq

4.36 The netback value in each market sector has been compared with theeconomic cost of gas supplies to assess economically viable level and structureof gas consumption in each region (see supply-consumption balances in Annex 4.3).The use of gas as fuel in general industry yields. the highest netback values,which are greater than the economic cost of all gas supplies (non-exportable andexportable). In contrast, the netback value of gas in feedstock applications inchemical and steel industries '.s close to the economic cost of gas in mostregions. The estimated netback value of $2.62/MMBTU in fertilizer productionimplies that additional gas consumption is economically viable when evaluatedagainst the economic cost of non-exportable gas ($2.08-2.34/MCF), but not so whenevaluated against the economic cost of exportable gas ($3.7/MCF). In the event

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implies that addltLonal gas consumptlon la economically viable when evaluatedagaLnst the economic cost of non-exportable gas ($2. 08-2.34/MCF), but not so whenevaluated agaLnst the economic cost of exportable gas ($3. 7/MC). In the eventthat dometlc gas requlrements are largely met by exportable gas supplies after2004, additlonal use of gas in fertilizer productlon wlll be economlcallyjustified only ln areas where gas Le supplled at a cost below the netback valueof $2.62/MMBTU (e.g. Kalimantan). Slmllarly, the netback value of gas Ln steelmanufacture is marginally above the economic cost of gas in West Java. Furtherefficiency improvements may somewhat Lncrease the gas netback in existingfacilities since most of the Lnvestment costs are already sunk. However, ln vliwof the low netback value vie-a-via the economlc cost of exportable gas, theproposals to construct addltlonal gas-based KIDREX facliltles needs to becarefully evaluated agaLnst the possibliLty of lnvestLng in a dlrect or indlrectreductLon process using an alternative fuel. The netback value of $2.47/MKBTUfor gas in methanol productlon is far below the prlce of $3.00/MMBTU to theLndustry, thus limlting extenaLve use. Methanol productLon is cokcentrated lnKalLmantan where relatively cheaper gas is available. Finally, the netback valueof gas in power generation is estimated at $3.20/MMBTU when estimated against thecoal optlon. ThLs figure Lndicates that non-exportable gas, wlth economlc costat or below $2.34/mcf is an attractlve fuel for power generatlon ln the medLum-term. However, when compared against the coat of supplylng exportable gas,natural gas may not be the least cost option for power generation unless flue gasdesulphurizatLon equipment costs are lncluded.

Table 4.6: NETBACK VALUE OF GAS L/

AlternatlveCategory Optlon $/MOBTU

General Industry Fuel oil 3.99-6.32Power Generatlon Coal 3.20Iron & Steel Imports 2.49Fertillzer Imports 2.62Methanol Imports 2.47Cement Coal 1.94

A/ Assuming 1000 STU in one cu ft of natural gas.

Source: Mission Estimates

4.37 Incremental natural gas consumptLon for the perlod 1991-2004 has beenestimated on an annual basLi for all consumers whose netback values in gasconsumptLon exceed the economic costs of llkely gas supplies. The annual phasLngof Lncremental gas consumptLon has been projected on the basLi of (i) annual gasrequLrements to meet the year-by-year productlon plans among the bulk gasconsumers, (LL) annual projections of growth of output in the manufacturlngLndustrLes, and (LLL) the projecled level of substLtution of oll products bynatural gas ln each year of the projection perlod.

4.38 Total annual domestic consumption of natural gas in the Base Case isestimated to Lncrease from around 300 BCF in 1990 to over 1,204 BCF by 2004. Thecumulative domentlc consumption of gas is projected to reach 13 TCF by 2005 and25 TCF by 2015. The cumulatlve gas consumption in the Hlgh Came is around 16 TCFby 2004 and over 40 TCF by 2015. The largest share of this increase in gasconsumption is accounted for by general industry and power sector. Thus, theshare of natural gas used Ln general industry has the potentlal to increase frompresently negllgible amounts to 25% of total domestic consumptLon by 2004 and 32%by 2010. similarly, the power sector has the potentlal to account for over 25%of total domestLc consumptLon by 2004. The HLgh Case estimates Lnclude a largeincrease in feedstock requLrements for capacity expansions fertlilzer and steelindustrLes in the late 19908.

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V. POLICY AND INSTITUTIONAL ISSUES

5.1 Until recently natural gas, apart from LNG, has been treated as a by-product of oil exploration. Domestic gas sales have mainly developed as a resultof the GOl directing Pertamina to supply gas to a few major industries at a pricebelow its economic cost. Fertilizer, steel and cement industries dominate thedomestic utilization of gas, and Pertamina's monopoly on gas trading andtransport has met their requirement, but the pricing system and the institutionalarrangements are not conducive to the expansion of supply to meet the growingrequirements of fuel for power generation and general industry. According toconservative estimate (Annex 4.1), the total domestic requirement for natural gasbetween the year 1990 and 2004 could increase fourfold to about 1200 BCF with theshare of power and general industry increasing from about 10% to 60%.Pertamina's operation neither meets the potential domestic gas requirements, nordoes it plan to do so.

5.2 A concerted effort Is needed to overcome the current constraints toexpanded domestic utilization of natural gas. This effort will not be successfulwithout structural and institutional changes to provide producers and consumerswith adequate incentives. Further, producer perception of the domestic marketmust change. At present, the main interest of the PSC operators in petroleumproduction is limited to oil and LNG. PSC operators need concrete assurances onfair producer prices and assured domestic offtake in order to motivate them toproduce more gas for the domestic market.

Institutional Asoects

5.3 In Indonesia, Pertamina has been successful in developing the LNG exportmarket, but less so in expanding the utilization of gas in the domestic market.Its preoccupation with PSC operators, oil and LNG exports and a variety of othertasks has prevented it from making the major efforts needed to develop thedomestic sector. The institutional framework is, therefore, lacking forefficient domestic purchases, transmission and sales of gas and the necessaryplanning, management and operation of an expanding gas market.

5.4 An entity must be created that focuses specifically on the development ofthe domestic gas market. This entity, in this report referred to as the GasTransmission and Marketing Entity (GTME), would need to undertake the purchaseof gas from the producers, gas transmission, and gas sales to bulk buyers. Theseactivities, along with associated planning and coordination for the domestic gassector and marketing and market development activities, should be GTME'sexclusive focus.

5.5 The cor's planning and regulation of the domestic gas sector is alsoinadequate. To ensure efficient and coordinated development of the sector, MIGASwould have to enhance its capabilities in medium and long-term planning, legaland technical expertise, safety regulation and other areas. As in the case ofPertamina, most of MIGAS's resources are now concentrated on oil and LNG and theimportant export market.

Pricing of Gas for Domestic Suovlv

5.6 Producer Prices. Under the current GOl policy, producer prices for naturalgas are determined by negotiations between Pertamina (as the agent of GOI) andindividual production sharing contract (PSC) operators based on the costs ofsupply, the rate of return requirements, and the market for gas in specificlocations. The net price received by the PSC operator, is fixed in US dollarterms for the duration of the contract and determined by the terms of the PSC,under which the profits from gas production (net of exploration, development andoperational expenditures) are split. On this basis, the producer price of gas isdifferent for each PSC.

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5.7 The issue is whether this pricing policy will provide the needed incentivesfor the several PSC operators, who have discovered gas or highly promisingprospects to invest more funds to develop the relevant gas fields for supplyingthe domestic market. While a recent agreement 2J/ may serve as a good model,there are still concerns that would have to be addressed to ensure thecooperation of the oil companies to expand domestic utilization of gas. First,PSC operators do not find a fixed price attractive, even if it is in US dollars,especially when the contract life is long. The operators/producers tend to seeka high initial price to compensate for future inflation and other risks and ahigh initial price could make it difficult for gas to compete with other fuelsand, thus, reduce the market.

5.8 The second concern of the PSC operators relates to the GOI policy ofdetermining the price for gas based on the economics of field development. ThePSC operators find this approach to be inconsistent with the notion that pricesshould be determined on an arms' length basis, as in the case of LNG exports.The PSC operators explore arid develop large fields for LNG export, accepting themarket risks so the price fotmula for LNG obviously provides adequate incentives.In the case of non-exportable gas, where the fields are not proximate to largefields, the issue is whether the principle of linkage with international pricesof alternative fuels should be followed. In the domestic market, petroleumproducts as well as coal are expected to be sold at economically efficient pricesbased on border prices, except limited volumes of non-exportable coal which willbe priced at long run marginal cost. If the producers are paid a proportion ofthe efficiency prices of the alternative fuels, they would have a clearperception of the gas price they will receive and this would provide theincentive for gas exploration and field development.

5.9 Further, under the present pricing policy, the operators have to takeexploration and drilling to advanced stages, appraise the field, testingproduction and assessing the reservoirs before they can begin meaningfulnegotiations with GOI on the gas price. However, the PSC operators are reluctantto spend substantial funds on exploration and field development without knowingwhat gas price they can expect.

5.10 In order to overcome these constraints to the development of the domesticgas market, GOI should change its producer pricing policy. The recommendedchanges are discussed in Chapter VI.

5.11 Consumer Prices for Enerc'v Products. The issue of consumer prices forenergy products was extensively analyzed in the World Bank's Energy PricingReview (Report No. 8684-IND, October 15, 1990), which argued for the adoption ofefficiency pricing as the basic guideline for determining consumer prices forenergy. This principle requires that prices be set above a floor defined by theeconomic cost of the fuel, and that any deviation of prices from economic costsneeds to preserve their relative ranking, e.g., if the economic cost of dieselis greater than the economic cost of fuel oil, then the consumer price of dieselshould be greater than the consumer price of fuel oil. Annex 5.1 summarizes theimportant recommendations of the report and the current status of affairs.

2/1 In this contract, which is in the final stages of negotiation, thetransmission to the landfall point is to be done by the operator as part of thePSC. The price to consumers is to be fixed as one rate, to remain constant indollar terms over the contract perLod. The absence of a price escalation clauseis sought to be mitigated by special add on to cost recovery before profit sharesare worked out. There is also a reopener clause that will provide for a reviewof the price when stated changes in circumstances have taken place. Theunderstanding reached between the operator and GOI/Pertamina seems to besatisfactory to both the parties, in that the operator expects an acceptable rateof return and GOI, a share of revenues apparently in excess of $1.20/MCF whichwill adequately cover depletion premium and taxes as leviable on the operator.

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5. 12 At present, the consumer prices of dissel and kerosene continue to be belowtheir efficiency price levels even after the price increases instLtuted in August1991 (see Annex 5. 1). Slnce diesel and kerosene compete with gas as industrialfuels, gas will be at a disadvantage when the gas consumer price is not accordlngto the princlple of efficiency prLcing, while dLesel and kerosene consumer prLcesare below thelr efficlency pric- levels.

Reaulation

5.13 In oll, gas and geothermal activities, Health, Safety and Environmentalsupervilsion are the responsibility of the Directorate of Oll and Gas EngineerLngwithin MIGAS. There ia a comprehensive legLlation authorlzlng the Directorateto carry out its actlvltles. As mentloned (para 5.5), most of MIGAS's attentionhas been on oil and LNG operations. As the domestic gas market expands, specificregulations and practlces would have to be developed and MIGAS's regulatingcapabilities would have to be strengthened to ensure that adequate envlronmentaland safety standards are followed and that the GMTE operates efficiently wlthinreasonable margLns between producer and user prices and provides reasonableaccess to the plpeline system.

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VI. STRATEGY FOR EXPANDED DOMESTIC USE OF GAS

6.1 Indonesia's oil/LNG current account balance is esk _.wted to decline from$4.2 billion in FY1992 to $1.9 billion by FY2001, mair'y due to increasingdomeotic consumption of petroleum products.23/ While it is possible that newoil discoveries will mitigate this decline, the exploitation of Indonesia's lowcost non-exportable proven undeveloped and potential gas reserves for replacinghigher value exportable liquid petroleum products in domestic consumption withthis gas, will imply a significant boost to the balance of payments. Such gascould, between 1994 and 2004, displace petroleum product fuels amounting to about900 million barrels of oil on an energy equivalent basis with an estimated valueof $17.5 billion thus increasing potential oil exports by about $1.5 billion ayear and improving the oil/LNG current account balance from $3.7 billion to $4.7billion in FY1996 and from $1.9 billion to $3.6 billion in FY2001.24/ The neteconomic benefit from the use of this non-exportable gas in industry and powergeneration, between 1994 and 2004, would amount to approximately $10 billion.However, the strategy to reach this simple objective would have to address anumber of complicated issues. First, to justify heavy investments and quicklyachieve an economic utllization of the gas transmission system, a substantialportion of the gas would initially have to be used for power generation even ifits use in general industry would produce higher economic benefits. Secondly,the uncommitted non-exportable reserves (8.4 TCF) would only be adequate forabout ten years of projected consumption. The bulk buyers would seek assurancesof longer term (e.g., 20 years) gas supplies before committing themselves tocostly investments Ln distribution systems and gas fuelled plants. Thirdly, thePSC terms for gas and the current producer price system do not provide adequateincentives for PSC contractors to develop proven gas reserves and, even less so,to explore for new ones. Finally, an adequate institutional and regulatoryframework would have to be created for the efficient development and operationof the domestic gas sector. Such a framework should provide a suitableenvironment for producers, transporters, distributors and consumers of gas andgive adequate incentives to coordinate their activities.

Domestic Gas Supolies

6.2 The uncommitted, non-exportable proven undeveloped and potential reservesof about 8.4 tcf would satisfy projected new domestic consumption for about tenyears, or up to about year 2004. Given adequate incentives to the PSC operators,the prospects are very good to find new gas fields during this period and thusadd to the reserves. This would be necessary to provide the potential gas userswith assured gas supplies for an adequate period, e.g., 20 years. Theexploration for gas in and around Java and Sumatra, therefore, assumes urgent andcritical importance. Since the prospects for finding several small and mediumstructures are bright, oil companies must be encouraged to explore aggressively.The pricing and PSC terms for gas are, therefore, of special relevance.

6.3 Exploring for hydrocarbons always carries with it risks of failure. Hence,the GOl must have a fall-back strategy for long-term gas supply particularly ofJava and Sumatra. Current gas reserves in Kalimantan and Natuna (to bedeveloped), which can be exported as LNG, are vast. A large volume isuncommitted beyond present contracts, which expire in stages between 1999 and2010. Before committing new quantities to future contracts, GOl should reviewthe long term domestic needs and the costs and benefits of using exportable gasLn the domestic market.

23/ "Indonesla: Developing Private Enterprise", World Bank Report No. 9498-IND,May 1991.

jj/ Natural gas would primarily substitute fuel oil and diesel oil in industrialheat applications. The prices of oil products are given in Annex 5.1. Petroleumprice projections for the perLod 1992-2004 are based on the World Bank petroleumprice forecasts Ln the Ouarterlv Review of Commodity Markets (December 1991).

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6.4 If, in spite of the above, gas shortages develop, the gas supply to thepower sector should be limited to meeting the peak generation requirements, andgas thus saved supplied to general industry. As shown by the netback estimates,gas use in general industry has a higher economic value than in power generation.

Pricina Strategv

6.5 To encourage increased exploration and development of gas for the domesticmarket, the producer pricing system should be changed to reflect theinternational prices of fuels displaced by gas. The producer price should behigh enough to make the development of existing fields, as well as theexploration for new gas, attractive to the PSC operators. The present system canbe described as a cost plus system, which has no relation to the internationalprice of fuels competing with gas. While this system may be appropriate todevelop already proven gas finds, it does not provide the necessary incentivesto the PSC operators for. new gas exploration. The main growth for gasconsumption will be in the power sector and in small and medium industry,replacing coal and diesel in the power sector and replacing mainly fuel oil inthe industry sector. A producer price formula could, therefore, peg the gasprice to a mixture of coal and fuel oil prices in the international market. Theshares of the fuels in this formula should depend on the gas market and would besubject to negotiations between PSC operator and GTME. The PSC operators areused to this type of gas pricing and its introduction is likely to acceleratefield development as well as exploration for new gas.

6.6 In regard to the GTME's margins for transmission, the differences betweenthe producer price and the price paid by the buyers of gas should allow GTME tocover its operating costs, a reasonable return on its operations and asubstantial portion of new transmission pipeline investments, as those will bethe bottleneck for the development of the domestic market in the next few years.GTME should independently negotiate the price and conditions for buying andselling gas, without undue intervention by GOI. If GOI decides to subsidizecertain gas use, this should be done through direct subsidies to the gasconsumers not via low gas prices, which would lead to inefficient use of the gas.

6.7 The bulk buyer price should be attractive compared to competing fuels andyield sufficient revenue to GTME to fund the development of the domestic gasinfrastructure. This could be achieved by a pricing formula of the followingtype:

- For the industrial market, negotiate a gas producer price equivalentto 65-75% of the international price of heavy fuel oil. Such aprice should be attractive to the producers and 'the '25-35%difference between fuel oil and gas prices would permit adequatemargins to GTME/PGN as well-as a competitive retail price of gas forindustrial consumers;

- For the power generation market, negotiate a gas producer pricelinked to the international price for coal taking into account theratio of thermal efficiency of a coal fired power plant and a gasfueled combined cycle power plant. In this case, the cost savingsin building a combined cycle power plant instead of a coal firedpower plant should provide ample incentives for price negotiations;and

- maintain the consumer prices of fuels competing with gas at or abovetheir border prices to ensure economically efficient pricecompetition between fuels and adequate incentives to convert to gas.

Institutional and Reaulatorv Asuects

6.8 Supply of gas from the fields to the market could be organized through (a)direct purchase by the bulk buyers from the producers or (b) through anintermediate organization, i.e., the gas transmission and marketing entity(GTME). In the first option, the transmission infrastructure would either be

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owned and operated by the seller/buyer (in accordance with gas purchaseagreement) or it would be owned and operated by a third party with seller/buyerpaying a toll fee covering the third party's costs and return on investment. Inthe second option GTME would own and operate the transmission infrastructure,purchase gas from the producers and sell it to the bulk buyers.

6.9 The direct purchase arrangement would initially maximize competition andminimize the transmission cost but in the long-run it would discourage thedevelopment of an efficient transmission system. The sellers and/or buyersowning the transmission system would have it sized to meet their own needs andwould be little inclined to invest in a larger size pipeline to support marketdevelopment and efficient expansion of the system. Additionally, in case of anextensive and expanding transmission system it would be increasingly difficultto allocate the transmission cost among the various users with any reasonableaccuracy, which would lead to the erosion of users' confidence. Even if thetransmission system was owned and operated by a third party charging toll feecovering costs and return- on investment, efficient planning of the systemexpansion would be very difficult as the owner/operator would have little controlon the producer/buyer negotiations. In the second option, with the GTME beingitself a buyer and seller of gas, it would have considerably more control onefficient design and expansion of the transmission system and would have a vestedinterest in market development. It would, however, be a natural monopoly whichwould necessitate regulating its costs and profits. An efficient policy forintroducing competition to GTME would be to permit bulk buyers to purchase gasdirectly from the producers and obligating GTME to transport these volumes atreasonable cost which, if disputed, would be determined-by the regulator.

6.10 In Indonesia, with a multiplicity of producers and a very large number ofpotential consumers, phased development cf an extensive transmission would berequired. Additionally, elementary transmission systems already exist in WestJava, South Sumatra and North Sumatra (worth about $200 million in replacementcost) which would have to be upgraded, expanded and integrated (at a cost ofabout $600 million) into a common grid to ensure efficient operations andsecurity of supply. It is unlikely that such a transmission system will beefficiently developed through random direct purchase arrangements between thebuyers and the producers. On these grounds as discussed above, establishment ofGTME would be the best way to bring about a rapid and rational development of thedomestic gas transmission network.

6.11 The gas industry, in most countries has developed either from privateinitiatives and competition or from government policies to replace other fuelswith gas. The former situation was almost unique to North America, but is nowemerging in Europe as well. Elsewhere, the trade and transport of gas are mostlygoverned by public planning and usually managed by one major gas-oriented entity.In some countries, this entity has evolved from diverse utilities (for exampleBritish Gas), or from oil companies (for example Gasunie of Netherlands, PetronasGas of Malaysia, Sui Northern Gas of Pakistan, GAIL of India). Common to all ofthese examples is the concept of coordinated planning, one major gas entity andgovernment regulation ensuring efficient planning and optimal development. Asimilar development approach could be adopted in Indonesia, involving thecreation of an entity (GTME) with exclusive focus on the domestic market. Sinceall the bulk buyers of gas are currently government-owned and the government alsohas a major share of the gas production, it would be difficult for a privatesector company to initiate the development of domestic gas sector. GTME would,therefore, need to start as a public sector organization. Its longer termcharacteristics should, however, include:

- efficient operations on a fully commercial basis with adequateregulatory controls and audits;

- flexibility to accept private as well as public funds for itsinvestments in the form of equity contributions, joint venturesand/or loans, to reduce the burden on the GOI budget; and

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- ability to generate internally and retain sufficient funds to makean adequate contribution to capital expenditures, after payingoperating expenses and debt service.

6.12 GTME should have its own Board of Directors (the executive Board) and Boardof Supervisors (the policy and macro-management Board). Pertamina should berepresented on the Board of Supervisors and it would be useful to giverepresentation to bulk buyers like PLN, PGN and the fertilizer industry,especially in the initial years, to facilitate coordination of gas purchase (rromPSC operators) and sale (to bulk buyers).

6.13 The institutional structure best suited for the above characteristics isa limited liability company, a Persero t. GOI's involvement and support wouldbe necessary, especially during the planning stage and GTME's initial operations,as it would involve the coordination of gas production from Pertamina and PSCoperators with the requirements of PLN, PGN, the fertilizer industry and otherGOI owned bulk buyers of gas. Once the gas producers and users have beenidentified, gas quantities and prices agreed, and the main elements of gastransmission infrastructure designed, GOI's involvement could be reduced andprivate funding sought for the infrastructure investments. With gas supply andsales contracted on a take or pay basis and adequate margins between its purchaseand sale prices, GTME's operations would be exposed to minimal commercial risksand should attract private funds in the form of equity, bonds and/or loans.

6.14 The identification of gas suppliers and users, agreement on quantities andpricing mechanisms and the initial plans for the gas transmission network areexpected to take at least 18 months. Those activities would require extensivenegotiations with concerned parties, substantial involvement of GOI, but no majorcapital outlays. The creation of a new Persero for this purpose would also takesome time, as existing laws 26 may need amendment. To start the necessaryactivities for the development of the domestic gas market early, it may,therefore, be desirable to initially use an existing corporate shell within thepublic sector. The logical candidates would be Pertamina and PGN; the pros andcons for each one are discussed below. C

6.15 Pertamina has extensive experience in negotiating supply contracts with PSCoperators and in bulk sales of gas. It has a strong financial position and alarge organization to absorb additional responsibilities. However, Pertamina,being a producer of gas, exporter of oil and LNG, and supplier of gas and liquidpetroleum products to the domestic market may run into conflicts of interestnegotiating gas supplies as well as bulk sales to the domestic consumers. Also,due to its participation in numerous PSCs and joint ventures and other legalobligations, it may be difficult to change the legal status of Pertamina toPersero, to suit the needs of the domestic gas market.

6.16 PGN's organization ib small as compared with the operations envisaged forthe GTME, but it is exclusively focussed on the domestic gas market. No conflictof interest is foreseen in PGN's negotiating gas supplies and selling the gas inbulk or retail. The combination of gas transmission and distribution in onecompany is more likely to lead to an optimal gas infrastructure design than ifit is done in two different entities.

5/ A Persero is a limited liability company that can be partly private andpartly Government owned.

6/ In particular, the laws that give Pertamina the sole authority to supplypetroleum products and natural gas to the domestic market. Nevertheless,these laws have accommodated PGN overlapping Pertamina in a part of gasmarketing. It should similarly be possible to create a Persero, asproposed, preferably with Pertamina being associated through adequaterepresentation at its Board of Supervisors.

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6.17 As Perums, Pertamina and PGN are allowed to retain only a minor portion oftheir earnings after taxes, social and pension funds contributions and obligatorypayments to GOI (DPS); their ability to form subsidlaries and accept privateequity funds is limited. The Persero form of organization would allow the OTMEto retain more of its earnings and enable the private sector to participate inthe funding of GTME's capital expenditure. Irrespective of GTME's initialinstitutional set-up, it will have to develop the skills that are appropriate tothe expanded role of natural gas in the domestic market. Theae skills range froma financial and commercial aspects of domestic gas supplies and sales to theengineering skills necessary to plan for and transmit gas efficiently and safelyto the market. In order to acquire these skills, it is recommended that asubstantial. portion of the equity in the GTME be contributed by a suitablyexperienced gas entity or that a long-term technical collaboration agreement besigned with such an entity;

6.18 To ensure a quick start of the development of the dom%stic gas market,substantial GOI (MIGAS) involvement would be needed during a transition perLodto: create a suitable regulatory and legal framework for the sector; initiatediscussions with gas suppliers and bulk buyers; plan the transmissioninfrastructure; and establish/strengthen necessary operating and regulatoryentities. After this transition period, the private sector should be encouragedto participate in the sector development to the extent practicable. The strategyto be adopted would consist of the following steps:

(a) use an existing public corporate shell, preferably PON, reinforcedwith relevant staff transferred from Pertamina, other domesticinstitutions and foreign expertise under a technical collaborationagreement, to initiate the planning and development of the gastransmission and distribution infrastructure and discussions withgas suppliers and bulk buyers;

(b) simultaneously, review the environmental, safety, pricing and otherregulatory aspects of the gas sector (including access to thepipeline system) and strengthen the capabilities of MICAS (throughthe creation of a separate directorate for domestic gas issues) toplay an active role in the long-term planning for the sector and itsregulation (see Annex 5.2);

(C) review existing laws for the sector and make amendments as necessaryto enable the formation of a suitable gas entity;

(d) assess the interest of thc private sector in the funding of theGTME, especially from suitably experienced gas companies; and

(e) establish GTME by converting the abovementLoned corporation into aPersero to facilitate participation of the private sector.

6.19 The GTME could be remunerated either through a toll fee system or througha margin between the purchase and sale prices of gas. The latter remuneratLonmethod Ls easier to administer and internationally the most common one, insituations where there are several gas producers and buyers, e.g. British Gas,Gaz de France, Ruhrgas, etc. Considering the large number of potentlal gasproducers and users in Indonesia, it appears that GTME's buying the gas from theproducers and selling it to the users would be more practical than a toll feesystem. The representation of the bulk buyers of gas at GTME's Board shouldensure that their interests are adequately protected at the price negotiationswith the producers as well as with the users themselves. Powever, once the basLcgas transportation Lnfrastructure is in place, GTME should be obliged to provideopen access to its pipeline system, at a reasonable cost, to gas producers andusers that may have concluded supply contracts in direct negotiations. Openaccess to the pipeline system would facilitate the development of the domesticgas market and encourage new exploration and development.

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6.20 A domestic gas directorate within MIGAS would have to be established at anearly stage for sector regulation and to coordinate the initial efforts todevelop the sector and establish the necessary institution(s). When GTNE startsoperating, the regulatory authority would verify that CTME does not abuse itsmonopoly in gas transmission, e.g. by earning excessive profits or refusingaccesu to the pipeline network at reasonable cost, and that it operatesefficiently in line with internationally accepted standards.

6.21 Gas clauses in standard PSCs need to be reviewed and amended as necessarywith a view to provide incentives to operators to explore for and develop gasfinds whenever economically justified. For example, many gas and oil fields aremarginal producers. The profit split for oil production is increased in favorof PSC operators for such marginal fields in new contracts. A similarflexibility should be exercised for marginal gas fields. Existing contractswhere gas development is not taking place may have to be amended to provide foran increased share of profit gas for the PSC operators. Further, gas flaring iscurrently not banned or restricted and some incentive to avoid flaring is needed.A penalty for flaring gas should be introduced to encourage the production andsupply of gas.

Investment ExDenditures and Their Financino

6.22 investments would consist of development of relevant gas fields,transmission infrastructure and distribution systems. Table 6.1 shows the orderof magnitude of investments in 1992-2002. The total investment of about $6.0billion is substantially higher than the currently projected investment in thesoctor of about 1.5 billion 2. Investment of about $2.8 billion (of the $6.0billion) would be in the public sector, amounting to around 5S of the totalestimated public sector investment during this period. About two-thirds of theinvestments in field development, almost all of the transmission infrastructureand about 40% of the distribution networks will need to be made in the first fiveyears of the program. The final phasing of the investments will be made once thedetailed design and costing of the pipeline infrastructure has been completed.

Table 6.1: Estimated Investments IA(S million)

Field Development Transmission DistributionRehion PSC. pertamina cTME PGN Total

E. S C. Java 1,041 106 420/k 172 160 1,899W. Java 1,325 552 - 155 330 2,362S. a C. Sumatra Lc 95 307 - 251 33 686N. Sumatra - 99 - 45 37 181E. Kalimantan 762 - - _4 - 806

Total 3,223 1,064 420 667 560 5,934

/A In 1991 dollars.Lb This is the estimated cost of the offshore pipeline from Pagerungan field

to the land fall. Portamina will own the pipeline when laid, but atransmission fee will be payable to a local company, which is arrangingthe financing. The pipeline is shown under field development an it is adedicated line, which generally form part of PSCm.

/c Includes $200 million for a trunk pipeline from South Sumatra to WestJava.

Source: Mission estimates.

v Includes about $800 million for ARCO, Pagerungam f$ild and offshore pipeline;$350 million for the development of ARCO'a field offshore West Java; $250 millionfor the development Portamina, onshore fields and expansion of transmissionsystem ln South Sumatra and $160 million for field development and transmissioncapaclty expanalon in North Sumatra.

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6.23 Given an adequate price for gas, the PSC operators are expected to financefield development as they have done for oil and LNG exports. In regard toPartamina, the East and Central Java requirement for the offshore pipeline hasbeen taken care of (see note to Table 6. 1). If constrained by financialresources, P-rtamina may seek Joint Operation Agreements (JOA) for its fielddevelopments. Such agreements are used for some of Pertamina'c oil fields. Thepartner matches Pertamina's munk costs firmt, then puts up 100' of all additLonalcomtm and is repaid from future production. Future production will first covercosts, then repay the partner for funds advanced to Pertamina alongwith an agreedpremium, and the remainder or "profit oLl" is divided 50/50 between Pertamina andthe partner; Pertamina may also consider other forms of contracting, includingBOTs, which have been used in the past.

6.24 For the laying and strengthening of the gas transmission system, the GTMEmay raise foreign resources through suppliers' credits, bilateral credits,commercial bank loans and *multilateral credits (IBRD/ ADB). Private equitycontributLons should be encouraged and, as a Persero, the GTME may issue localcurrency bonds, which could be bought by state owned insurance companies andpension funds among others. The low risk character of its operations would makeOTME a suitable bond issuer.

6.25 If PGN continues to operate as a Perum, only about $50 million equivalentof the required distribution network investments could be financed out of itsinternal cash generation, provided its present satisfactory financial performanceis maintained. A World Bank loan approved in 1990 (Loan No. 3209) providesanother $86 million for execution of some works in East Java and North Sumatra,but this still leaves a funding gap of over $400 million. A merger of PGN withthe proposed Persero GTME would allow a larger portion of PGN's projected cashgeneration from on-going operations to be retained for investment purposes.Further, such merger could provide access to private equity funds and otherflnancial sources and thus reduce the need of public funds.

Medium and Long term Perspectives

6.26 Indonesia has energy resources which are likely to last through the nextcentury. The foremost among the resources is coal with measured reserves of 4.2billion tons (about 100 TCF of gas in energy equivalent terms) and total reservesestLmated to exceed 32 billion tons. From the current level of 11 milllon tons,productlon is expected to reach 50 million tons in 2000.

6.27 Next ln order of importance are the gas resources. Of the 91 TCF of provenand potential reserves recoverable as of January 1990, an allocation of about 43TCF until 2020 would be required towards LNG exports on present plans of raisingexports from 21 million tons pe. year to 30 million tons per year by 2010. Tosatisfy domestic requirements until 2020, 35 TCF would be needed. It appearsthat there are sufficient proven and potential reerves of gas to meet this gasconsumption scenario, but development of the Natuna gas field would be necessaryif new gas reserves are not found.

6.28 The recoverable oil reserves are about 11 billion barrels and at thecurrent level of output (about 530 million barrels per year), the r-esrve-production ratio is 20:1. At thli rate, oil reserves would be depleted by 2015,unless new reserves are added or Indonesia decides to conserve oil either byreducing exports or by curbing the accelerating domestic consumption. Hydropowerand geothermal potentials are abundant, but their geographic distribution Ln manycases limits their development potential.

6.29 Thus, the long term planning for energy has to be based on coal as thebackstop fuel, unless exploration leads to more oll and gas discoverles. Whilethe prospects for new flnds are bright, the GOI has to carefully watch thesituation. If now reserves are not being added to make up for oil and gasdepletions, it would be prudent to limit oil and gas exports/consumption toensure that safe minimum recoverable reserves are maintained. Underlying the

-45-

strategy outlined for domeatic gas utilization is the assumption that more gasreserves will be found. In the meanwhile, the economy will be well served by theuse of currently available non-exportable gas on the scale as recommended in thisreport.

-46-

INDONESIA

Natural Gas Development Planning Study

Commercial Energy Balance, 1990(million BOE)

CrudeOl&OIFocd- Natural Cod Hydro Goo- Elsc LNG Peirholum ProdudsC _ndat Stock Gan Thermal Kerosene Mogas ADO IDO FO Av. Fuel Othws NepIh TOTAL

P*may Supply

Producen 5t0.7 0.0 325.0 46.4 17.3 1.7 0.0 0.0 0.0 7.7 0.0 0.0 928.8I_pel 45.7 0.0 0.0 5.0 0.0 0.0 0.0 14.3 2.7 0.0 68.2E ul3unk (26.5 0.0 0.0 (16.1) 0.0 0.0 (191.3) (0.1) (1.0) (2.7) (2.5) (48.2) (14.5) (564.9)USbjL 0j.. (15.2) 0.8 0.0 (6.3) 0.0 0.0 (6.6) 3.9 1.2 (0.4) (0.3) (6.0) (5.03 (34.2)GROSSAVALABLE 274.7 0.6 325.0 27.0 17.3 1.7 0.0 (196.1) 3.9 1.1 13.4 0.0 (0.3) (0.6) (53.2) (14.5) 397.9

Conermlon, Own Us., Losse

me" (273. (0.4 (.n 0.0 0.0 0.0 0.0 0.0 40.7 37.1 65.4 12.0 30.2 56 09.4 17.9 9.2 1Pn uGe.erde 0.0 0.0 (2.0) (17.7) (17.3) (1.7) 23.1 (10.5) (0.4) (18.0) (44.5)LN&L" 0O 0.0 (209.6) 0.0 0.0 196.1 (11.8)OwUse,dLo.s (1.03 0.0 (66.q (0-1) (4.4) (0.1) tr (0.7) (0.6) (2.4) (13.6) tr (92.3)TOTAL (274.53 (0.4 (261.q) (17.6 (17.3) (1.7) 17 16.1 48.0 37.1 54.2 11.0 9.4 5.6 55.0 17.9 (139.4)

Ndt Supplies 0.1 0.0 43.6 9.2 0.0 0.0 167 (0.03 50.5 36.2 67.6 11.0 9.1 4.8 2.4 3.3 258.6

Fial Eery U 0.0 0.0 22.7 8.9 16.7 0.0 50.5 36.2 67.0 11.0 9.1 4.0 0.0 2315

h A_y 0.0 0.0 22.7 *.9 10.5 0.0 0.0 27.5 9.5 6.7 0.0 0.0 87.8T _M_PM 0.0 0.0 t1 0.0 0.0 0.0 36.2 40.0 1.5 0.4 4.8 0.0 84.9Ho _sehdd 0.0 0.0 Ir 5.3 50.5 0.0 0.0 0.0 Q.O 55.8olae 0.0 0.0 tr 2.8 0.0 0.0 0.0 0.0 0.0 2.8

Non-energy Use 0.0 0.0 20.9 0.3 0.0 0.0 0.0 (0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.4 3.3 27.1Nags: WV buhcd.. gas Lve. y smA. queRis..

Bowes: MQAS OQ :

H ~~~~~~~~~~~~~~~~~~~~~~~~~~~~xa-'

0.

INDONESIA

Natural Gas Development Planning Study

Commercial Energy Balance, 1985(million BOE)

CnadoOU&OlF- Nawd Coal Hydro Goo- Ebe LNG P*dcum ProducssCmndw_g. Stock Go Twmnal Kegs.. MoWN ADO ID0 FO Av. Fud Oflem 14bth TOTAL

Prm Suppy

Przudlin 467.6 0.0 229.5 6.4 12.9 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 738.7Impel 32.4 0.0 3.0 0.0 0.0 0.0 1.7 0.5 0.0 0.0 37.6ExpGW__U (205.4) 0.0 0.0 (4.5) 0.0 (139.9) 0.3 0.1 (1.5) (0.6) (0.4) (13.2) (42)Sc . DOi. (25.1) 1S.9 0.0 (1.2) 0.0 (2.2) .7 2.3 7.4 2.2 4.6 0.2 (25.6) (3.) (1.3)GROSS AVALABLE 200. 3. 220.5 57 12.9 0.3 0.0 (142.1) 5.7 2.3 7.7 2.3 4.9 0.1 (28.0) (16.2) 301.8

Cnsion, Own Use, Losses

Rdney (100.6) (13.9) (0.6) 0.0 0.0 39.3 22.5 44.1 9.4 21.4 4.0 42.0 16.4 (14.5)Powworat_o 0.0 0.0 (0.7) (2.|) (12.9) (0.3) 12.9 (At1 tr (t8.3 (14.7) (41.0)LNGSLP° 0.0 0.0 (14) 142.1 (s6)Own Use and Loom (1).6 0.0 (45.3) (0.1) (2.7) (0.2) (0.1) (1.5) (0.9) (2.6) 0.1 (0.2 (54.5)TOTrAL (200.6 (13.0) (194.6) (2.0) (12.9) (0.3) 10.2 142.1 39.2 22.4 38.6 6.5 2.4 4.1 28.2 16.2 (115.7) co

Ne Supplis 0.0 0.0 34.7 2.7 0.0 0.0 10.2 0.0 44.9 24.7 44.3 10.6 7.3 4.3 2.2 0.0 168.0

Final Energy Use 0.0 0.0 16.3 2.0 0.0 0.0 10.2 0.0 44.9 24.7 44.3 10.6 7.3 4.1 0.0 166.6

kidusty 0.0 0.0 16.3 2.0 5.5 0.0 0.0 20.0 9.3 7.1 0.0 622Transpo,tdtn 0.0 0.0 0.0 t1 0.0 24.7 24.3 1.3 0.2 4.1 54.6Household 0.0 0.0 I 0.0 3.0 44.0 0.0 0.0 0.0 0.0 0.0 47.9COmes 0.0 0.0 0.0 0.0 1.6 0.0 0.0 Q0 0.0 0.0 0.0 0.0 1.6

Non-energy Use 0.0 0.0 16.4 0.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 2.2 Q0 19.4Nde: iVbdkMe&*,al...vwy sl, quant_.

bmew MIGAS

0̂ 'wI

Natural Gas Development Planning Study

Net Energy Consumption, 1985 & 1990

(million BOE)Industry Transportation Households Others Total Share

1985 t99 19S5 1990 19S5 1990 1995 1990 19S5 1990 19SS 1990 ha_~

Pelroleum Products

KwOMw 0.0 0.0 0.0 0.0 44.9 50.6 0.0 0.0 44.9 50.6 27.0 21.9 (.1)magn 0.0 0.0 24.7 382 0.0 0.0 0.0 0.0 24.7 38.2 14.8 16.5 1.7ADO 20.0 27.5 24.3 40.0 0.0 0.0 0.0 0.0 44.3 67.5 26.6 29.1 2.5DO 9.3 9.5 1.3 1.5 0.0 0.0 0.0 0.0 10.6 11.0 6.4 4.8 (1.6)FO 7.0 &7 0.2 0.4 0.0 0.0 0.0 0.0 7.3 9.1 4.4 3.9 0.4)Av. FumI 0.0 0.0 4.1 4.9 0.0 0.0 0.0 0.0 4.1 4.9 2.5 21 (0.4)

Total Fuel Oils 36.3 45.7 54.7 84.9 44.9 50.6 0.0 0.0 135.9 1812 81.7 78.3 (3.4)

Natural Gas 18.3 22.7 0.0 t 0.027 0.033 0.0 0.0 18.3 22.7 11.0 9.8 (124Coal 2.0 .9 0.0 0.0 0.0 0.0 2.0 8.9 12 3.6 2.6Gas & coal 20.3 31.6 0.0 0.0 0.027 0.033 0.0 0.0 20.3 31.6 122 13.7 2.2

Eectricity Ss 10.5 0.0 0.0 3.0 s 1.6 2.8 102 18.7 6.1 8.1 2.0

NdCG 026 0.56 2.0 2A 0.5Cod 1.03 6.43 7.8 27.8 20.0PSaism 6.83 8.81 51.7 38.1 (134do 4.97 6.66 37.6 286 (84tGslasum 0.13 0.67 1.0 29 1.9lul_ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~(2.r4 (4.4S)

13.2 23.1 100.0 100OToti .Cm, , ds 25. 42.1 0.0 0.0 3.0 5.4 .6 2.6 30.5 50.3 18.3 21.7 .4

TOTAL 622 676 54.7 64.9 47.9 56.0 1. 2.8 1S.4 231.5 100.0 100.0 0.0

OVall Shae 37.4 37.9 32.9 36.7 266 24.2 1.0 12

: 8

U t

SX

O 0.~

-51-

Anno L 2Page 1 of 6

INDONSIA

Natural Gas Develonment Planning Study

Coal Data and Characteristicg

Recent Develovments

1. Indonesia signed a spot contract with a Hong Kong Power Company for twocargoes of Kaltim Prima coal in August 1991. According to the Financial Times,this contract "... *sent shudders through the coal market." The price wasUS$33/ton delivered, on a heat basis of 6300 kilocalorie/kg. By comparison,Australian sales to Japan have been at US$39.85/ton FOB in 1991 (6700kilocalorie/kg); the price for U.S. coal has been $36/ton, FOB Gulf; North ZuropeMCIS spot market CI? for steam coal (less than 1% sulphur, 6000 kilocalorie/kg)has been within a range of $42.40/ton to $43.11/ton during Jan-Aug 1991.

2. There was a trial export of a cargo of 35,000 tons of coal (5,300kilocalorie/kg) from the Bukit Asam mine in Sumatra to Japan at a price of$28/ton, FOB.

3. Some of the relevant freight rates for coal are:

Indonesia - Hong Kong $3.75/tonIndonesia - Japan $4.25/tonAustralia - Hong Kong $9.00/ton

4. Kaltim Prima's new terminal handles "Capesize" vessels - 180,000 DWT (morecapesize and slightly smaller Panamex terminals are in the offing).

Indonesia's coal reserves

5. Indonesia's coal reserves are shown in Table 1. As indicated, the measuredreserves are approximately roughly split between Sumatra and Kalimantan.

Oualitv of Indonesia Coal

6. The technical characteristics of Indonesian coal, by region, are shown inTable 2.

-52- Annex 1.2

Page 2 of 6

Table 1: Estimate of Indonesia Coal Reserves /a

Indicated &Location Measured Inferred Hvootetic Total

----------------------million tons----------------------

SUMATRA 2,286 6,373 14,290 22,953

N. Sumatra - 1,272 428 1,700C. Sumatra 521 1,261 700 2,483S. Sumatra 1,764 3,800 13,162 18,727Bengkulu 2 40 - 43

KALIMMITAN 1,991 6,788 103 8,882

B. Kalimantan 1,058 3,925 - 4,983S. Kalimantan 933 2,623 - 3,556W. Kalimantan - - 103 103C. Kalimantan - 240 - 240

JAVA 4 23 19 47

Sulawesi - 89 - 89Irian Jaya - 4 - 4

TOTAL 4,282 13,277 14,412 31,975

/a As of January 1990

Source: Ministry of Mines and Energy

-53- Annex 1.2Page 3 of 6

Table 2: TECHNICAL CHARACTERISTTCS OF INDONESIAN COAL

Sumatra Kalimantan

Total Moisture (%) < 11 9 - 26Moisture ADB (X) 5 - 8 3 - 16Ash ADB (%) < 10 1 - 15Volatile Matter ADB (X) 36 - 41 35 - 44Fixed Carbon ADB (%) 45 - 53 35 - 47Sulphur ADB (%) < 1 0.03 - 1.27Calorific value (kilocalorie/kg) ADB 6,800-7,000 5,200 - 6,800

Note: ADB - Air Dried BasisSource: Ministry of Mines and Energy

7. In general, Indonesian coal has high volatile matter, high moisture, highhardness, low sulphur and low ash. High moisture tends to raise the freighttransport cost on a per MMBTU basis. Coal with high volatile matter content isgenerally used as steaming coal, and not in industrial processes such as steel-making, though the development of Pulverized Coal Injection technology isbeginning to permit this type of use.

8. Some details of the reserves and the quality of coal are shown in Table 3.

Table 3: DETAILS OF COAL RESERVES AND QUALITY

Company/Contractor Reserves Total cal. value(Million Moisture Kcal/ Kgtons) (Z)

Sumatra

PTTBBA - Tanjung Enim 137 27 5490PTTBBA - Ombilin 157 11 6800PT Allied Indo 13 4 7217

Kalimantan

PT Arutmin 2261 <7 6300PT Utah Indonesia 67 4 6700PT Kaltim Prima 2106 3 5900PT Kideco Jaya Agung 1112 <22 5000PT Adaro 1046 17 5830PT Berau 238 17 5700PT Chung Hua 219 <7 5700PT M.H. Utama 57 11 6350PT Tanito Harum 84 <11 6500

Table 4: Proiection of Coal Production and Congumtion(1990-2001)

Am9& 1990191 l99l/92 1992/93 1993194 1994195 199S/96 1996197 1997198 1998199 1999/00 200010

R. PRODUCTION:

ONSILIN 650 700 750 850 1,000 1,250 1,250 1,250 1,250 1,250 1,2S0sUMIT AMA s5000 S,400 5.700 5,700 5,700 5700 5,700 5,700 5700 5,700 5,700NUAR TG ESAR --So 500 1,000 2,000 2,500 2,500 2,500 2,500BJUNO - - - - 500 1,000 2,000 2,500 2,500 2,500 2,500CONTRACTORS 3,250 5,750 8,300 12,000 14,750 18,000 22,500 26;SOO 29,500 33,000 36,500PRIVATES 1.10 1.150 1.250 1.550 1,55 1.050 1.550 3.050 1-550 1.050 _1 S0

TOTAL 10,000 13,000 16,000 20,100 24,000 28,000 35,000 41,500 43,000 46,000 50,000B. CONSUMPTION:

PCFI PLANTS 4,758 4,758 4,758 7,408 7,766 16,332 21,372 24,673 26,323 26,323 26,323CENMNT INDUSTRY 1,795 1,845 1,895 1,945 2,091 2,248 2,417 2,598 2,793 3,002 3,227OTHERS 20 500 750 1.000 1.5QQ 2.000 2.500 3.000 4.000 5.000 6.000 1

TOTAL 6,753 7,103 7,403 10,353 11,357 20,580 26,289 30,271 33,116 34,325 35,550

SOURCE: Directorate of Coal, 1991

0*

0'

-55- Annex 1.2Page 5 of 6

Proiected Coal Production and Consumption

9. The projected coal production and consumption are shown in Table 4.

Proiection of coal demand and production in ASEAN. NICs and Japan

10. The projected coal demand in various countries is shown in Table 5.

Table 5: PRCJECTED COAL DEMAND AND PRODUCTION IN VARIOUS COUNTRIES

Country 1990 1995 2000

million tons per year

DEMAND

ASEANPhilippines 2.97 6.79 14.82Malaysia 1.94 2.80 5.30Thailand 10.47 24.11 38.36Indonesia 6.61 17.79 39.03

NICsSouth Korea 37.00 41.50 52.00Taiwan 20.10 24.20 27.40Hong Kong 9.50 2.50 4.50

Japan 118.00 130.00 104.60

Total 206.50 264.70 348.11

PRODUCTION

Philippines 1.68 2.60 3.28Malaysia 2.02 3.04 N/AThailand 9.83 24.00 38.07Indonesia 10.65 30.00 50.00

Total 24.18 59.64 <100.00

GOI policy on coal for Dower generation 1

11. Between 1984 and 1990, 4x400 MW coal-based power plants were installed,using pulverized coal-fired units. The plant availability has been 80%. In theperiod 1991-2001, there are plans to add 3x600 MW coal-based units at Suralaya,

1 .Based on Ir. A. Arismunandar's paper at the 6th Pacific RimConference.

-56- Annex 1.2Page 6 of 6

4x400 MW at Paiton in East Java, 2x65 MW at Bukit Asam in Sumatra, and 2x65 MWat Ombilin in Sumatra .

12. The private sector will be invited to participate in the installation ofthis capacity via BOO schemes. Cogeneration using coal by the private sector isalso encouraged.

13. GOI plans to apply stringent air pollution standards through theapplication of coal preparation, combustion and emission control technologies.

-57- Annex 2.1

INDONESIA

Natural Gas Development Planning Study

PERTAMINA ORGANIZATION CHART

i~ I

Lj,0S~~i lEllai §i-

:z r. I i

It!

I 1, 1 IS,

IIs~~~~

-59-

Annex 2.2Page 1 of 2

Indonesia

Natural Gas Develooment Plannina Study

Levelised Comparative Power Generation Costs

Combined Coal-fired Fuel oilcycle Steam La Steam

Technical Data

Fuel Natural Gas Coal Fuel OilHeat Content (MMBTU) 1/MCF 22.2/ton 5.9/bblCapacity(MW) 450 500 500Thermal Efficiency (%) 46 38 39Plant Factor (%) 65 65 65Gestation Period (Years) /A 3 5 5Economic Life (Years) 20 25 25

Electricity Generation

Energy Supplyat full capacity (Gwh/Yr) 2,562.3 2,847.0 2,847.0

Energy Supply IncrementsYear 1 (%) 20 40 20Year 2 () 50 70 50Year 3 (%) 100 100 80Year 4 (%) 100 100 100

Capital and O&M Costs

Unit Capital Cost ($/Kw) 600 1,000 900Investment Cost (S million) 310.5 575.0 517.5Annual 0 & M Cost (%) Lb 4 2.5 2Capacity and O&M Cost (C/Kwh) 2.23 3.26 3.05

Fuel Prices and Costs

Fuel Price (S/unit) 2.34/MCF 30.0/ton 16.5/bblFuel Price (S/MMBTU) 2.34 1.30 2.80Annual Real Price Escalation(%) 1.0 0.5 1.0Annual Fuel Cost (S million) 46.2 35.1 78.3

Unit Fuel Cost (*/Kwh) 1.80 1.28 2.75

Levelized Generation Cost(*/Kwh) /c 4.03 4.54 5.79

LI Not including fluo desulphurization equipment.ik As a percentage of capacity costs, without desulphurization equipment.i2 This is the levelized cost over the lifetime of the plant.

Source: Mission estimates.

-60-

Annex 2.2Page 2 of 2

Indonesia

Natural Gae Develonment Plannina Study

Sensitivity Analysis of Power Generation Costs

Scenario Fuel Prices Unit Generation Costs

Without coal flue desulohurization eauioment ¢/Kwh

Base Case

Gas $ 2.34/MCF 4.03Coal $ 30.0/ton 4.54

Base Case Gas Price. Switchover Coal Price

Gas $ 2.34/MCF 4.03Coal $ 18.1/ton 4 03

Switchover Gas Price. Base Case Coal Price

Gas $ 3.00/MCF 4.54Coal $ 30.0/ton 4.54

Switchover Gas Price. Low Coal Price

Gas $ 2.72/MCF 4.33Coal $ 25.0/ton 4.33

Hich Gas Price. High Coal Price

Gas $ 3.70/MCF 5.08Coal $ 41.0/ton 5.01

Switchover Gas Prlce. HMuh Coal Prico

Gas $ 3.61/MCF 5.01Coal $ 41.0/ton 5.01

With coal flue desulohuriLation eauinment

Swltchover Gas Price. Base Case Coal Pric-

Gas S 3.84/MCF 5.19Coal $ 30.0/ton 5.19

Switchover Gas Price. Low Coal Price

Gas $ 3.57/MCF 4.98Coal $ 25.0/ton 4.98

Switchover Gas Price. Righ C.oal PrLeGas $ 4.45/MCF 5.66Coal $ 41.0/ton 5.66

_ 6AW%ES/wJI/k/s07-?sr-92

UOEVEL0P0 IRECOVERAILE GAS RESERVESWEST JAVA OFFSOE GS FIELDS KVELOPIEIT PLAN AND COST SINARY

I I I ASSOCIATED GAS RESERVES NON-ASSOCIATED GAS RESERVES I TOTAL ESTINATED DELIVERYINO. I FIELD IOPERATOR IPROVEN POTENT. POTENT. TOTAL PRVEN POTENT. POTENT. TOTAL ASSO. + II I I |UDEV. DKV. UNDEV. lWDEV. DEV. tWNDEV. INO1 ASSD.| ASSO. NON-ASSO. TOTAL |I I I I BSCF BSCF BSCF BSCf BSCF BSCF BSCF BSCF I BSCF IFISCFD ISCFD ISCFD

II1 2 3 j4 5 6 7 1 8 9 10 11 12 13 14 15 j

| | OFFSNORE I I | I I1 IBINA, NWC IARCO (ARII)1143.00 0.00 0.00 143.00 0.00 0.00 0.00 0.00 | 143.00 39.18 0.00 39.18

12 IAPN IMRCW (MRII)I 0.00 0.00 0.00 0.00 1113.00 0.00 0.00 113.00 I 113.00 0.00 30.96 30.96| 3 ILL ARCO (ARIIT, 0.00 0.00 0.00 0.00 82.00 0.00 0.00 82.00 | 82.00 | 0.00 22.47 22.47 || 4 IKLX, KLY IARCO (AR1I) 0.00 0.00 0.00 0.00 406.00 0.00 0.00 406.00 | 406.00 0.00 111.23 111.23 |I 5 IBZZ, TS lARCO (ARII)1 0.00 0.00 0.00 0.00 | 137.00 0.00 0.00 137.00 | 137.00 | 0.00 37.53 37.53 | o 16 IT ARCO (ARII)1 0.00 0.00 0.00 0.00 | 61.00 0.00 0.00 61.00 | 61.00 | 0.00 16.71 16.71 I

7 ISC, SE IJARCO CARIJ)l 0.00 0.00 0.00 0.00 1 24.00 0.00 0.00 24.00 I 24.00 j 0.00 6.58 6.58I8 ISC - 3 IRCO (ARII)I 0.00 0.00 0.00 0.00 14.00 0.00 0.00 14.00 | 14.00 0.00 3.84 3.84I9 ES C IMCO CARI()| 0.00 0.00 0.00 0.00 | 35.00 0.00 0.00 35.00 35.00 0.00 9.59 9.59 II I I ..... _.____............. ..... I I 1 SUB TOTAL 1143.00 0.00 0.00 143.00 | 872.00 0.00 0.00 872.00 11,015.00 | 39.18 238.90 278.08 |

-I I - _ ___ _ __ ........................ _ ............... _ .......-------------------------.......- '''''''''''''-DI10 lIVuiO I NAXS 1 35.30 0.00 0.00 35.30 I 0.00 0.00 0.00 0.00 35.30 9.67 0.00 9.67 rAI 11 IZELDA I RAUS 28.24 0.00 0.00 28.24 | 0.00 0.00 0.00 0.00 | 28.24 7.74 0.00 7.74 I CI-------------------------------------------------------------------------------------------------------------------------------------- i

1206.54 0.00 0.00 206.54 1 872.00 0.00 0.00 872.00 11,078.54 1 56.59 238.90 295.49

Assumption :(i). gs Delivery for 10 years (vi). Develot ent Facilities includes

(ii). Associsted Gss Pressure 100 Psig and Non Assciated Gas pressure (a). Offshore surface facilities1000 psig (b). Suimrine gas gathering Lines

(iii). Cost of Facilities includes, copressor for Associated Gas, (c). Purification plantGathering Lines, and Process facilities. Cd). Other onshore facilities where needed o

CM). All costs estimted at 1991 USS. (vii). Strong equifer pressure hport is asumd, m Xthis this mill minimize copresmion farequir.emnts. o.

PUGAS 68/W PRES/KIi/ks/07-Nar-92

UtDEVELOPED RECOVERABLE GAS RESERVESWEST JAVA OF FSH0RE GAS FIELDS DEVELOPNENT PLAN AND COST SUIMARY

I No. OF WELLS REQUIRED TO BEI DIST. PIPE DEVELOPMENT COST DEFERRED GRANM|0. I DRILLED N NO. JUCTION TO JtICT P/L SUPPLY LINE | I COWP. COST TOTAL |

I IDEPTH APPRAI- OF POINT POINT SIZE PRESSURE PRESSURE | DRILL PLATFORM FACIL. TOTAL | FROM 6 TO COSTI IMETERS SAL DEVELOP. TOTAL IPLATFORS KM INCHES PSIG PSIG | S E S M S N S 110 Y. USS .6M S |.,_............ .......................... .... ....... ........ ................ .. .. ..... ....... I...........................

I 1 16 17 18 191 20 21 22 23 24 25 126 27 28 291 30 31 I,,,~~~~~~-=s-=.-=-,,-,,=-=--=,-====-===,,=- --==" =----=-- I==

|1.00 670 4 8 12 4 P F/S 72 16 100 650 19.30 30.00 49.20 98.50 0.00 98.50|2.00 670 3 6 9 | 4 P F/S 43 24 1000 650 | 14.50 30.00 127.40 171.90 0.00 171.90 |3.00 670 3 6 9 j 4 N N C 37 30 1000 650 I 14.50 30.00 130.60 175.10 I 30.00 205.104.00 670 5 23 28 I 9 N N C 27 26 1000 650 I 45.00 67.50 16.20 128.70 0.00 128.70 I5.00| 670 4 7 11 4 B2.C 13 16 1000 650 | 17.70 30.00 103.90 151.60 | 30.00 181.60 |

|6.00 670 2 4 61 4 N N F S 23 16 1000 650 9.60 30.00 8.50 48.10 0.00 48.10I7.001 2340 2 3 5I 2 K.C 17 8 1000 6501 28.10 15.00 3.10 46.201 0.00 46.201

|8.00| 2340 1 3 4| 1 BTSA 3 8 1000 650 22.50 7.50 0.60 30.60 0.00 30.6019.00 1000 2 3 5 | 2 E.C 14 10 1000 650 | 12.00 15.00 3.20 30.20 0.00 30.20 |....................... - ...... *- *.*--- -- ------ - ----- -----------. *-- -- -.------------- I

I 1 26 63 89 1 34 249 1 183.20 255.00 442.70 880.90 1 60.00 940.90....... ........ ... .... ........ ... ....... .... ... .. *. .-. *..-----.. .----.. .*.- .. *.-----..--. .*-----. ..-----..--..- .. I

110.00 1 0 0 0 0 0 --- 0 0 0 0 0.00 0.00 0.00 0.00o 0.00 0.001111.00 1 0 0 0 01 0 --- 0 0 0 0 1 0.00 0.00 0.00 8.001 0.00 8.00

............. ....... ...... ...... ....... ...... ...... ....... .. *..- .-----------------. ....--...----------- *-... .------.- *----.--.I

I l 26 63 891 34 249 1183.20 255.00 442.70 888.901 60.00 9U .901----- -- --- -- ------ --- I-

lb OQPfD m

0.M*I-

INDONESIA

Natural Gas Development Planning Study

UNDEVELOPED RECOVERABLE GAS RESERVESWEST JAVA ONSHORE FIELDS DEVELOPMENT PLAN AND COST SUMMARY

maInuuuau _in_u uuinin _._. .zrzrw . . ._nuu *-insu inuwU.iniun .uumu mu uinI I I I TED GAS RESERVES I NON-ASSOCIATED GAS RESERVES I TOTAL I ESTIMATED DEVELIVERY I

No. I FIELD I OPERATOR I PROVEN POTENT. POTENT. TOTAL IPROVEN POTENT. POTENT. TOTAL I ASSO.+ I II I jI IUNDEV. DEV. UNDEV. I UNDEV. DEV. UNDEV. I ONASSO I ASSO. ON-ASSO TOTAL I

I I I BSCF BSCF BSCF BSCF I BSCF BSCF BSCF BSCF I BSCF I MMSCFD MMSCFD MMSCFD II 1 1 2 1 3 1 4 5 a 7 1 8 9 10 11 1 12 1 13 14 15 6

ONSHORE I I I I I II i CICAUH I PERTAMINAll I 0.00 0.00 0.00 0.00 1 139.07 0.00 0.00 139.07 1 139.07 I 0.00 38.10 38.10 1

1 2 PASIRJADI I PERTAMINA II 0.00 0.00 0.00 0.00 1 0.00 10.20 0.00 10.20 1 10.20 1 0.00 2.79 2.79 I1 3 I PEGADEN I PERTAMINA III I 0.00 S4.31 0.00 54.31 0.00 14.47 0.00 14.47 1 68.78 14.88 3.96 18.84 11 4 I PAMANUKAN I PERTAMINAIII I 0.00 0.00 0.00 0.00 1 11.64 0.00 0.00 11.64 I 11.64 1 0.00 3.20 3.20 11 5 I SUKATANI I PERTAMINA III I 0.00 0.00 0.00 0.00 1 37.65 0.00 0.00 37.65 1 37.65 1 0.00 10.30 10.30 1

6 I HAURGEUUS I PERTAMINA III I 0.00 0.00 0.00 0.00 1 35.41 0.00 143.56 178.97 178.97 1 0.00 49.00 49.00 1I 7 I KANDANGHAURBARA PERTAMINA Ill I 0.00 1.68 0.00 1.58 1 0.00 0.00 0.00 0.00 1.68 1 0.43 0.00 0.43 1I * KANDANG HAUR TIMU I PERTAMINA III I 0.00 22.68 0.00 22.68 I 0.00 7.20 0.00 7.20 1 29.88 1 6.21 1.97 8.19 1I 9 I CEMARASELATAN I PERTAMINA III I 0.00 0.67 0.00 0.67 1 0.00 19.12 0.00 19.12 1 19.79 1 0.18 5.24 5.42 * I1 10 I CEMARABRT&TMR I PERTAMINA III 0.00 98.15 0.00 98.15 j 0.00 17127 0.00 171.27 1 269.42 28.89 46.92 73.81 *1 11 I WALETUTARA I PERTAMINA III 5.90 0.00 26.90 32.80 1 4.31 0.00 17.07 21.38 I 54.18 1 8.99 5.85 14.84 I1 12 I SINDANG I PERTAMINA Il I 0.00 0.00 0.00 0.00 1 0.00 44.08 0.00 44.08 1 44.08 1 0.00 12.08 12.081 13 JATI BARANG I FERTAMINA IN 1 0.00 23.71 0.00 23.71 1 0.00 10.79 0.00 10.79 1 34.60 1 6.50 2.96 9.46 11 14 I JATI BARANG BRT I PERTAMINA lIl 0.00 0.00 0.00 0.00 1 18.94 0.00 0.00 18.84 18.84 1 0.00 5.16 5.16I 15 IRANDEGAN I PERTAMINA III I 0.00 19.00 0.00 19.00 I 0.00 0.00 0.00 0.00 1 19.00 1 5.20 0.00 5.20 1

16 1 GANTAR I PERTAMINA m I 0.00 0.00 0.00 0.00 I 0.00 82.62 0.00 82.52 I 82.52 1 0.00 22.61 22.61 1I - - - - -_

I I TOTAL I 1 5.90 220.10 26.90 252.90 1 385.99 359.65 190.63 906.27 1 1.15917 I 69.28 24825 317.53 1

AsmxnpUons:(). Gs deiveryo 10yars (vii). Randegan totl potentil undeveloped rewrves have been4. Assocted Gas Preur 100 PI and Non Associated Ga adjusted for net hydrocarbons ( C02 + Inert * 33.7 t)

Prsre 1000 Psig purifcation cost US$20 million(HQ. Codt of becile inc-ude, compreor for assocated ga. (vii. Pamanukan total potenial undevelo"ed reserves have been

gatrIng lins and proc fscilitie. excluded as ft Is practically pure C02, purifiation cost USS(iv7. Fied gas compreor assumed to be required I Axth Wr 10 million(. All coats eataled at 11 USS (x). Sukatanil tota potential undeeloped ressve have been(vi. H Ngeus I potl undeveloped rer have been excluded as Tt I practically pure C02, puri*fation cost USS$11

ad_utd for net hydocabon (C02 + ient - 7.75 *). 10 miNion I epurifcaton cost USS 30 mliTon H

0 *

UNDEVELOPED .GVERABLE GS RESERVESWEST JAVA ONSHORE FIELDS DEVELOPMENT PLAN AND COST SUMMARY

- umamm, womasaws Uin U Uni =.Um o-_ _*_u _ inn U UU UUi-WU-

I I No.OFWELLSREQUIREDTOBEDRILLE DIST. PIPE I I DEVELOPMENTCOSTI EFERRED GRAND INo.I I JUNCTION 0 JUNCT PIL SUPPLY UNE I No. I IOMP. COST TOTAL I

I I DEPTH APPRA- I POINT POINT SIZE RESSUR RESSUR I I DRILL FACIL TOTAL I ROM 6 TO COST IMETERS SAL DEVELOP. TOTAL I KM INCHES PSIG PSIG I I MMS MMS MMS IOY-SMs MmS I

I |i1 17 18 19 1 20 21 22 23 24 1 125 26 271 28 30

I 900.00 4.00 6.00 10.00 l CICAUH 5.00 10.00 1000.00 650.00 I 1 1 12.00 19.50 31.50 I 3.00 34.50 1

1 2 1 600.00 1.00 1.00 2.00 ICILAMAYA COMP 30.00 e.00 1000.00 660.00 I 2 1 2.00 5.00 7.00 1 300 10.00 II 3 1 950.00 2.00 3.00 5.00 I PAMANUKAN 10.00 6.00 1000.00 660.00 1 3 1 6.00 14.00 20.00 I 4.00 24.00 1

I 4 I 1800.00 1.00 1.00 2.00 I PAMANUKAN 6.00 5.00 1000.00 650.00 1 4 I 5.00 5.00 10.00 I 4.00 14.00 1

1 5 1 1800.00 2.00 1.00 3.00 1 ANJATAN 4.00 8.00 1000.00 650.00 I 5 I 7.00 6.00 13.00 I 4.00 17.00 II 6 I 1400.00 4.00 6.00 10.00 I SUKATANI 8.00 14.00 1000.00 650.00 1 6 I 18.50 60.00 78.50 I 5.00 83.50 II 7 I 2100.00 1.00 1.00 2.00 1 ANJATAN 6.00 6.00 100.00 650.00 I 7 I 5.00 6.00 11.00 I 2.00 13.00 11 8 I 2100.00 2.00 1.00 3.00 I KANDANG HAUR 6.00 6.00 1000.00 650.00 1 8 1 8.00 6.50 14.60 1 2.00 16.50 11 9 1 2000.00 1.00 1.00 2.00 I LOSARANG 10.00 6.00 1000.00 650.00 I 9 I 5.00 6.00 11.00 2.00 13.00 1I 10 1 2000.00 4.00 13.00 17.00 I LOSARANG 1.00 16.00 1000.00 650.00 1 10 I 44.00 47.00 91.00 I 5.00 96.00 II 11 I 1800.00 2.00 2.00 4.00 I KRASAK 15.00 6.00 1000.00 650.00 I 11 9.00 13.50 22.50 1 2.00 24.50 1I 12 1 2300.00 2.00 2.00 4.00 I KRASAK 5.00 6.00 1000.00 650.00 1 12 I 12.00 6.00 18.00 1 2.00 20.00 1

13 i 2300.00 2.00 1.00 3.00 1 ATI8ARANGBR 0.00 6.00 1000.00 65.00 13 I 9.00 7.00 16.00 1 2.00 18.00 1I 14 1 2300.00 1.00 1.00 2.00 1 ATIBARANGBR 0.00 6.00 1000.00 650.00 I 14 I 8.00 5.00 11.00 1 2.00 13.00 Ii 1s I 1500.00 1.00 1.00 2.00 I RANDENGAN 0.00 5.00 100.00 650.00 I 15 1 4.00 25.00 29.00 1 6.00 34.00 Ii 16 I 1100.00 2.00 4.00 6.00 I KANDAN¢ HAUR 12.00 8.00 1000.00 650.00 1 16 i 9.00 12.00 21.00 1 4.00 25.00 1

I I e3 51 87 123 1 I173.50 263.00 436.s0 54.00 490.501m ...... ... inu...mmin mumminuw m ._n sumumum mu.. mmummUU ....... mum.. m.u .. r mwmumi... ....

(x) *. Pstamina plans to produce these field at 20 MMscfd (to minimise the watewy coning)durIo 1902. Theie currently producing 6 MM.cfd.

(Kl). Strong equlbr prme support Is asumed, thib wAi minimise compresdon requirement.

0Q ¢OQ 0gD &

0

IEWLOPD SERC IE GS RESERVESCENTRL A EAST JAVA _OR AND OFFSNORE AS FIELDSOEELOPENT PLAN AND COST 3MSEtV

| | | | ASSOCIATE rAS NREES H-ASXIATED AS RESERVS | TOTAL ESTINATED DVELIVERY|lb. | FIELD | OPERATO IPWEN POTENT. POTENT. TOTAL I PIEN POTENT POTENT. TOTAL O. I ||

| | |w|UNDEV. OKV. UMEV. I LII. OEV.. EV. Il asO.|I ASSO. Sl MAL| | |I |OF SSCF *SKF CF I SCF SSCF SSCF 3SF I SSCF I| FD SCFD |UF

1 2 3 14 S 6 7 I a 9 10 11 I12 113 14 1SI~ ~ 01M

I I ONSHORE II I I I I 2II lUT CENTRAL JAVA PEITMINA III I0.00 0.00 0.00 0.00 10.05 0.00 33.54 4 43.5 0.00 11.90 11.902 zbI TI CENTRAL JAVA MERTANINA III 0.00 0.00 0.00 0.00 6.63 0.00 5.41 12.04 1 12.04 | 0.OO 3.30 3.30

|3 I PERTINA III I 0.00 0.00 0.00 0.00 105.70 0.00 0.00 105.70 105.70 0.00 29.00 29.00I * |M n PERTMINA III I 0.00 0.00 0.00 0.00 56.20 0.00 0.00 S6.20 56.20 0.00 15.40 1540I S IONDAHS IPEToE TRESID1 0.00 55.00 0.00 5S.00 | 0.00 0.00 0.00 0.00 S.OO I 1S.10 0.00 1S.10

I I 53I TOTAL I 0.00 05.00 0.00 SS.OO I 178.58 0.00 38.95 2173.3 1 272.53 I.10 S9.60 74.70 0 0I I e~FFSMXE I ----------------------------------------------------------------------------6 llaA I SELL I 0.00 0.00 0.00 0.00 I 0.00 0.00 500.00 500.00 I 500.00 0.00 137.00 137.00 0I IKE - r I ECO 4.60 0.00 4.70 9.30 0.00 0.00 0.00 0.001 9.301 2.S0 0.00 2.S0 ElI GIKE - 6 I nDE 2.10 0.00 7.60 9.70] 0.00 0.00 0.00 0.001 9.70r 2.70 0.00 2.r-lo 19 9 IKE - S I NDECO I 0.00 0.00 0.00 0.00 1 O4.40 0.00 107.20 241.60 241.60 | 0.00 66.20 66.20 j110 lo0 I NIL 137s.OO 0.00 210.90 S67.90 I 0.00 0.00 0.00 0.00 S67.90 1ISS.60 0.00 1SS.60

I 11 lIDA NOIL 0.00 0.00 0.00 0.00 0.00 0.00 400.00 400.00 400.00 0.00 109.60 109.60 II12 ITERAN UI _I I 0.00 0.00 0.00 0.00 367.60 0.00 0.00 367.60 I 367.60 I 0.00 100.70 100.70 I113 IV. KAWEAN I MtI I 0.00 0.00 0.00 0.00 I 0.00 0.00 367.00 367.00 367.00 0.00 100.50 100.50114 IPAGEUUGAN I ARII 0.00 0.00 0.00 0.00 l1.SS2.10 0.00 0.00 1,SS2.10 1,.S52.10 I 0.00 425.20 42S.20 |

| | |SU0 TOTAL 136.70 0.00 223.20 506.90 12.054.1O 0.00 1.374.20 3.428.30 I4.015.20 1160.00 939.20 1,100.00 | 1----------- ----- ------------------------------------------------------ 1-I---------------------- ---------- 1 --------- 1--- I......................| T O T A L 1363.70 SS.00 223.20 641.90 12.232.68 0.00 1.413.1S 3.64S.0 14.287.73 17S.90 9M.D 1.174.70

AsmAsptimn -a(I). So eel lvey for 10 VW (vi). IawqI -g_t facilitis fncluc X

(if). Associted Gm Pressure 100 fals lw Non Asoistes Gs (a). Offshore sfae fac titlesPfrees 10110 P1si (b). S irm Pa gathering lins e w

(lil. Coet of facilities lomclud Coprows fow Assciated Cos, gatberins lines, (c). Puitication plantmd proces facilities (d). Other _obwe facilities wre

Civ). Field pa coressommad to be re*dred in sixth yar. (vii). Pa*gm fields facilities an locatedCv). All cats ntimted at 191 U# en an islad.

inUIEwLoP NEEMLE Gas UwiWsCENTAL AM UV JAVA OfSEI N OFFIO US FIELDSEWETM Tu PM AM MST SIUINA

I I go. OF IELLS EQUIRED TO K ILLED DIST. S1PLV PIPE | DEVLO NT COST DEFERED GRAND |jNe.jlI No. J| CTION TO JCT. PIL PRES- LINE M . ST TOTAL || | 9EIT4P I OF POINT POINT SIZE tE PiESURE| DRILL PLATFORMS FACIL. TOTAL |fU 6 TO COST| |NETEnS APPSAISAL DVELOP. TOTAL IP|ATf_ IKES PSIC PIC M S M * M S M S I 10 T.uh M M S

~~~~~~~~~~~.. .. .................... ........ ............. .............................. ................................................................ ..................... ................................

I 116 I? is 19 1 20 21 22 23 24 25 1 26 27 28 29 30 31

I Il 2M00 1 1 2 NM PIPELINE 0.00 6 400 650| S.20 0.00 13.90 19.10 2.00 21.10||21 2000 2 2 4 NA PIPELINE 0.00 6 400 650| 10.40 0.00 5.140 15.80 1.50 17.30|

3 2000 2 S 7r MA DANDER 24.00 12 400 650| 18.20 0.00 34.70 S2.901 4.00 56.904 20O 1 3 4 MA UMGJAI 28.50 a 400 6501 10.40 0.00 18.60 29.001 2.00 31.00

| 150S 1 2 3 NA PIPELINE 12.00 6 100 650| S.90 0.00 17.80 23.70| 8.50 32.20|................................................................................................................................................................

................................................................

I I 7 13 20 1 U.50 I 50.10 0.00 90.40 140.50 1 18.00 158.so--*-.----.-.-....................................................................................................................................................................................................................

6 1000 6 a 141 4 SEKULZ 15.00 14 1000 650 34.00 30.00 72.20 136.201 9.00 145.20 0?|7| 2700 1 1 2| 1 IE -S 12.50 6 100 650 113.00 7.5O 3.70 24.20 3.00 2?.20|161 2700 1 1 2| 1 E -5 5.00 6 100 6SO 13.00 O.50 3.80 24.301 3.00 27.301

9'l 2700 2 3 5| 3 GESIIK 33.00 14 700 650 18.00 20.00 6400 102.00 9.00 111.00|10 3200 6 10 16 I 4 SUAAUTA 83.00 16 100 650 1123.00 30.00 176.50 329.50 30.00 359.SO I

| 11 1100 5 6 11 3 PIPELINE 12.00 12 1000 1300 | 29.00 22.50 S8.40 109.90 6.00 11S.90 ||12| 600 4 2 6 2 PIPELINE 2.50 18 900 1300 9.00 1S.00 S1.80 75.80 6.00 81.S00|i 2000 6 14 201 S PIPELINE 4S.00 18 900 1300 | 96.00 37.50 * 258.20 391.70 5 O3.00 444.70114 2500 S 16 21 0 PIPELINE 420.00 28 1900 1300 1126.00 0.00 216.60 342.60 30.00 372.60

I Z36 61 97 23.00 628.00 1 461.00 170.00 905.20 1.536.20 149.00 1.685.20-- - - - - - - - - - - - - - - - - - - - - ---------------------------------------------------------------------- r -...................................-..- ,,--,,,,,,------------,-I

1 I 43 74 117 I 23.00 692.50 511.10 170.00 995.60 1,676.70 I 167.00 1.843.70

(viii) *. The production formtion of W. Kalen structure Is very tight andwould requiro stimlnation. In addition the ftlo pressuwr from wells will decline rapidly.hence the cost of facilities and compression Is estimted hisher.

M M

(Ix). Stron equiter pressure a4port is dssued, this mill minisise coWression requirements.0*

UNDEVELOPED RECOVERABLE GAS RESERVESSOUTH SUMATRtA ONSHORE FIELDS DEVELOPMENT PLAN AND COST SUMMARYIUUUiuuui WU uUm mwmm uuu 333U3 UWIFW umuse UU.uuuU mauwutsm. *goru*m MM *nu mamma== UUmam7 II E GAS RESERVS INON-ASSOCIATED GAS RESERVES ITOTAL IESTIMATED DEVELI VERY II No. I* A?. I OPERIATOR I ROVE POTENT. POTENT. TOTAL ROVE OTENT POTENT. TOTAL ASO., + I

I I I I ~~~~~~UNDEV. DEV. UNDEV. UNDEV. 0EV. UNDEV. ON ASSO ASSO. ON-ASSO TOTALI± I I I B~~~~~~'SCF BSCF BSCF BSCF BSCF BSCF BSCF BSCF I SCF MMSCFD MMSCFD MMSCFD ~~ USUUUmma UmUUU= EUWWOU annual iWinu= uininui =mwus. WaRuMhlh maWOMUM unwm==== mwW=nuuhm uuuuinuh

I ILEKO IASAMERA I0.00 0.00 0.00 0.001 3.661 0.00 3.84 7.401 7.40j 0.00 2.03 2.031I2 ILETANG IASAMERA I0.00 0.00 0.00 0.00 I 4.47 0.00 6.75, 101.22 I101.22 I 0.00 27.73 27.73

3 I SUSAN IASAMERA I 0.00 0.00 0.00 0.00 I0.00 0.00 161.00 161.00 I161.00 I 0.00 44.11 44.11 I

FtI I SUB TOTAL I 0.00 0.00 0.00 0.00 I 98.03 0.00 171.56 256.62 I256.62 I 0.00 73.87 73.87I

4 I TUMELET I TI I 0.00 0.00 0.00 0.00 I 0.00 0.00 11.70 11.70 I 11.70 I 0.00 3.21 3.21 I F~I6 I BUKA I PTSi 0.00 0.00 0.00 0.00 I 0.00 0.00 7.78 7.78 7.78 I 0.00 2.13 2.13 1 C0I SSERDANG I PTSI 10.00 0.00 0.00 0.00 I0.00 0.00 9.30 0.301 9.301 0.00 2.55 2.551 T 7r PETAR I PTSi 0.00 0.00 0.00 0.00 I0.00 0.00 15.70 15.70 I 15.70 I 0.00 4.30 4.30 COI

I ~~~~SUB TOTAL I0.00 0.00 0.00 0.00 0.00 0.00 44.48 44.48 I 44.48 1 0.00 12.19 12.19 0 I I~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

I 8 I BENUANG I PERTAMINA If I 0.00 0.00 0.00 0.00 I0.00 125.00 0.00 125.00 I 125.00 1 0.00 34.25 34.25II 9 I LEMBAK I PERTAMINAI 11 17.CO 0.00 0.00 17.80 I 434.00 0.00 0.00 434.00 1 461.80 I 4.88 118.90 123.78 I I 10 I BERINGIN I PERTAMINAI 11 14.20 0.00 1.02 15.22 I 77.30 0.00 10.06 87.36 1102.58 I 4.17 23.93 28.10 I ti 11 i PAGAR DEW I PERTAMINA 11 I 0.00 0.00 0.00 0.00 I 17.84 0.00 0.00 17.84 I 17.84 1 0.00 4.89 4.89I 1 12 I PRASUMENA I PERTAMINAII1 I 0.00 0.00 0.00 0.00 I161.00 0.00 0.00 161.90 I 161.90 I 0.00 44.36 44.36T 13 5KUANG. I PERTAMINAIl 0.00 0.00 0.00 0.00 I0.00 69.80 0.00 56.80 I 56.80 I 0.00 19.12 19.12I 0T 14 IMUSI PERTAMINAI 11 0.00 0.00 0.00 0.00 I0.00 241.60 0.00 241.60 I 241.60 I 0.00 66.19 66.19I

I I ~~~SUB TOTAL I 3.0 0.00 1.02 33.02 SI69.04 436.40 10.06 1,137.60 1 1,170.62 1 9.06 311.64 320.09

j. I ~~~TOTAL 32.00 0.00 1.02 33.02 I789.07 436.40 226.13 1.451600 I 1,484.62 9.05 397.70 406.75 I~

MI. Gas delivery fo 10 yere (vi). Strong equlfor pressure support is assmed,(ii). Associated Gam ressur 100 Pug and Non Amsocited Gas this edit minimize compresdion requirements.

Pressur 1000 Pdg(Ml). Coat otachoW.4 inckude, Compressor for associatd pas.

gaw- Nnsc mid procss ~i hodes.(14 Fasi gas compressor assumfed to be require In dxth yuewKM.A eonsdlad at 186 USS

0*

UNDEVELOPED RECOVERABLE GAS RESERVESSOUTH SUMATRAONSHORE PELDS DEVELOPMENT PLAN AND COST SUMMARY

m uuuWWuW oo _wu ft Wo a u oooin .uuau _uWW. WWw mum... mum.o. mooummal mas .oummum=oI I No. OFWELS REQUIRED TO BE DRILL I 01ST. PIPE I DEVELOPMENTCOST I DEFERRED GRAND II No. I I JUNCTION OJUNCT PJL SUPPLY UNE I I OMP.COS TOTALI I DEPTH PPRAI- I POINT POINT SIZE RESSUR RESSUR I DRILL FACIL. TOTAL IFROM 6 TO COST II I METERS SAL EVELO TOTAL I KM INCHES PSIG PSIG MM$ MMS MM$ IOY.-SMM MM$ I

o senseU ooW" _._M... .1 &*=mo.m mt==.... omuo nausea...... n--.-- mu.... mue... mm... ss , o I1I1 16o0 1 1 2 LETANG 30.80 a 1000 6501 4.16 5.21 9.371 3.00 12.371

1 2 1 1200 2 4 6 I ILIRAN BAM 27.50 8 1000 650 9 9.36 18.58 27.94 1 4.00 31.9413 S 2400 4 6 9 MUSi 30.00 12 1000 650 28.08 29.78 57.6 I 5.00 62.86

.~ ~ ____ - ..-- - II I 7 10 171 88.00 1 41.6 83.57 95.17I 12 107.171

141 800 0 1 I MUSI 20.00 4 1000 6501 1.04 3.41 4.451 3.00 7.451I51 1300 0 1 I TERAS 7.50 4 1000 a60 1.9 1.73 3.421 3.00 64211 1000 0 1 1 I BUKA 13.00 4 1000 e60 1.30 2.44 3.741 3.00 6.74 1a1 7 1 1500 0 1 1 SUKACINTA 15.00 4 1000 65o 1.96 3.48 S.43 I 3.00 8.43 1

_~~~~~~~ __ _ - II I 0 4 4 55.50 1 5.98 11.06 17.04 1 12.00 29.041

1 8 1 2400 3 4 7 I BENUANG 5.00 10 1000 650 21.84 17.82 39.e6 1 4.00 43.66 191 1700 4 1s 22 1LBABK 6.00 18 1000 6501 48.62 73.41 122.031 8.00 130.0311101 2400 2 3 5 ITANJUNG MI 17.00 8 1000 6oN1 15.60 26.95 41.55 4.00 4S.551I I1 1200 0 1 1 BERINGIN 25.00 4 1000 6501 1.5 4.69 6.251 5.00 1125f

1121 2100 3 9 IPAGER DEW 5.00 12 1000 650e 24.57 22.97 47.641 6.00 53.5411131 1S50 2 2 4 PAGER DEW 18.00 8 1000 6501 7.80 12.63 20.43 4.00 24.43S1141 1400 4 9 13 MUSI S.00 14 1000 6s51 23.06 33.83 67.491 7.W 64.49

I I 18 43 el 81.00 74 143.65 191.30 334.951 38.00 372.951_ _ -~__ _ , ,- I

I I 25 57 82 224.50 74 11s12 2ss.93 447.161 62.00 S09.101Wum m_.. m wwm.. .. mmu mu... M..ost..... ooms ooo WWmW.. _.m.. mum_ namusm mu .owww= mo..oI

OQ fD X

0O

PUGAS 68/WPRESIK1I/ks/07-Nsr-92

UDEVELOPED tEOWERABLE GAS RESERVESCENTRAL SUIATRA ONSHORE FIELDS DEVELOPMENT PLAN AND COST SUISIRY

-- I--------- -- I... == = _sI I I I ASSOCIATED GAS RESERVES NWO-ASSOCIATED GAS RESERVES I TOTAL | ESTINATED DEVELIVERY1N0. I FIELD IOPERATOR IPROVE POTENT. POTENT. TOTAL |PROVEN POTENT. POTENT. TOTAL I ASSO. 4 I II I I IU30EV. OEV. U.NDEV. IUNDEV. DEV. UNDEV. Ij ASSO. I ASSO. NON-ASSO TOTAL II I I I BSCF B SCF SCFIF SCF BSCF BSCF BSCFIBSCF IBC ISCFD SFD MSCFD I

1 ISIDIGIM I CPI | 3.41 0.00 29.73 33.14 0.00 0.00 0.00 0.00 33.14 1 9.08 0.00 9.08| 2 ISIKLADI C CPI I 0.00 0.12 0.00 0.12 0.00 22.74 0.00 22.74 22.86 | 0.03 6.23 6.26I 3 ISEANGA I CPI |12.52 0.00 0.00 12.52 | 78.51 0.00 0.00 78.51 91.03 1 3.43 21.51 24.94 1I 4 ILIBO CPI I 0.00 12.71 0.00 12.71 0.00 18.70 0.00 18.70 31.41 3.48 5.12 8.60 nI 5 ILIDO S.E. [PR I CPI I0.00 15.29 0.00 15.29 I 0.00 20.62 0.00 20.62 1 35.91 1 4.19 5.65 9.84 116 ININAS IPR I CPI I 0.00 29.43 0.00 29.43 1 00.00 .00 0.00 29.43 a 8.06 0.00 8.06 1I I---------------------------------------------------------------------------------------------------------------------------...

...........I I SUB TOTAL 115.93 57.55 29.73 103.21 1 78.51 62.06 0 140.57 1 243.78 1 28.27 38.51 66.78 1

1 7 IJIGA I C & T 0.00 0.01 0.00 0.01 I 0.00 30.36 0.00 30.36 1 30.37 | 0.00 8.32 8.32 II8 IKELADU I C&T I 0.00 0.00 0.00 0.00 I 0.00 0.00 22.88 22.88 22.88 1 0.00 6.27 6.27 I

'0I I SUB TOTAL I 0 0.01 0 0.01 I 0 30.36 22.88 53.24 I53.25 I 0.00 14.59 14.59 III I . . . ..... ...

I TOTAL 115.93 57.56 29.73 103.22 1 78.51 92.42 22.88 193.81 297.03 1 28.27 53.10 81.37 I

Asusptfos:rti). Gm delivery for 10 years(f ). Assci§ated Gas PressUre 100 Psig and Non Associated Gas

Pressr 1000 Psig(ffi). Cost of facilities Include, coWrssr for associsted as,

gstherfln Lines, and process facilitles.(iv). Feltd gss caqxessor assued to be required In sixth yearCv). All costs estimted at 1991 USS F'(vi). Strong quifer pressure suport Is asued, this will minaiize copression requirements.

PWGAS 68/UBPRES/WKlIkh/07-Nar-92

WDEVELOPED RECOVERABLE GAS RESERVESCENTRAL SUMATRA ONSHORE FIELDS DEVELOPMENT PLAN AND COST S3UAMRY

No. OF WELLS REQUIRED TO BE | DIST. PIPE DEVELOPMENT COST I DEFERRED GRAND |INo. I I JUNC- TO JUNCT. P/L SUPPLY LINE ICOMP. COST TOTAL II I DEPTH APPRAt- DEVELOP I TION POINT SIZE PRESSURE PRESSUREI DRILL FACIL. TOTAL IFRON 6 TO COST II IMETERS SAL MNT TOTAL I POINT KD INCHES PSIG PSIG |IMS MS M S 11° Y.'S M U S

~~~~~~~~~~~~~~~~~~~~ ~~~~~~~~~~~~~~~~~~II 1 2500 1 1 2 SIDINGIN 5 6 100 650 6.50 6.90 13.40| 2.00 15.40

|21 1800 1 1 2 SIKLADI 10 6 1000 650 4.68 5.10 9.78 3.60 13.381| 3 354 2 3 5 SEBANGA 10 10 1000 650 2.30 10.37 12.67 4.09 16.76|I 4 2100 1 1 2 LISO 5 6 1000 650j 5.46 7.00 12.46 " 1.50 13.96 I

|5 1400 1 1 2 LIBO 7 6 1000 650 3.64 8.18 11.82 1.50 13.32|161 1C00 1 1 2 MINAS 15 6 100 6501 2.60 7.99 10.591 2.54 13.13. .. ......................................... ....................................................................................

--... -- .... .. -.....-*-- -----------

I I 7 8 151 52 40 4200 3900 1 25.18 45.54 70.72 1 15.23 85.951

| 7( 3000 1 1 2 |WDUK 13 6 1000 650| 7.28 7.90 15.18| 2.18 17.361I 81 2800 1 1 2 I DUK 10 6 1000 6501 7.28 5.98 13.261 1.53 14.791.....---... I..-...-.-....-.-....--- ..-..--.-.-.-.--.-...----..-.-----.----.-------..--.------..-..-...-.....-....------ 1.

i1s5 2 2 4 23 12 2000 1300 1 14.56 13.88 28.441 3.71 32.151............................................ .........................................................................................

,__...___._I

IIf I I I I.... ......_ ________ ................................................................... __ ______.... ___..........................................__...........I

1 1 9 10 19 | 75 52 | 39.74 59.42 99.16 | 18.94 118.10 I

OQ :

0*

UNDEELOPED RECOVERABLE GAS RESERVESNORTH SUMATRA ONSHORE AND OFFSHORE FIELDS DEVELOPMENT PLAN AND COST SUMMARY

UU UUUUUUUmU UUSUmUU inMWMMMM 00moa WWmM== =urn=. Maso=a. m0 000M... m000=== mmnium M0MW0MMI I I I TED GAS RESERVES I NON-ASSOCIATED GAS RESERVES I TOTAL I ESTIMATED DEVELIVERYI No. I FIELD I OPERATOR I PROVEN POTENT. POTENT. TOTAL I PROVEN POTENT. POTENT. TOTAL I ASSO. + I II I I I UNDEV. DEV. UNDEV. I UNDEV. DEV. UNDEV. I ON ASSO I ASSO. ON-ASSO TOTAL II I I I BSCF 8SCf BSCF BSCF I BSCF BSCF BSCF BSCF I BSCF I MMSCFD MMSCFD MMSCFO I

I*. U _ _ U _ _ m 0 * .. U... .UU U ....... U... U u m. mmma ........ m m ....... mm.. .mm W

I I ONSHORE I I II 1 I CUNDAA I MOBIL I 0.00 0.00 0.00 0.00 I 16.30 0.00 0.00 16.30 1 10.30 1 0.00 4.60 4.80 11 2 I S. ARUN MOBIL I 0.00 0.00 0.00 0.00 1 0.00 169.00 0.00 156.00 159.00 1 0.00 43.60 43.00 01 3 IRAYEUC IMOBIL I 0.00 0.00 0.00 0.00 1 8.30 0.00 0.00 8.30 1 8.30 1 0.00 2.30 2.30 11 4 I LHO SUKON AN. I MOBIL I 0.00 0.00 0.00 0.00 I 19.50 0.00 0.00 19.60 I 19.60 I 0.00 5.30 6.30 i1 5 I LHO SUKON AS. 1 MOBIL I 0.00 0.00 0.00 0.00 1 250.10 0.00 0.00 250.10 250.10 I 0.00 08.50 68.50I S I LHOSUKONBS. I MOBIL I 0.00 0.00 0.00 0.00 1 27.40 0.00 0.00 27.40 1 27.40 I 0.00 7.80 7.50 Z1 7 I PEUTOWLS I MOBIL I 0.00 0.00 0.00 0.00 I 55.00 0.00 0.00 55.00 I 55.00 I 0.00 15.10 15.10 1 rt

SUB TOTAL I 0.00 0.00 0.00 0.00 1 376.60 159.00 0.00 535.00 5 535.60 1 0.00 140.80 146.80 1 bI I _ ___ _ _ S _

1 8 I JULU RAYEUJ 3AS1MERA I 0.00 2.00 0.00 2.00 0.00 31.71 0.00 31.71 33.71 0.50 8.70 9.20 1 CI I__3

0)

II SUB TOTAL I 0.00 2.00 0.00 2.00 I 0.00 31.71 0.00 31.71 1 33.71 1 0.50 8.70 9.20 1 aI I __ _ . _ , _ - t 1 9 I KUALSIMPANG I PERTAMISNA I 0.00 34.30 0.00 34.30 1 0.00 77.40 0.00 77.40 I 111.70 1 6.40 21.20 30.60 I tD 3 1 10 ISERANGJAYA I PERTAIMINA I 0.00 91.40 0.00 01.40 1 0.00 0.00 0.00 0.00 1 01.40 I 26.00 0.00 25.00 1 F 1 11 jP.TTUBUHANBR IPERTAMINA I 0.00 16.40 0.00 18.40 1 0.00 10.00 0.00 10.00 1 26.40 1 4.80 2.70 7.20 1 x tI

12 P.TUBUHANTM PERTAMINA 0.00 1300.00 61.30 I 0.00 2.70 0.00 2.70 64.00 1 14.10 0.70 14.80 mg~~~~~~ ~ ~~~ ~ ~~~~~~~~~~~~ . _ - :3 >S UBTOTAL I 0.00 193.40 0.00 196.40 1 0.00 90.10 0.00 90.10 283.50 53.00 24.60 77.60 1 'I I __ _ _ _ _ _ _ _ _ -

I I OFFSHORE I I I I I , I P1 13 I NSBJ1 1 MOBIL I 0.00 0.00 0.00 0.00 1 165.10 0.00 0.00 155.10 1 165.10 1 0.00 42.80 42.S0 1

1 14 NSSJ2 IMOBIL I 0.00 0.00 0.00 0.00 1 189.70 0.00 0.00 159.70 I 159.70 1 0.00 43.80 43.80 1 '

1 16 NSBA I MOBIL I 0.00 0.00 0.00 0.00 1.426.40 0.00 0.00 1.426.40 1 1.425.40 1 0.00 390.50 390.50 111 INSBS IMOBIL I 0.00 0.00 0.00 0.00 1 8.50 0.00 0.00 8.80 1 8.50 I 0.00 2.30 2.30 CA

I I ___________ SUB TOTAL I 0.00 0.00 0.00 0.00 I 1748.70 0.00 0.00 1,748.70 1 1,748.70 I 0.00 479.10 479.10 1

I TOTAL I 0.00 195.40 0.00 197.40 1 2,125.30 280.81 0.00 2,406.11 2,00151 I 63.80 659.20 712.70 1Im mmumumu.mm MMuMuM n M_un= MUmma. Mumma MM. .. mu .. Om.. ma Maso.. n=O=sw mm =.... m..... u..,...

AsuAmpon:).GaDsDveryi ory10 ears (vi. De pment inludes Facilies

(I). Asocltod Ga Pure 100 Pdg nd Non clated Gas (a). Ollhore sudace laclltesPressure 1000 Pgo (b). Submarine gas gathering lines m X

(IN). CGoc d aleIlit Ineludeg. empor kr ocked (C). Purificatlon pant Hgas, gaherIng nes, ad process itIes. (c). Other onshore hcilities where needed O.

(i. Ried gs eemnopsor assmed to be required In dxth yea. n O(i).M l_code matd at 190 USS (vii '. Mobil etimates US $ 300 Million to remoe acid gases. I.

UNDEVELOPED RECOVERABLE GS RESERVESNORTH SUMATRA ONSHORE AND OFFSHORE FIELDS DEVELOPMENT PLAN AND COST SUMMARY

= _ _ ._nall u..uu..muU.. ........ .. . .. mu..... . . . . . . m. ..... mm ... . .. n.... momm=a....... m . u..... . ... mu..... *9mI NO.OFWELLSREQUIREDTOBE I I DIST. I PIPE No. I DEVELOPMENT COST I DEFERRED GRAND II NO. I DRIFLLE I JUNCTION I OJUNCT I P/L SUPPLY UNE PLAT I 9 COMP. COST TOTAL II I ODEPTH APPRAI- EVELOP- I POINT I POINT I SIZE RESSUR PRESSURE FORM D DRILL COSTOF PLAT TOTAL I FROM 6 TO COST I

I I IMETERS SAL MENT TOTAL I I KM I INCHES PSIG PSIG M MUS FACIUTIES FORM MM$ S 10 Y.-US$ MM MM 5" um s n. uu. mu... w.=... mmumuuuum am===== ummwas mass== m.u.muss =urn= mumM.S. wusrn..s .. a..= u.S.M wuUm==u mUmmus I I I I I I I IIt 3.700 1 1 2 ILHOKSEMAWE I 51 12 1,000 660 01 9.02 5.00 0.00 14.621 1.50 16.121121 3.400 3 e 9 ARUN 1S 12 1.000 e6o 01 39.00 21.00 0.00 60.001 9.80 69.80113 1 3200 1 2 ILHOSUKONAN. I 101 10 1,000 eso o1 8.32 3.80 0.00 12.121 1.50 13.e21141 2.400 1 1 2 LHOSUKON UTA I 01 14 1.000 650 0 6.20 14.00 b.00 20.201 1.50 21.701156 3,100 5 9 14 ALUR SIWAH 239 16 1,000 6s0 0o 56.42 33.30 000 89.721 15.60 106.3216 1 2.700 1 1 2 ILHOSUKONAS. I 5 a 8 1,000 650 0 7.02 5.68 0.00 12.701 2.50 15.201171 1.500 2 2 4 ILANGSA I 101 12 1.000 650 01 7.80 9.00 0.00 16.801 3.00 19.801

I - I - 14 21 36 _ 9 68.00 I 1 134.38 91.78 0.00 226.16 1 35.40 261.56

8 12.000 1 1 2 IKOTABINJAI I 101 8 1,000 6so 01 5.20 6.30 0.00 11.501 2.50 14.001_ _ ~ ~ ~ __ .- _ _ I _-181 1 1 2 IKOTABINJAI I 10I a 1.000 eso 01 5.20 6.30 0.00 11.501 2.50 14.001

19 I1 .0 4 2 8 I KUALASIMPANG I 01 10 1,000 650 01 11.70 6.20 0.00 17.90 7.00 2410 1110 1 3.000 2 3 6 I KUALASIMPANGI 13 10 100 650 01 19.50 12.00 0.00 31.50 1 .00 37.60I1 11 1 1.700 1 1 2 I P.TABUHAN8AR I 01 6 1,000 'I 01 4A2 12.95 0.00 17.371 1.50 18.l71121 2,100 '2 1 3 IP.BRANDAN I a I 8 1,000 650 0o 8.19 6.20 0.00 14.399 3.00 17.I I 9 7 16 1 1 21.00 34 09 43.81 37.35 0.00 81.169 17.50 96.661I I I I I I I I1131 1.500 2 2 4I NSN I 101 12 1,000 6s5 19 14.40 31.00 7.60 52.90 0.00 52.90s914 1.510 2 2 4 NSBJI I s11 12 1.000 6so 19 14.40 33.00 7.50 54.90 0.00 s4.s0os169 1.600 10 29 39 ILHOKSEUAWE I 5 1 28 1,000 650 7 149.70 579.20 95.00 823.90 30.00 853.9099169 1,460 0 1 1 INSBA I 201 12 1.000 eso I 1 3.48 23.40 7.s0 34.381 0.00 34.381

I I 14 34 489 I 50.00 64 10 1181.96 66.60 117.50 se8.081 30.00 996.08

9 1 38 63 101 9 149 1 365.37 802.03 117.60 1.284.901 85.40 1.370.30

oLAFh a

EAST KAUIMANTAN ONSHORtE AND OFFSHORE GAS FIELDSDEVELOPMENT PLAN AND COST SUMMARY

IUUUUUU iUUUiUinU WWWWW WWWWW WWWuiun mim . w.U uum vmu mI I I ~~~~~~~ED GAS RESERIVESI NON-ASSOCIATED GAS RESERVES I TOTAL ESTIMATED DEVEUVERY

I No. I FIELD I OPERATOR I ROVE POTENT. POTENT. TOTALI PROVEN POTENT. POTENT. TOTAL I ASSO.. + I I I ~~~~~~~UNDEY. DEV. UNDEV. UNDEV. DEV. UNDEV. NON ASSO. ASSO. NON-AMS. TOTAL I I I B~~~~~~~SCOF SSO SCF BSCF USOF BSCF BSC F BSCF BSCF MMSCFDI MM SCFD MSFO MUSOFO

I ON1SHORE I I IIII I ITANTA I PEFRTAMINA IV I 0.00 2.76 0.00 2.760 0.00 22.20 0.00 22.20 I 24.96 0.76 0.08 6.84I

I2 TWAPA TERni P I PERTAMINA IV I0.00 0.00 0.00 0.00 I 0.00 232.60 0.00 232.60 I 232.60 0.00 63.73 63.73 I3 IUNYU +NIBUN I PERTAMIINA IV g0.00 84.62 0.00 84.92 I 0.00 36.64 0.00 36.64 I 121.66 I 23.27 10.04 33.31I

I I ~~~~SUB TOTAL 0.00 87.68 0.00 87.68 I 0.00 291.44 0.00 291.44 I 379.12 I 24.03 79.85 103.88I

I4 IMUTLARA I UFFCO I0.00 49.00 0.00 49.00 0.00 166.30 0.00 166.30 I 216.30 I 13.42 45.56 88.988I I PAMAGUAN I HUFFCO I 0.00 0.00 0.00 0.00 I 0.00 14.40 0.00 14.40 j 14.40 0.00 3.95 3.965 I 6 NILAM I HUFFCOO 0.00 25.90 0.00 25.90 I 0.00 707.60 0.00 707.600 733.50 I .7.10 193.86 200.96 j t

I 7 I ADAKC I HUFFCOO 0.00 18.40 0.00 18.40 I 0.00 490.60 0.00 490.60 I 509.00 I .04 13..41 139.45 I 'I 8 ISEMUERAN I HUFFCO I 0.00 18.00 0.00 18.00 1 0.00 160.20 0.00 160.20 I 178.20 I 4.93 43.69 48.82 I-

I I ~~~~SUB TOTAL I 0.00 111.30 0.00 111.30 I 0.00 1.539.10 0.00 1539.1I 1650.4I 17.07 376.11 393.18 0

I IOFFSHORE COI9 IPANTAI IUNOCAL I0.00 0.00 0.00 0.00 I 11.17 0.00 0.00 11.17 I 11.17 1 0.00 3.06 3.060 4I10 PETUNG UNOCAL 0.00 0.00 0.00 0.00 j 11.32 0.00 0.00 11.32 I 11.32 * 0.00 3.10 3.10 I -4 ..I11 ISESUJLU IUNOCAL I0.00 0.00 0.00 0.00 97.00 0.00 0.00 97.00 I 97.00 I 0.00 26.68 26.58 I 0 I 12 ITENGAH I UNOCAL I 0.00 0.00 0.00 0.00 I 18.35 0.00 0.00 18.35 I 18.35 I 0.00 6.03 603 I , 0I 13 j PEMARUNG I UNOCAL I0.00 0.00 0.00 0.00 24.93 0.00 0.00 24.93 I 24.93 I 0.00 6.83 6-.83 I zI 14 IATTAKCA I UNOCAL I 0.00 96.60 0.00 96.60 0.00 0.00 0.00 0.00 I 96.60 j 26.47 0.00 26.47 I ttI 15 I SANTAN I UNOCAL 140.00 0.00 0.30 40.00 * 17.53 0.00 0.00 17.63 1 57.53 I 10.96 4.80 16.76 I

I I SUB TOTAL I 40.00 96.60 0.00 136.60 IS18.3 0.00 0.00 1810.3j 316.9 I 37.43 49.4 86.83II I_

_ _ _I 16 I TAMBORA I TOTAL IND I 0.00 19.80 0.00 19.80 I 0.00 624.34 0.00 624.34 I 644.14 I 6.42 171.05 176.47II17 IBEKAPAJ TOTAL IND I0.00 74.50 0.00 74.60 I 0.00 93.67 0.00 03.57 I 1CO.07 I 20.41 25.64 40.06I18 IHANDIL ITOTAL IND I .00 211.87 0.00 211.87 I 0.00 158.16 0.00 158.16 370.03 I 681.05 43.33 101.39I 19 ITUNU ITOTAL END 1 6.00 0.00 0.00 0.00 I2.828.40 0.00 3.655.00 6.483.40 0,6483.40 I 0.00 1.776.27 1.776.27

I I I I ~~~~SU TOTAL I0.00 306.17 0.00 306.17 I281128.40 876.07 3,655.00 7.359.47 I76065.64 I 3.88 2.016.29 2,100.17

ITOTAL 40.00 601.75 0.00 641.75 3 3008.70 2.706601 3,656.00 9,370.31 10.012.00 162.41 2.521.65 2.684.06

Qii. Associatd Gas Presmur 100 PsIg and Non Associated Gas (hiv. Strong equller pressure suppont Is assumed, this wIN minimize *Pressur lOoo Pug compression requirawnt

(HI). Cod d1 fAcUe 11 nclude,b compressor INr associated gas.gv. NA: NcM AvallablegailwirlIng us,and procsess olNllse.0Pl) iedd goa oompresso assmed luDbe reqirdW In slid, yw

(V). AU eo Idmat at 164USS

EAST IALIMAWTAN ONSHORE AND OFFSHORE GAS FIELDSOEVELOPMENT PLAN AND COST SUMMARY

oI N.OF WELLS REOUIRED TO I DIST. PIPE I DEVELOPMENT COST I DEFERRED GRAND1 NO. I BE DRIED NO.d I JUNCTION 0 JU4C P1L SUPPLY UNE I ICOMP. COST TOTAL II I DEPTH PPRAI-DEVELOP PLAT- I POINT POINT SIZE RESSUR PRESSURE I DRILL FACIL LATFOR TOTAL I FROM 0TO COSTI IMETERS SAL MENT TOTALFORM I KM INCHES PSIG PSIG I MM$ MI$ MM$ MM I1o0Y.USSM MS I

u uuuuuu inu winu muusuu mm Wmuu muinw~ muuu umummummamuw wumunwa anwumum uuuumam

It 2300 1 i 2 oI HULU PELAPAI B 12.5 0 1000 660 86.00 4.00 0.00 90.001 1.50 91.502 1 3341 2 4 6 a - - 0 1000 601 906.00 35.00 0.00 131.001 3.00 134.003 SI 3215 1 2 3 0o - - 0 1000 6501 12.E0 18.60 0.00 31.001 1.60 32.60

. _ I~-I I 4 7 11 a 194.50 57.60 0.00 252.00 6.00 258.00 I

41 2500 2 4 6 o PIPELINE 5.0 0 1000 6501 19.50 31.00 0.00 50.501 3.00 53.603S 1 4000 0 1 1 0 PIPELINE 3.0 0 1000 6501 5.25 2.50 0.00 7.75 1.60 9.251161 5600 4 a 13 o PIPELINE 5.0 0 1000 6501 93.00 104.00 0.00 t97,00 1 9.00 206.007 4100 3 6 9 o PIPELINE 5.0 0 1000 6e01 48.00 72.00 0.00 120.001 0.30 126.308 313527 2 3 5 oI PIPELINE 23.0 0 1000 6501 23.60 26.20 0.00 49.803 2.20 62.00

I I 9 19 28 01 I 1609.5 204.70 0.00 374.65 I 19.00 393.66 I. _ I~-

19 1 1262 0 1 1 0 IPIPELINE 5.0 0 1000 6051 3.00 6.50 0.00 9.601 1.50 11.0011101 7204 0 1 1 t PIPEUNE 6.0 0 1000 650 5.25 4.00 7.60 16.75s 1.60 18.251 _111 2943 1 2 3 t PIPEUNE 6.0 0 1000 680N 21.00 13.00 7.60 41.601 1.60 43.001

12 1 3272 0 1 1 1I PETUNG 0.0 0 1000 660 I 8.00 14.00 7.60 29.50 I 1.60 31.00 1131 2600 1 1 2 1 PAGAT 7.5 0 1000 6M 1 12.00 19.00 7.60 38.60| 1.50 40.001141 3000 1 2 3 2 IPIPEUNE 12.0 0 1000 so 1 21.60 72.00 15.00 108.01 1.50 110.1011514137 1 1 2 1 IATTAKA 18.0 0 1000 650 1 20.'0 43.20 7.60 70.70 1.60 72.20

_ -_ - - - - II I 3 9 13 1 02.5 0 90.85 171.70 62.60 316.05 3 10.60 325.65 3

116 13000 6 7 12 4 PIPEUNE 10.0 0 1000 6e01 80.40 91.00 30.00 207.401 8.00 215.4017 13000 2 3 6 I PIPEUNE 5.0 0 1000 6501 36.00 36.00 15.00 87.001 2.00 s.00e1161 3478 3 4 7 *3 PIPELINE 9.5 0 1000 6603 50.40 54.00 15.00 128.401 5.00 133.4019 4230 6 53 Go II ITAMBORA 8.0 0 1000 660 I 600.00 S11.00 100.00 1,211.00 80.00 1201.00

-~ -II 1 16 07 3 21 I 32.5 781.00 602.00 160.00 1.633J0 I 05.00 1,726.80 3

32.00 102.00 21.00 j 95.00 I 1.237.00) 1.125.90 212.60 2.575.40 I 130.60 2m6.s05 I

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DOESIA

NATURAL GAS DEVELIPIT PLAISIN S1W'f

Useb Java

on(Al I ttgvreo a l D))

A A199 19 9 u ! I A IA'19 1 A ¶ 1 9 1 A1A 21 I A A 20 2 001M 1 e 2 00 5I A2 A 0 'M

Fertil r K" Jan 94 106 94 110 96110 9110 96#110 9 110 96 110 96 110 96 110 96 110 96 110PetrochemIcal Kujang0, 45 62 48583 46 58 4855 48 6549 56 6156968361 54 62 56 65 5766sPLN, Muara Karang/Tanjisg Priok 85 96 159 188 1683 17 278 314 242 279 239 275 238 274 238 274 238 274 238 274 288 274PL", So ~10 12 10 12 10122 10 12 10 12 1012 101210 12 10 12 10 12 10 12Ste ;Prosb k"O 187 167 187 167 187 157 137 157 137 167 187 167 187 167 137 .157 187 167 187 157 187 157noSDor and LPG extraction Balogap 40 48 40 48 40 46 40 46 40 46 40 46 40 48 41 47 42 49 48 60 46 52Soe C b1i~n?",Indocesent i i 1618 161 161 1616 i 1618 s i i s i 16 3 61 1 1 161 1616 i 17 20S_n raimdustry 116 183 169 160 161 185 192 221 260299 292 836 2 877 859 413 892 451 428 492 466 585R.sld nt*I8/coircial 14 15 13 16 15 17 15 17 16 18 17 20 18 21 20 23 21 24 22 26 28 27

Total 56 639 O64 764 674 774 827 960 06 994 8N 1050 984 1074 970 1116 1006 1157 1046 1208 1089 1252SVNPLI

Existing Svpply 200 210 200 210 200 210 200 210 200 210 177 195 152 167 130 148 112 128 98 108 so 95 NeM Supply 276 290 34 3528 a34 3525 49 57849 578 693 730 98 780 6938 780 720 758 720 758 720 7586Total supply 476 500 I a34 562 5164 562 1749 768 1749 788 1870 925 1345 C97 1823 878 I 882 881 I 818 366 1 8C0 853A a Averag pay; U u Maximum DovPupu Kuang Average 9Dy Suppl4f, lAyti: 4: 2 W c pd

The existing suyply consists of 180 lcfd ex L-Psrigi end 20 Wscfd from onshore fiolds, discounting 85 llcd ex Arjuns which *111 terminate 1994Adtion s,y 'd Ex I Po Xdsu * 2800E x. I ffshore IT*ds a 29Ex Per tainx onshore fiolds a 882

ARCO mdswsepedNJava = 160Totalw oval abln spply u 200 * 29 * 882 1 150 200 (existing supply frm L. Prigul and Arjuna. Hoo"r, it viII start tapering donn in 1999).

qI

-79-Annex 3.10

INONESIA Page 1 of 2

NATURAL CAS DEVELOPMENT PLANNINC STUDY

WST JAVA

Ona Dovelopmnt and Cost Profile

11-94 11996 11996 11907 1 19 I 1999 12000 I 2001 I 2002 I 2008 12004

(1) as* FonrsumchMWnincalloud ref Ineryl ( I I I I)nad pron u ogle r689 |754 774 9C01 994 1080 11074 1 1151 1157 1 12081 1252 1

) Existing Supply 1 210 I 210 I 210 I 210 I 210 16 1 167 I 148 I 128 I 106 I 9C 1Additional supply required 1429 544 I 564 740 I 7C4 1ca61 907 19721 1084 I 1095 11157 1

) Now Supply Availablo 1 290 I 352 $ 62 I 576 576 I 7a0 W 10 I 780 I 7531 756 756

Source of SupplyFrom proven developed remaining (UMSCFD)resrvesPERTAMINA EP III

Ctcouh O8 80 80 80 30 80 80 80 30 30 30Clloa yo (North) 87 37 37 37 37 87 87 87 87 87

glan'tar 28 28 28 28 23 28 28 28 23 28Randagon 2 2 2 2 2 2 2 2 2 2

exu Subtot l 14 14 14 14 4 4 14 14 4 1

Total Supply from Proven Roservos 30 92 92 106 106 106 106 106 106 106 106

From Undeveloped Reserves

Portotnor ISI IC_cauh 86 86 8s 86 86 86 83 83Ceses 73 78 78 78 78 73 78 73Cs an 12 12 12 12 12 12 12 12Neurcault I 49 49 49 49 49 49 49 49Onntdr 22 22 22 22 22 22 22 22Kandan (TMR)a Randegan 5 5 5Walst Utra 15 15 s

Subtotal 212 212 212 212 212 240 240 240

ARCO (ARSI) Offshore UndevelopedRoerves

NYA (NWC) ~~~39 39 *' *9 80 89 89 89 89 89 80Bp (Nt) I 81 81 81 81 81 81 81 81 11 81

U. ~~~~~~~~~~~~2 22 22 22 22 22 22 22 22 22 22

SC$ 1 1 14 1 14 1 1 1 1 1 1

Subtotal 1 260 260 260 260 260 260 260 260 260 260 260

ARCO Undeveloped RecoverableReservoes I I I I I

From addition reserves In offshorearoe W fields 18 1|7 14 87 1i 187 s18

Maxus I - -15-- 15 15 1it 15s 15

Totel SuppIy from Proven and 1 290 182 152 1 57S 576I 780 1 780 1 7801 751 1 7681 716Undevelop d Rserves

NOTES:

ports Ino UnTt P! onnhoro fieldo *r brought on production to met incresed gas dmand.C n ynlt E IJX gdditi ns fI-eds *r brouM an producttontomset Incry gl dmn In a ph progr

tRCunsl ass (under de lpqdr r eerve.) cn fonsdered ror supp y of ilde tonalscomas:fc mspou, CeO North West Java ARU *o the undevlpde o acing *tu 4ture.whe*xp1ntlrnPro;1 r tOtne*9ypl 1 unofo a -lbErnl t ruc t ures.A ma ntaun 2C s u p s soW has bd t up v ere'

Java hic can be developed to me the domtic nd

INDONESIA

WST JAVA

OAS DEVELOPMENT AND COST PROFILE

(DEELMENT COST IN US DOAS MILLION)

1992 1993 1994 1995 1996 1997 1990 1999 2000 2001 2002 2003 2004Cost of Development of Proven

Developed ReservesUNIT EP III onshore (4 structure) 30 96 653 - a 6 18MII (offshore NW Java) 17 structures 106 126 74 175 a2 22 62 110 78 16 26Maxus - Offshore NW Java

(associated gas) 10Subtotal l 136 l221 127 1756 32l 32 62l 1161 961 15 261- I I

Cost of undeveloped recoverableresrves

P ortef; hr 120 120 68 20 22ARCO (MlII) offshore 55 150 45 45 80 45 30 goMaxus offsore r=30 _ _

Tot I 1136 12761 397 40 1761 92 11071 1461 1261 15 461 221 1

m ¢

O

INWNESIA

NATtRAL UAS DEVEPMENT PUIWDNN STUDY

EAST AND CENTRAL JAVA

Consumption and Supply Projections(All figure in MMSCFD)

19945 1995M 19961 1997 1996 1999 20001 20011 20021 2003 I 2004Y E A R IA V A VIA I A VIA MIA M A VIA M1A MIA V A VI

C0NPUWTI0N

_atJv I I I I I I I I I I I IE JavaI I I I I I I I I I I I

_ ~ ~ ~ ~ ~~I I I I I I I I I I I IFertilizer, Gre ik 45 52 49 566 49 66 49 58 49 66 46 68 49 66 49 66 49 66 49 566 49 66

PLN, Gesik 1176 206 1226 260 1231 266 1281 266 1231 26 1231 2M6 1231 26 1281 286 1281 266 1231 286 1231 286 ICeneral Industry I 5 61 168 72 72 68 1 93 107 1104 120 1116 184 1132 152 1144 166 1167 190 1172 198 1189 217 IReeidmntial/Comrcial 11 1 1 1 1 1 1 1 1 1 1 1 12 2 2 2 2 2 12 2 12 2

Total 1277 819 1889 889 1353 406 1375 430 1386 443 1397 466 1414 476 1426 490 1439 604 1464 622 1471 641 ICentral Java I I

I I I I I I I I I I I I cPLN, Sbmarrng 1 - - I - - I - - 1127 146 1197 226 1197 226 1197 226 1197 226 1197 226 1197 226 1197 226 1 I

General Industry I - - - -I - -18 1 32 37 160 57 66 4 160 691 65 76 71 82 178 90|Residential/Com.rcial 1 1 I 1 1 I I 1 I 1 I I

Total I | 1140 161 L229 263 1247 263 1253 290 1257 295 1262 301 1268 308 1275 316 |

Total for East A Central Jav*I277 819 1339 889 1353 406 15515 91 1616 706 1644 739 1667 765 I683 785 1701 806 1722 830 1746 867 I

SUPPLY I I I I I I I I I I I IEx (Central Jva) onshore | I 164 90 1U 804 0 806 1 4 80 164 80 56 80564U 8056 4 80 |

f ieds 1 1 1 1 I I I I I I IEx(East Java) offshoro fioldsl346 482 1846 q32 1346 432 5466 682 1546 682 16 682 5162 782 M162 782 1626 782 1706 882 1706 882 1

Total Supply Available 1846 482 1346 432 1346 432 1530 662 5610 762 o6LO 762 5690 862 1690 862 1690 862 5770 962 1770 962 1

X

NA1URAL GAS DEVELOPLET PLANNING SWUDY

East and Central Java

Gas Development Profile (WSCFD)

I IM1 19931 1994 1995 1996 I 1997 1990 1999 2000 I2001 I 2002 I 2003 I 2004-Eat Jwas Consumpton I -I - I t19 I891 4661 4301 4431 461 4961 490j 5041 5221 6411Central Java ConsumptionI -I -I -I -I -I1611 2631 2831 2901 295 801I 801 83161

Total Consu.ption I I -3191 889 4061 591 7061 7899 765 7851 NS 80 8571a a - - - ~~ ~~ ~~~~~--- --- - =----

Source of Supply

Cntra 1 Java on 9M 1998 1994 1996 1996 1997 1996 1999 2000 2001 2002 2003 2004Shore

Pert inr (onshoro)Tobo 29.0 29.0 29.0 29.0 29.0 29.0 29.0 29.0Danager 16.5 15.6 15.5 15.5 15.5 15.5 15.6 16.6Condong 15.6 15.5 16.5 15.5 15.6 15.5 15.6 15.6Shall (offshore)Muria 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0

Subtotl I 80.0 80.0 60.0 80.0 80.0 60.0 80.0 60.0Eat JavaKODECO (offshore) oKE-C 40 40 40 40 40 40 40 40 40 40 40 4P 40ARCO (ARBANI)PagCrunpAn 392 392 392 392 392 392 392 892 392 392 392Terangp 100 100 100 100 100 100 100Kangean 100 100

MOBILWA 100 100 100 100 100

Subtotsl 40 1401 432 14321 4321 6821 6821 6821 7821 7821 7821 8821 8821Total 40 40 432 432 432 662 762 762 862 862 862 962 962Notes

1/. Ecat Java will Initially be supplied by Kodeco 0 40 MUSCFD and ARBNI (Pagerungan at 392 MMSCFD)2/. Mobil D will ab developed to produce 10 IUSC D in 1995 to increase total gas supply to 582 4CFD 432 * 150 = 582 MMSCFD)3/. ARBNI Terang will be produced to ply I in 1998 to incrse682 ScFD 432 10 100 = 682 ISCFD4/ MobIl Madura WA *ill b woo d top yrdu 100 MM SCFD in 1996 200 to increase tot rl graupl to 782 MMSCFD (432.150.100.100=724/ Mob duWes MDngAn will ha developed prodc 100 MMSCFD In year 2000 to increase tot gaslC/ lWest Kvongon *II bedVOlOpdto produce 100 MMSCFD in yer 2003 to increse as supp t MSCPD (48 *150.100.1U6/. Prom proven developed recoverable c sr ther Iu net assoclated gas (about 17 MM!CFD) evae able from Enterpris and Petro_er-Trendfields. It has not been included in suply *etiat.

lb

0.Ph

I

Eat and Central Jave

DEVU.0!E CST (USS IO

1M I 1MI 1994 IM9 1"$ 1997 199! 1999 2000 2001 202 03 20Central Java S0 40 0 _ _2 2004

East Java- - -- - - -- - -

KE65 107 4Pagr.g n 76 166 112Tarang 48 10 16Kongean 26 89 89so 83 92 92 92 23 23UDA 69 23 23 ___- :

Subtotal I 12 1190 1195 140! 1081 179 23! 23i 266 1 89 189I ____

Total I 12 11901 196 1 1901 148 1791 231 231 26e 891 971 8 _ 1

1. A R 8 N I: 2. M o b i 1: 3. K 0 D EC 0 USe UM- - ~~US SUM USSUM -------

Pagerungon 372.6 Madura: 369,5 K E 6: 111,0Torang 81.8 Madura: 115,9Kungan : 444.0 -

Subto 47S,4 In phasing the investment KODECO is estimated toSubtotal 898.4 spend about 111 million by 1992.

*0

w0 .

Nb NZ

- - I- - - - - - - - - - - - - -

- _ _ -_- -_- -_- - _- - _- - _- - _- - _- - _- - _- - _- I _- - _

.~~ .4 3 a._~~~~~~~ -_ -_ - - - --__ -_ -_ - - - -___

|~~I N * >I

; f0 a a | 0 £ N .4 2

S 8 | {; 'I I * | ; e N X u 3 I- ~ ~ ~ ~ ~ ~ ~ ~ ~ ------

I -~ ~ ~ ~ ~ -- ---- ----

^ I _____I _ I _____#_ .. _

g i -q-g- i a i I ! t - - -i ! - I - - - - -

2 - t- i- S i- - - - ---- v- - -l - - - - - - -;~~~~~~~~~~~~~~32I 2 - - - - - - - - - - - -

I-----i!-!-'

5__; j 2I 0S .4 1 ?IS!_Eo e "

! s° s !§!~S!t! U *3 e .,,=

! - "- 9- ! :N i * I I I"-X@

£T'£~ ~~~ xuu

* … S -S-S-S~~~~-S8

NATURAL GAS DEVELOPMENT AND PLUNNINC STUDY

S O U T A A N D C E N T R A L S U MA T R A

GAS DEVELOPMENT AND COST PROF1LE

|I 19m9211 |1994 |1996 | 1996 11997 11996 1999 2000 | 2001 12002 1200 12004

(1) Tti 0uja Coguiptio(1) t(wteo Duri) | | 24 |286 288 f2 2h| 27 294 |298 00 |0 309

t2) Ex1 0iSst7ly) I 1719 1791 179 1167 1 164 1 134 112 1 150 1140 1140 1120

(8) Additional supply required (MMSCFD)l I I 106 I 107 1 109 I 119 1 121 I 128 I 142 I 148 1 I 165 I 189Source of Supply (WSCPD)

PERTAMINA UINT EP -2Su g PERTANINA UN1T EP - 227 27 27 27 27 27 27 25 26 26Lombak so so 80 so 80 80 80 80 80 80Ber ngin 20 20 20 20 20 20 20 20 20 20Kuan - - - - - - - 15 1s 15Prebummnnng 80 a0 80 so 80 30 80 80 30 30Huei - 2 40 40 40 40 40 40 40 40 40 40Subtotal I 1197 197 1971 19711971197119712101 21012101 1A s rn S.S ~4Letang 201201201 201201201201201 201201Subnn 30 so 301 30o 30 0 380 30 s08 30Subtotal s o so oS0 01 s0o so so5so so 0o1 01 I

Dowelopment Cost - USB MllionDEVELOPMENT COST ____________Lembak 122 _ -1 8|B oring) 41 4 ~

Prkeno 47 - i - -Mmcl - 8~~~~~~~~0 15s 7 - - 7----------

Pertamin Total 12101 30 165 7 - 171 16 S - 7 i I IAssamra S.SI I~~~~~~~~~______-_______________________ Ii::::t::::Suboa 1s6o 1 I-I I I I9 1I I dI I I ISurb Total so 9Grand ToUt^l 296 3080I 1S 7 - 28 15 1 7- I X

Note: 1/. GAS deliverebllity estimated for 10 years supply based on 1.1.90 reserves2/ Supply from Pertaoina unit EP 1 A Asam-ra S. be a'ilable from ongoing PrtaminaPs development of 4-undeveloped reserv-c from L.mbak, Muvi Ber r in, Prabumenang and an d Asamera's Letang nd Subang fields.3/. B nuang deelop mnt eo t has not en includd in view of Sangetti fi-ld heavy developed hich will make upteh required supply.

INOESIA

NATURAL GAS DEWEL0PNENT AND PLAINING STUDY

NORtH SUMATRA

Consuption and SLiply Projections

(ALL figures in WISCFD).......,................................. ............................................................................................................................................

__

1994 1995 1 1996 1997 M998 1999 2000 I 2001 2002 2003 2004IA N A N A N A N A N A N A N A N A N A N A N

I 1~~~~~------------------------------------------ ----------------------------------------------------------------- -------------|Fert & Paper |134 154 134 154 134 154 134 154 134 154 134 154 134 154 134 154 134 154 169 154 t69 194|

IPLN hedan 88 101f 88 101 I u 101 I a 1011 88 1011 88 101 I88 101 8 8 101 1 88 101 1 88 101 1 88 101 1I I I I I I I I I I I I IIPetrochemicats 12 14 1 12 14 1 13 15 1 13 15 1 13 15 1 13 15 1 14 16 1 14 16 1 14 16 1 15 171 1 6 18 1II I IOD IIII IGerw l Industry 1 25 29 1 28 32 1 33 38 1 39 45 1 43 49 1 49 56 1 63 72 1 68 78 73 84 1 79 91 1 86 991

IReS/Comi. | 2 3 1 2 3 1 2 3 | 2 3 1 2 3 1 3 4 | 3 4 | 3 4 | 3 4 | 3 4 1 3 4 1

|Refineries of LPG 1 17 19 1 17 19 1 18 21 1 19 22 1 19 22 1 20 23 1 20 23 1 21 24 1 22 25 1 22 25 1 23 26 11----------------------1I------------------------------------------ ----- -------------------------------------------------------------------------ITOTAL 1 278 320 1 281 323 | 288 332 1 295 340 1 299 344 | 307 353 1 322 370 1 328 377 | 334 384 1 376 392 1 385 42 11----------------------1I--------------------------------------------------------------- --------------------------- -------------------------------|Total Excluding I I I I I I I I I I II Fert and Paper I 14 166 1 147 169 1 154 178 1 161 186 1 165 190 | 173 199 188 216 1 194 223 200 230 1 207 238 216 248 11----------------------1I---------------------------------------------------- ---------------------------------------------------------------------lExisting Supply | 35 40 1 35 40 | 35 40 1 35 40 35 40 35 40 35 40 35 40 35 40 35 40 35 401

|Add. being arrangew 50 60 1 50 60 1 50 60 1 50 60 1 50 60 1 50 60 1 50 60 1 50 60 1 50 60 1 50 60 1 50 60 |I I I I I I I I I I I I IIAdditionsl Possible j 60 77 1 60 77 1 60 77 1 60 77 1 60 771 | 67 60 77. 60 77 60 77 60 77 60 77 .................................................................................................................................................

^,,

Note: 1. A a Averege WSCFD; N = Naximum MSCFD2. Supplies for Fert 9 Paper have been secured till 2005 also currently average 40 MUSCFD and mx. 50 MSCFD is being supplied.3. Additional supply of 70 PWsefd (Caximum) can be made available from 4 Pertamina fields (Kuala Simpang, Serang Jaya, P. Tubuhan

P. Tubuhan Tmr).

-91-

INDONESIA Anex 3.16

NATURAL GAS DEVELOPMENT PLANNING STUDY

NORTH SUMATRA

GAS DEVELOPMENT AND COST PROFILE

: 1992 :1993 : 1994 : 1995 : 1996 : 1997 : 1998 : 1999: 2000 : 2001 : 2002 : 2003 : 2004 :

: : : (CNNSCFD:

t1). Total Consuwption : : : :Without Fertaltzer : : : 166: 169: 178: 186: 190: 199: 216: 223: 230: 238: 248:and Paper Mill : : : : : : : : : : :

..... ............ ....... - -- ...... ..... ...... ...... .... . ----- .... ..... ------- :----------------------------

(2). Existng SWply : : : 40: 40: 40: 40: 40: 40: 40: 40: 40: 40: 40:(3). AdditionaL supply : : : 60: 60: 60: 60: 60: 60: 60: 60: 60: 60: 60:

being arrenged : : : : : : : : : : : :

Add. supply required : : : 66: 69: 78: 86: 90: 99 :116 :123 :130: 138: 148:

SouceoSg4pLy : : : : : : : :FD : : : :Source Of Supply : : : : : : (MNSCFD) : : : ::

Proven undeveloped : : : : : : : : : : : :

Reserves to be developed: : : : : : : : : : :to met the dkmnd : : : ::

PERTANINA EPI : : : : : : : : : : :KUALA SINPANG : : :30.60 :30.60 :30.60 :30.60 :30.60 :30.60 :30.60 :30.60 :30.60 :30.60 :30.60 :SERANG JAYA : : :25.00 :25.00 :25.00 :25.00 :25.00 :25.00 :25.00 :25.00 :25.00 :25.00 :25.00

P. TUBUHAN BARAT : : : 7.20 : 7.20 : 7.20 : 7.20 : 7.20 : 7.20 : 7.20 : 7.20 : 7.20 : 7.20 : 7.20 :

P. TUBUHAN TINUR : : :14.80 :14.80 :14.80 :14.80 :14.80 :14.80 :14.80 :14.80 :14.80 :14.80 :14.80......................... ................. :....... ...... :..... .. :...... ........... :...... ............ :...... ............ :...... .......----...--....... ...

SUB TOTAL INSCFD : : :77.60 :77.60 :77.60 :77.60 :77.60 :77.60 :77.60 :77.60 :77.60 :77.60 :77.60 :. . . . . . . . . . ... .. ....... ...... ...... . . .. ..... :. .... .. .. .... .- .. .. ...... : ......---- :---:---:---:---:--

Development Cost in USS Millfon

KUALA SIMPANG :17.90: : : : : 7.00: : : : :

SERANG JAYA :31.50: : : : 6.00: : : : : : :P. TUBUHAN BARAT :17.37: : : 1.50: : : : : : :P. TUUAN TIMUR :14.39: : : : 3.00:

TOTAL DEVELOPMENT COST :81.16: : : : :17.50: : : : : :

Notes:(1). Gas deliverability for 10 years supply based on 1.1.90 reserves.

(2). Supply sources is from Pertmina EP I fitelds CKual Shpang, Serang Jaya, P.Tubuhan Bret, P. Tubuhan Timir)(3). "obIl mill also continue supply of gas for Fertilizer nd Paper mill which It has comitted.(4). Further exploration has to carried out to meet the demand beyond year 1998.(5). In case the Natuna ga Is available for LNG Plant at Arun. Mobil onshore fields

can be put on strem to meet the domestic demwnd.

-93-

Annex 3.17

INDONESIA

NATURAL GAS DEVELOPMENT PLANNING STUDY

E A S T K A L I MA N T A N

Consumption and Supply Projections

(All figures in NMSCFD). ....... .................. .............. ............................... .. .... . .. . ..... ...... ... .... ............

1 1994 1995 I 19961 1997 1 1998 1999 20001 20011 20021 20031 2004 1

IA MIA MIA NIA MIA NIA MIA MIA MIA NIA MIAMI.......................-------- -------- -------- -------- -------- -------- -------- -------- -------- -------- I .. .. II ..---- I-

Fertilizer, Sontangll89 217 1224 258 1228 262 1266 306 1305 351 1305 351 1305 351 1305 351 1305 351 1305 351 1305 351 |

PLN, Samarinda |15 17 15 17 15 17 124 28 28 32 28 32 29 33 29 33 129 33 29 33 129 33|

I I I I I I I I I I I IPLN, Balikpapan 16 7 6 7 6 7 1 6 7 6 7 6 7 6 7 6 7 6 7 6 7 1 6 7

I I I I I I I I I I I IPetrochem,Bontang 59 68 59 68 | 59 68 |59 68 | 59 68 59 68 | 62 71 | 65 75 | 68 78 72 83 75 86

Buw'yu IIIIIIIIIII

Refinery,Balkpapan| 33 38 133 38 133 38 133 38 |33 38 133 38 133 38 133 38 |33 38 133 38133 38 1

iotal 1302 347 1337 388 1341 392 1388 47 1431 496 1431 496 1435 500 1438 504 1441 507 14"5 512 1448 515 1

urrent Supply 1 1176 185 1176 185 1176 185 1176 185 1176 185 1176 185 1176 185 1176 185 1176 185 1176 185 I

upply Required 1 1161 203 1165 207 1212 262 1255 311 1255 311 1259 315 1262 319 1265 322 1269 327 1272 330 |

IIIIII I.................. .. ..................................... . .......... ......... ..................... ......................

Puglas 69/Katdesup/dd/291091 A. Av. day NMSCFD M. a Max. day NMSCFD Date 2/28/92

-95-

INDONESIA Annox 3810

NArU9AL GAS OEYELOPMENT PUANNINO STUDY-_---------------_-.--------_----_----

EAST KA L I M ANT A N

AS OEV&.OPlIET AND COST PROFILE___________________________________________.___--______________________-______________________ __-________-_________________________________

11992 1 1993 8 1994 1 1998 1 1996 1 1997 1 19981 19991 2000 1 2001 1 2002 1 2003 1 2004 1-------------------------------------------------------------- __-------__-_---__-------------------------------------------_----_-_--------

I I I I (l'C) I I I I I I

(1)Total Ga Consumption 14CFO 8 I I I 88 8921 447 1 4901 496 1 6001 5041 07 1 512 1 8151

(2)Ex;iting Supply FHSCFD I I I I 18 8 1dS8 181 16 I 1 188 1 6 1851 Les 18 168 1 65 1__________________________________________--__--_______________________________ ____________________________________________________________

(S)Additional supply required (M.ecfd) I I I 1 208 I 207 1 262 I 811 1 811 1 818 | 819 I 822 1 327 I 88O I

SOURCE OF SUPLY I l I I I (SCF) l _______________________ ~I I I I I I I I I I I I I I

Provon Undevoloped recoverable l l l lRose.rv to be developed to meot the dondl l l I l l l l l I | l

------------------------------------------------------------ _------------__--__--------------------------------------------------------_--

HUFFCO (VICO) l | l l l I l l l I l l

Nila l 139 l 1S9 1O9 139 139 139 139 139 139 1 19Sdak l l 196 96 96 96 961 96l 961 96 961 IS.bornh 3 I 3 11l 811 l 11 81 81 811 811 8 11 81utiur I l I I l l l I I l I 48 481 481

------------------------------------------------------------------------ __---__-----------------------------------------------------------

subtotal SPCDI I I 1 266 1 2_6 1 266 1 26 11 2 1266 1 266 8 314 1 814 1 814 1_________________________________________________________________________________________________--________________________________________

TOTAL INDONESIE l | l I l I l l I I I l l I

Tambora l l I I l l l1 12 l1 2 122 1 122 1 122IHandil 5 I I I I e I W 18 591 9 1 s91 8

_________________________________________________________________________________________--____________________________________________--__

Subtotal MSCF I I I I I I 1 122 1 1S1 161 1 181I 16811 1681I 181 1----------------------------------------------------------------------- __----__-----------------------------------_-----------------------

TOTAL 1scmI I I 1 266 1 266 1 266 1 388 1 471 4471 447 1 495 1 4'6 1 4981

DEVELOPNT COST IN US$ ILLION

Nilan I 1-8 801 401 l l I l I 9.0 I l I IBaduk I 721 241 24 | I I I 1 6.8 I l I IS.mbersh I 801 101 101 1 1 1 I 12.21 2 I IMutiars I I I I 1 31 1 10 0 I 10.0 0 I 1

------------------------- _---------_-------------------------------------__--__-----------------------------------------------------------

Subtotal of Huffco 1 190 1 84 1 74 1 10 I I I l 31 1 25.3 S 12.2 1 I I l------------------------------------------------------------------------- __--__-----------------------------------------------------------

Total Indonesia I l l l I I I l I l I | I

Tembors l I I l 1 124 1 41 1 42 I I l l l lHandil n 771 26 1 261 1 I I 1 1

--------- __------------------------------------------------_--------------__--___------------------_--------------------------------------

Sub Total I I I 1 77 1 149 1 67 1 42 1 1 1 1 1 1 1

IW1 TOTAL 1 1901 84 1 74 1 87 1 149 1 67 1 42 1 81 1 25.3 S 12.2 1 1 I

Notes:1/. Oa, deliverability eotimated for 10 year, supply based on 1.1.90 (proven undovoloped, potential, and potential

undeveloped roxrvn-).2/. Addition supply is from Huffco (VICO) Onshore fiold- Niles. Bdake, Seeberah. Nutiora and Total Indonesian

Offshoro Tambora xnd Handil potential undeveloped reoerve.S/. Supply of m* is based on S0O of Aeociatod and 70S of Non Associtod Romin;ng

Undoveloped Roeevoc.

Natural G+as DeveloDnment Study

Natural Gas Conswptlon Scenario (Bse Case) /a............................................

CBCF)... .. ^...................................................................................................

1990 1991 1992 1993 1994 1995 1996 1997 1996 1999 2000 2001 2002 2003 2004

West Jaa

Fertlllsers 20.0 20.0 20.0 32.8 34.4 35.2 .35.2 35.2 35.2 35.2 35.2 35.2 35.2 35.2 35.2Po&er Genewation 2.9 18.2 25.4 25.4 34.7 61.6 59.6 103.3 91.9 91.1 90.7 90.7 90.7 90.7 90.7IroniSteel 45.8 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0Cement 5.6 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.6 5.8 5.9 6.0 6.0 6.1PetrochemIcals .16.4 16.4 16.7 17.0 17.4 17.7 18.1 18.6 19.2 19.7 20.3 20.9Rest of Incistry /b 11.5 /c 17.6 23.7 34.1 42.5 50.7 58.6 70.2 95.0 106.7 119.8 131.2 143.3 156.2 170.3Rel/Comm 4.0 4.0 4.4 4.7 4.9 5.3 5.6 5.9 6.3 6.7 7.1 7.5 7.9 8.4Reflnerleswi+PG 14.S 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.C 14.9 15.3 15.8 16.3

Subtotal (1) 85.7 130.1 143.3 183.3 202.9 239.4 246.1 301.9 316.0 327.6 341.3 354.1 367.7 302.2 397.8

Central Jav............

Power Generatfon 46.3 71.9 71.9 71.9 71.9 71.9 71.9 71.9%0Rest of Industry /b 4.8 11.7 18.1 20.3 21.8 23.9 26.0 28.4

Subtotal (2) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 51.1 83.6 90.0 92.2 93.8 95.8 97.9 100.3

East Java

Fertltfsers 13.9 16.4 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9Power GeneratIon 37.2 60.3 64.8 82.4 84.2 84.2 84.2 84.2 84.2 84.2 84.2 U8.2 84.2Rest of Industry lb 16.4 19.4 22.9 26.4 33.8 38.0 42.5 48.0 52.6 57.4 62.9 69.1Res/Coms 0.4 0.4 0.4 0.4 0.5 0.5 0.5 0.6 0.6 0.6 0.7 0.7

Subtotal (3) 0.0 0.0 37.2 90.9 101.0 123.6 128.9 136.3 140.6 145.1 150.7 155.2 160.1 165.6 171.9

North Suastra.............

Fertflfsers 44.5 46.1 46.1 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 61.8 61.8Power GeneratIon 7.5 22.0 16.1 26.6 32.2 32.2 32.2 32.2 32.2 32.2 32.2 32.2 32.2 32.2 32.2PetrochemIcals 4.3 4.4 4.5 4.6 4.7 4.8 4.9 5.0 5.2 5.3 5.5 5.7 >Rest of IndUstry /b 5.8 Ic 6.3 7.6 8.4 9.1 10.2 11.9 14.4 15.8 17.9 22.9 24.9 26.5 28.8 31.3 OQRes/Coms 0.5 0.5 0.6 0.6 0.7 0.7 0.8 0.8 0.9 0.9 1.0 1.0 1.1 1.2 & XRe f nerle .LPG 6.2 6.2 6.2 6.2 6.4 6.6 6.8 7.0 7.2 7.4 7.6 7.9 8.1 8.3 0

Subtotal (4) 57.7 81.1 76.5 95.1 101.6 103.0 105.0 107.8 109.6 112.0 117.5 119.9 121.9 137.4 140.5 eh -'

1990 1991 1M2 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2001

Smuth & Centrst Smtra,......................

Fertitisers 49.8 49.8 58.1 69.3 70.1 70.1 70.1 70.1 70.1 70.1 70.1 70.1 70.1 70.1 70.1Power GeneratIon 0.3 5.0 5.0 5.0 5.0 5.0 4.5 3.6 1.9 1.9 1.9 1.9 1.9 1.9 1.9Petrochmicals 2.2 2.3 2.3 2.4 2.4 2.5 2.5 2.6 2.7 2.7 2.8 2.9Rest of Industry /b 2.3 3.1 3.7 4.2 4.9 5.9 6.5 7.3 9.4 10.2 10.8 11.7 12.8Refineries+LPG 28.8 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.3 9.6 9.9 10.2 10.5Other - Ourl 88.5 112.4 126.3 140.1 134.9 137.0 137.0 139.1 137.0 126.4 116.8 109.5 106.2

Subtotsl (5) 78.9 63.8 162.9 201.0 216.4 230.8 225.8 228.0 226.9 229.9 230.2 220.8 212.2 206.2 204.4

Kalluentan..........

fertilisers 62.0 62.8 66.0 68.0 69.0 69.0 81.8 83.4 97.0 111.4 111.4 111.4 111.4 111.4 111.4Power Generation 1.5 3.8 6.8 6.8 8.5 8.5 8.5 10.9 12.5 12.5 12.7 12.7 12.7 12.7Petrochemicals 9.5 9.5 21.5 21.5 21.5 21.5 21.5 21.5 21.5 21.5 22.6 23.7 24.9 26.2 27.5Refineries+LPG 12.2 12.2 12.2 12.2 12.2 12.2 12.2 12.2 12.2 12.4 12.7 12.9 13.2 13.4

Subtotal (6) 71.5 86.0 103.5 108.5 109.5 111.2 124.0 125.6 141.7 157.6 158.9 160.5 162.0 163.5 165.0

Rest of Indbnesia /d.................

Power Generation 6.0 8.2 13.9 16.1 15.1 15.1 15.1 15.1 15.1 15.1 16.1 16.1Rest of Industry /b 2.9 3.2 3.5 3.9 4.3 4.7 5.2 5.6 6.1 6.7 7.3 8.0

Subtotal (7) 8.9 11.4 17.4 20.0 19.4 19.8 20.3 20.7 21.2 21.8 23.4 24.1

Total Indnesa

Fertilisers 176.2 118.6 190.1 232.9 238.9 241.1 254.0 255.6 269.2 283.6 283.6 283.6 283.6 296.4 296.4Power Generation 11.5 46.7 87.5 130.1 151.7 203.6 205.0 m.1 308.0 308.8 308.4 308.6 308.6 309.6 309.6Iron&Steel 45.8 S0.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0 50.0Cement 5.6 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.9 6.0 6.0 6.1Petrocheicals 9.5 9.5 21.5 4.5 44.6 45.1 45.5 46.0 46.5 47.0 48.8 50.7 52.7 54.8 57.0Rest of Industry /b 22.4 Ic 23.9 33.6 64.9 77.9 91.6 105.9 133.3 171.8 197.6 226.0 246.9 268.6 292.9 319.9Res/Colm 4.5 4.5 5.3 5.7 6.0 6.4 6.8 7.2 7.7 8.2 .8.7: 9.2 9.7 10.3RefineriefUPC 32.7 41.9 41.9 41.9 41.9 42.1 42.3 42.5 42.7 42.9 43.6 4.8 46.0 47.3 48.6other 88.5 112.4 126.3 140.1 134.9 137.0 137.0 139.1 137.0 126.4 116.8 109.5 106.2

tD TOTAL 303.7 361.0 523.5 687.8 742.8 825.4 849.8 970.1 1038.3 1082.5 1111.5 1125.6 1141.5 1176.2 1204.0 N

,,., ,,,, ,,,,,,, , ......................................................-......... o

/i Actual figure for 1990; Base Case projections for 1991-2004/lb This category includes Industrial fuel conmuewsPc Includes residentlal and coeiercIal customers/d Includes Batem, Sulawesi nd Irian Jaya.

ItDOUESIA

Natural Ga Consuqption Scenarfo (sigh Cas) /a

(KF)................... ..............................................

_...........................................

1990 1991 1992 1993 1991 1993 1996 1997 1996 1999 2000 2001 2002 2003 2004mest Java

Fertiltsers 20.0 20.0 20.0 32.8 34.4 3S.2 35.2 35.2 35.2 35.2 35.2 35.2 35.2 35.2 35.2Power Genration 2.9 18.2 25.4 25.4 34.7 61.6 59.6 103.3 91.9 91.1 124.0 154.3 186.7 205.5 224.2IrontSteel 45.8 52.6 55.1 53.3 53.3 107.3 107.3 10T.3 107.3 107.3 107.3 107.3 107.3 107.3 107.3Cement 5.6 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.9 6.0 6.1 6.2Petrochedcals 16.4 16.4 16.7 17.0 17.4 17.7 18.1 18.6 19.2 19.7 20.3 20.9Rest of Intry /b 11.5 /c 17.7 23.9 34.7 43.7 52.9 62.2 90.3 103.3 117.5 133.8 149.2 165.6 183.8 204.0Residentflt/Comercal 4.0 4.0 4.4 4.7 5.1 5.5 5.9 6.4 6.9 7.4 7.9 8.4 9.0 9.5Ref inerleetP6 plants 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.9 15.3 15.8 16.3Sahtotal (1) 85.7 132.8 148.7 187.1 207.5 299.1 307.0 379.6 382.1 396.4 446.5 493.8 544.3 582.9 623.6Central Java............ ...........

Poer Genration 4.3 71.9 71.9 71.9 87.7 96.1 105.3 114.4Rest of Indstry lb 4.8 11.7 18.7 21.3 23.7 26.3 29.2 32.4Sh*totel (2) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 51.1 83.6 90.6 93.2 111.4 122.4 134.5 146.8

Eat Java

Fertltiser 13.9 16.4 17.9 17.9 17.9 17.9 17.9 7.9 17.9 17.9 17.9 17.9Power Geneation 37.2 60.3 64.8 82.4 84.2 84.2 84.2 84.2 102.1 104.6 118.1 132.8 132.8IrontSteel 14.3 15.5 16.7 17.9 19.1 20.3 21.5 22.7 24.1 25.5 27.0Rest of Iniintry /b 16.6 20.0 23.9 28.0 36.2 41.3 46.7 53.5 59.7 66.5 74.2 82.3Residsntfal/Comercala 0.4 0.4 0.4 0.5 0.5 0.5 0.6 0.6 0.7 0.7 0.7 0.8SLhtotal (3) 0.0 0.0 37.2 91.1 115.9 140.2 147.2 156.6 163.0 169.7 195.6 205.5 227.3 251.2 260.9

worth Sumatra......... ........... __

fertlu 44.S 46.1 46.1 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 49.0 61.1 61.8Powr enration 7.5 22.0 16.1 26.6 32.2 32.2 32.2 32.2 32.2 32.2 32.2 32.2 32.2 32.2 32.2 csttrocdmical 4.3 4.4 4.5 4.6 4.7 4.8 4.9 5.0 5.2 5.3 5.S 5.7lest of Iintry lb 5.8 /c 5.8 5.8 7.7 9.4 10.7 12.6 15.5 17.2 19.7 25.6 28.5 31.8 35.3 39.2sldmntfat/Cwrcela 0.5 0.5 0.6 0.6 0.7 0.8 0.8 0.9 0.9 1.0 1.1 1.2 1.2 1.3 iRe finwrise*PC plants 6.2 6.2 6.2 6.2 6.4 6.6 6.8 7.0 7.2 7.4 7.6 7.9 8.1 8.3S.*total (4) 57.7 80.S 74.7 94.4 101.9 103.5 105.7 100.9 111.0 113.9 120.2 123.6 127.4 144.2 148.5

1990 1991 12m 1993 1994 1995 1996 1997 1990 1999 2000 2001 2002 2003 2001...............................................................................................................................................................

South & Central Sumtra.......................

Fertilisers 49.8 49.8 58.1 69.3 70.1 70.1 70.1 70.1 70.1 70.1 70.1 70.1 70.1 70.1 70.1Pomur Cwneration 0.3 5.0 5.0 5.0 5.0 5.0 4.5 3.6 1.9 1.9 1.9 1.9 1.9 1.9 1.9Pmtrodamicals 2.2 2.3 2.3 2.4 2.4 2.5 2.5 2.6 2.7 2.7 2.8 2.9Rest of Industry /b 1.1 2.3 3.1 3.8 4.4 5.2 6.3 7.0 8.0 10.5 11.6 12.9 14.3 15.9RefinrlestLPK ptlnts 28.8 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.3 9.6 9.9 10.2 10.5Other - Duri 88.S 112.4 126.3 140.1 134.9 137.0 137.0 139.1 137.0 126.4 116.8 109.5 106.2

Subtotat (5) 78.9 64.9 163.0 201.1 216.5 230.9 226.0 228.4 227.5 230.7 231.3 222.3 214.3 208.8 ?S5.0

Kalimantan..........

Fertitisers 62.e 62.8 66.0 68.0 69.0 69.0 81.8 83.4 97.0 111.4 126.7 129.1 142.7 144.3 144.3Power Generation 1.5 3.8 6.8 6.8 8.5 8.5 8.5 10.9 12.5 12. 12.7 12.7 12.7 12.7Petroche dcals 9.5 9.5 31.0 31.0 31.0 31.0 31.0 31.0 31.0 31.0 32.6 34.2 35.9 37.7 39.6RefinerieswLPG plants 12.2 12.2 12.2 12.2 12.2 12.2 12.2 12.2 12.2 12.5 12.9 13.3 13.7 14.1

Schtotal t6) 71.5 86.0 112.9 118.0 119.0 120.7 13!.5 135.1 151.1 167.1 184.3 188.9 204.6 208.4 210.7

Rest of Indbne ia /d................. o

Power Generation 6.0 8.2 18.4 18.4 20.6 19.6 19.6 19.6 19.6 19.6 30.5 30.5Petrocheicats 9.1 9.1 9.1 9.1 9.1 9.1 9.4 9.7 9.9 10.2Rest of Iasbtry hb 2.9 3.3 3.8 4.4 4.9 5.3 5.9 6.5 7.2 8.0 8.9 9.9

Sabtotal (7) 0.0 0.0 0.0 8.9 11.5 31.3 31.9 34.6 34.0 34.6 35.2 36.2 37.3 49.4 50.6

Total Indonesia...............

Fertilisers 176.2 178.6 190.1 232.9 238.9 241.1 254.0 255.6 269.2 283.6 298.8 301.2 314.9 329.3 329.3Power Generation 11.5 46.7 87.5 130.1 151.8 208.1 207.3 298.6 312.6 313.4 364.1 412.9 467.2 520.8 548.7IroniSteel 45.8 52.6 55.1 53.3 67.6 122.8 124.0 125.2 126.4 127.6 128.8 130.0 131.4 132.8 134.4Cement 5.6 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.9 6.0 6.1 6.2PetrochemIcats 9.5 9.5 31.0 53.9 54.1 S4.5 55.0 55.5 56.0 56.5 58.8 61.2 63.7 66.4 69.1Rest of Industry lb 22.4 /c 24.5 32.0 65.0 80.3 95.7 112.4 157.9 185.9 216.5 251.2 279.9 311.1 345.7 383.7Residentil/Com0erlat 4.5 4.5 5.3 5.8 6.2 6.7 T.2 7.8 8.4 9.0 9.6 10.3 10.9 11.6Ref Ineries+U'G plants 32.7 41.9 41.9 41.9 41.9 42.1 42.3 42.5 42.7 42.9 43.7 45.0 46.4 47.8 49.2Other 88.5 112.4 126.3 140.1 134.9 137.0 137.0 139.1 137.0 126.4 116.8 109.5 106.2 'd

lOTAL 303.? 364.2 536.5 700.7 m7.4 916.5 942.3 1085.3 1143.3 1193.8 1297.4 1372.3 14T.8 1569.3 1656.2 0o S............................................-.--------------------------------------..-................................................................. ''''''''''''''''...

/a Actual figures for 1990; Nigh Ca projections for 1991-2004/b This category Inctuds indatrial fuet con_rs M H/c Includes residential d ce_mrctl c&stmrs/d Include 3atm, Sul_al en trim Jaa.

-101-

Annex 4.2

INDONESIA

Natural Gas Development Planning Study

Netbagk Value of Gas in Alternative Uses

The netback value analysls has been undertaken to assess the relativemerits of natural gas utilization in industrial end-uses. Where gas is usedprimarily as feedstock, e.g., fertilizer and petrochemical plants, theeconomic value of gas has been evaluated against the import option. In caseof fuel applications in general industry, the netback value estimates theeconomic competitiveness of natural gas vis-a-vis alternative fuels (mostlyfuel oil and diesel oil). Finally, natural gas generally competes with coalin cement, and possibly steel, production. Table 1 below provides the priceassumptions for the p-cducts and fuels considered in the economic analysis.Table 2 provides a detailed breakdown of the netback value of gas in GeneralIndustry.

Table 1: Economic Prices of Products and Fuels

Prices

Urea US$ 135.0/tonSteel (billets) USS 234.0/tonMethanol US$ 174.0/ton

Fuel Oil a/ Rp 232/litreDiesel Oil (automotive) a/ Rp 368/litreDiesel Oil (industrial) a/ Rp 345/litreCoal Rp 33.5-41/ton

a/ Based on crude oil price of $17.60/bbl.

Table 2: Netback Value of Gas In General Industry($/MMSTU)

Industry New Plants New Plants Conversion

(Fuel Oil) (Diesel) to Gas

Glass 4.16 6.33 2.98Metal 6.32 8.91 3.07Paper 4.03 6.00 3.50Iron & Steel /a 3.99 5.61 3.20Textiles 4.98 7.42 3.38

L& excluding direct-reduction process at Krakatau Steel.Source: Mission Estimates

* INDONESIAGas Development Planning Study

SUPPLY-CONSUMPTION BALANCE (1994-2004)

West Java Ent & Central Java

$/MMBTU S8MMThI

LX 4_ 3n 2-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-

ol 0~~~~~~~~~~~~~~~~~~~

so ISO 0 Io vob 2s o Si0 bo . soF er yer yfuC pw year

Note:1. The relatively low AICs for East Java are the result of (1) sunk costs for Pagerungan fields,

and (ii) AIC calculations at the field only (BD, Terang, Madura).2. The supply curve for each region is a function of the economic costs (AIC + depletion premium) m

and gas reserve volumes for each marginal. field in the region. The consumption scenarios have Xxbeen estimated on the basis of (a) netback value of gas and (b) projected volume of consumption o >in each end-use category.

SUPPLY-CONSUMPTION BALANCE (1994-2004)

North Sumatra 4 S3

SI/MMTU

:s C - I voI wI> ! I

~~oo*I ~~~o

4-

3-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-

0-~~ ~~ ~~ ~~~~~~~~~~~~~

So loo~~~~~~~~~~~~~

50 ~~~~~~~~~~~~~~4-SCF per year

1 I~~~~~~~~~~

0*

-105- Annex 5.1

INDONESIA Page 1 of 5

Natural Gas Development Planning Study

ENERGY PRICING 1/

Sectoral Context and Objectives

1. The energy sector of Indonesia accounts for about 40% of exports and 38%of the 001's domestic revenues. Although these shares are at about half oftheir peak levels in 1981, a result of the decline in oil prices and thegrowth of the non-oil economy, the energy sector is expected to continue toplay an important role as a supplier of financial resourcer and competitivelypriced inputs to production. On this basis, the GOI's objectives for thesector are:

(a) the economic (efficiency) objective: to meet the country's energyrequirements in the least cost way.

(b) the resource mobilization (financial and fiscal) objective: tomaximize the country's foreign exchange earnings and budgetaryrevenues, and enable producers to recover their costs and obtainsufficient resources to finance their growth and development.

(c) the social (equality and fairriss) objective: to promote theregionally balanced development of the country and enable most ofthe people to afford the basic services provided by energy(lighting, cooking, transportation).

(d) the environmental objective: to promote the production andutilization of energy resources in a manner that will conserve theenvironment.

2. Central to the pursuit of these objectives is the rationalization of thestructure of domestic energy prices. In a deregulated, decentralized marketeconomy, such as Indonesia is striving to become, producers and consumers needto be given the correct price signals if they are to make economically optimalinvestment and consumption decisions.

Principles of Enerav Pricing

3. The rationalization of energy prices will require the adoption ofefficiency pricing as the basic guideline for decision making. The adoptionof efficiency pricing is consistent with the economic objective, and alsoprovides as sound basis for the achievement of resource mobilization, socialand environmental objectives. The adoption of this framework simply requiresthat prices be set above a floor defined by the economic cost of the fuel.Any deviation of prices from economic costs needs to preserve their relativeranking.

J;/ This annex is based on "Indonesia: Energy Pricing Review," World BankReport No. 8684-IND, October 1990.

-106- Annex 5.1

Page 2 of 5

4. The use of economic cost as a floor ensures that consumers will bewareof, and producers will recover, the resource cost of fuel supply. Thereflection by prices of the r 've cost of alternative fuels provides anincentive to choose the leas . option. Buyers will purchase the fuel onlyto the extent that the econo.'.. enefit derived from its consumption (asreflected in its netback value, i.e. the buyers' willingness to pay) willexceed the price. If a fuel's economic cost is higher than the willingness topay of a given consumer, then that particular stream of consumption is noteconomically viable and no transaction will take place. Hence, the netbackvalue acts as a ceiling on the range within which a price can be set.

5. The analysis and determination of prices based on the above frameworkneeds to be carried out in two stages. In the first, prices are set equal toeconomic costs. This set of prices, which will be denoted as efficiencyprices, will be strictly consistent with the objective of economic efficiency.Efficiency prices provide a useful starting point or rcference standard as,conceptually, they represent the prices that will guide producers andconsumers towards the levels of output and consumption that will yield themost benefit tQ the economy. The second stage consists of adjustingefficiency prices to accommodate other objectives to the extent that it isfeasible, given the range between efficiency prices and netback values.

Issues and Opportunities

6. Having postulated efficiency prices as the reference standard, we nowhave a basis for the discussion of the implications of the current structureof energy prices.

Petroleum Product Prices

7. The domestic petroleum prices are compared with the efficiency prices inTable 1. There are important subsidies on the prices of major fuels, such askerosene and diesel.

-107-Annex 5.1Page 3 of 5

Table 1: PETROLEUM PRICES

Petroleum product Official price la Efficiency price /b(Rp/liter) (Rp/liter)

Aviation gas 400 345Aviation turbo 400 379Gasoline 550 368Kerosene 220 368Automotive diesel 300 368Industrial diesel 285 345Fuel oil 220 232

L& Official price as of August 1991.

Lb Based on a crude oil price of $17.60/bbl, adjusted for refinerymargins, transport and distribution costs. Road user charges forgasolines and automotive diesel have not been included.

source: MIGAS and Mission estimates.

8. The pricing of energy on the basis of economic costs will provide theappropriate signals for the promotion of energy efficiency as well assubstitution of petroleum products for more economical alternatives, such asgas, coal, LPG and electricity. That improvements in energy efficiency willlessen pollution is self-evident, but it is fortuitous that virtually everymajor economically desirable substitution trend will by itself lead to reducedpollution.

9. Another important implication of the adoption of efficiency pricesis that they will guide the transition of the economy from its heavy relianceon petroleum and other depletable resources to consumption structure that willbe more sustainable in the long term. Basically, as the lower cost depositsare depleted (both locally and globally) the fossil energy resources (oil,gas, coal) will become more costly to produce and their prices should rise.The upward trend in price will gradually concentrate the market on users withthe highent netback value, who would be the only ones willing to pay thehigher prices. In parallel, the economic viability of nonfossil and renewablealternatives (such as geothermal, hydro, nuclear, recycled agricultural,industrial and urban wastes, and other new energy options) will improve andtheir contribution to the energy balance will increase, and the availabilityof energy to meet the requirements of a growing economy should not bejeopardized.

-108-Annex 5.1Page 4 of 5

A Plan of Action for the Future

10. In the absence of a general framework of pricing guidelines andmechanisms, there has been a strong incentive for various groups to lobby ontheir own behalf and influence the decisions in their own best interests.Unless the economic merits of the options can be evaluated in an independentand comprehensive manner, it is likely that the efficiency objective, which isthe most important for economic development, will continue to receiveinadequate consideration. To remedy this situation, it is recommended thatthe GOI develop and implement a comprehensive energy pricing strategy, whichincludes the adoption of a set of clear and simple guidelines for theadministration of energy prices and the correction of a few major pricingdistortions on the basis of the above guidelines.

A Recommended Set of Pricing Guidelines

11. On the basis of the discussion on the objectives and principles of energypricing, the recommended approach is the adoption of the efficiency objectiveas the general framework for the evaluation of prices and pricing proposals,through the use of a two-stage approach. The first stage consists of thedetermination of a set of efficiency prices that strictly matches economiccosts, including depletion allowances, risk premiums, environmental abatementcosts and user costs. Efficiency prices constitute the recommended startingpoint as, conceptually, they represent the prices that will guide producersand consumers towards the output and consumption levels that will yield thegreatest benefit to the economy. Thus, the adoption of efficiency prices asthe principal guideline constitutes an essential condition for the formulationof a rational pricing strategy.

12. The second stage consists of the adjustment of efficiency prices toaccommodate financial, fiscal, social and environmental objectives within afloor defined by the efficiency prices and a practical ceiling provided by thenetback values. As emerged from the discussion, the adoption of efficiencyprices is largely congruent with the achievement of financial objectives, themobilization of fiscal resources to support programs focussed on alleviationof poverty, the improvement of infrastructure and other social concerns, andthe reduction of pollution. The guideline to adopt efficiency prices as thefloor for price adjustments is based on the need to ensure the sustainabilityof supply through the recovery of the full costs, as well as the inefficiencyof the use of price subsidies to pursue policy objectives.

The Correction of Existino Distortions

13. The current structure of domestic energy prices is the result ofpast decisions that responded to the requirements of the moment be they thefinancial needs of the state enterprise in the sector, the desire to promotethe development of certain energy producing and energy using industries, aconcern for the affordability of energy, pressures from the internationalpetroleum market, budgetary needs, and other considerations. In the absenceof an integrated approach to energy pricing, the domestic prices of severalimportant energy products have diverged significantly from the underlyingcosts of supply. TULs provides incentives for excessive use and distortions

-109-Annex 5.1Page 5 of 5

in relation to the lost cost pattern of energy productlon and consumptLon.The correction of theme distortions, on the basis of the guidelLnes discussedabove, is necessary to support the Government's strategy of opening up theeconomy and moving towards a system of guidance by Lncentives rather thanadmlnistrative Lntervention.

-111-Annex 5.2Page 1 of 7

INDONESIA

Natural Gas Development Planning Study

Regulation

Regulation of the gas industry exists to ensure safe delivery ofgas for a fair return to the supplier and a fair price to thecustomer. It is found throughout the world as a direct ordelegated function of government. Regulation for safety has madea positive contribution to the success of the Indonesian Oil andGas Industry.

The Present Regulatory Body

In both oil and gas and geothermal activities Health Safety andEnvironmental supervision and control are the responsibility of theDirectorate of Oil and Gas Engineering within MIGAS. There iscomprehensive legislation giving authority to the Directorate'sActivities (see Chart A)- The line of delegation is included asChart B. A regulatory body is in place, the exercise of its roleof protector adviser and regulator is now historical and appears tohave created confidence between the regulator and the regulated.

The small domestic gas market is no exception to this but it isonly natural that most of MIGAS' attention has been on Oil and LNGoperations. As the domestic market expands so will MIGAS'workload.

The priorities include critical areas such as high pressure systems(1OBAR and above in transmission) emergency reaction, leakagesurveys, compressors, control stations and distribution systems.These require constant attention. Other less sensitive activitieswill reauire self-regulation by operators which will neverthelessfor monitored by MIGAS, as most gas operations have some element ofrisk.

Items for further development are :

- Emergencies- Trained and Qualified Staff- Standards for Material and ...

- Standards for Construction- Codes of Practice- Gas Quality and ...- Gas Pressures- Inspection and Liaison

To these the following should be added:

- Pipeline Capacity and Availability- Price Transparency- Annual Reporting

-112-

Annex 5.2Page 2 of 7

EMERGENCIES

There should be one known published point of contact in thevicinity of every gas installation. The controller of that pointmust train, prepare, plan and be solely responsible for emergenciessuch as gas leakages, fires etc. The emergency plan must specifythe role of other emergency services stipulating who should act,how, when and where they should act in accordance with specificresponse times. Emergency trials should be rehearsed and reactionslogged. Reports on these trials should be automatically submittedto MIGAS for approval and construction advice. MIGAS willobviously require reports on actual emergencies so it is as will toestablish such a format in advance. MIGAS will further need toensure that in the event of any threatened or current emergency theresponsive teams will have the right of access to any premises atpotential risk. In other words they will have as much legal rightto prevent accidents as to deal with them after the event.

Trained and Oualified Staff

The requirement already exists that all staff engaged in keyengineering and construction work shall be fully trained andqualified. Where particularly critical work is concerned MIGASchecks these qualifications against job descriptions. Thisdiscipline should also by self-regulated by operators in lesssensitive areas. Constructors should keep records of personellfilling jobs requiring skilled engineering staff. These recordsshould be regularly kept on a mandatory basis and be available toMIGAS for inspection.

Standards for Material - and Construction

Accepted International and Indonesian Standards must applythroughout. MIGAS should catalogue publish and make available toall operators and constructors a list of recognised Internationaland Indonesian Standards on a regular basis. They should beacceptable to the Indonesian Petroleum Association who will be (asat present) part of the consultative process in their production.MIGAS either directly or through an authorised inspection agencywill check in advance all critical works to ensure that acceptablestandards are observed.

Suppliers and constructors in all areas of the industry shouldsatisfy themselves that standards are maintained and should keeprecords available for inspection.

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Page 3 of 7

Codes of Practice

These in-house regulations governing procedures ensure safe andefficient operation. They should be kept up-to-date by regularreview. Normally they would not be part of any ongoingsurveillance by MIGAS. However, MIGAS should satisfy itself thatsound codes of practice exist before consenting to (licensing) anycritical work. Operators and constructors should ensure that theirstaff are fully trained in their use and application. Records ofsuch training should be kept.

Gas oualitv

MIGAS should require each operator to meet a quality for gas whichit has regulated. The gas should meet standards of calorificvalue, an" be free from impurities. Companies should keep logs ofquality and provide them for inspection on a regular basis. MIGASshould be notified of any non-compliance and action taken torectify it. A reasonable period should be allowed for ofcorrection, but MIGAS should have the right to shut downoperations.

Gas Pressure

Minimum and maximum acceptable pressures should be stipulatedthroughout the system from field to burner tip. Instructions mustbe given to staff to notify any variance at points of risk andpenalties should be automatically imposed by MIGAS for failure todo so. Pressures should be recorded at key points at all times.

Inspection

The enhanced requirements of the domestic industry will requiresome increase in the number of MIGAS inspectors employed, and willlead to an increase in the scope of the work they will audit andapprove (See Chart C). Overall, they will :

- Ensure qualified staff are employed in critical areas.- Ensure that specified standards are applied.- Ensure that critical work is performed to approved standards.- Examine and approve/reject any variations.- Examine correct and approve emergency training, services

procedures and incidents.- Suspend any work in the event of accident or emergency until

the cause is identified and corrected.- Check that organisations institute and maintain sound Codes of

Practice - and train their staff to follow them.

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Annex 5.2Page 4 of 7

Check Gas Quality and Gas Pressure. Require any delinquentsupplier to notify faults, or shut the system down until thosefaults are corrected.

Pipeline Capacity and Availability

An expanding domestic market will require regulation to ensure thatmajor work meets both the present and future needs of the country.A specific area is the construction of high pressure (10 Bar +)transmission lines. Their capacity should be assessed not only onpresent merit but future potential. MIGAS should have authority torequire that any major line should be built with spare capacity.

As trade will be confined to one operator, the gas transmission and market-ing entity, the principle of open and free access to several suppliers (CommonCarriage) will have to be established. There will be two areas forpotential competition. The first will be among the PSCs, thesecond will be from alternative users. It makes sense for MIGAS tosatisfy itself on both scores . The fact that a high pressure lineis built primarily to service one supplier should not preclude itfrom serving another; while the demands of alternative users (e.g.PGN) can equally be in the national interest.

MIGAS will find that as the system grows there will be an increasedawareness of performance guarantees and force majeure clauses whichmay conflict with take or pay conditions. The need to arbitrate ondisputes affecting carriage will arise. Quite apart from physicalconstraints arising from new sources of supply there will besimilar constraints on usage.

MIGAS will assist the whole industry if it initiates standardprocedures for arbitration. These procedures must prevail and mustnot be circumvented by any lobbying. All findings of mucharbitration should therefore be made public.

Price Transparency

Another area for regulation is price7 In most countries priceregulation is the prime role of regulators. The Federal EnergyRegulatory Commission of the US the Office of Gas Supply (Ofgas) ofthe U.K. have both impacted on market pricing. Elsewhere concernabout security of supply, its strategic value and its role innational economics has placed price decision and regulation eitherdirectly in the hands of governments or surrcgate committees actingon behalf of all interested parties.

Fair pricing is covered elsewhere in this report. While pricingpolicies will be the subject of inter-ministerial decision MIGASshould continue to publish prices and to explain them openly to the

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Annex 5.2Page 5 of 7

gas industry and its customers - as at present. This transparencymeans that operators as well as their customer will know what willbe paid for gas from well head to burner tip.

To enable MIGAS to continue with this function (and expand it wherenecessary) each company involved should provide audited informationon a regular basis. Where MIGAS is dissatisfied with any financialinformation it should have powers to investigate and regulatecorrection.

A provision for open arbitration (cf above) should also beinitiated.

Annual Reporting

MIGAS already reports on its role as the guardian of safe andenvironmentally sound practices in the oil and gas industry. Asthe domestic market grows so will public interest in it. It istherefore worth making gas regulation a separate subject andpublishing an annual report on regulatory activity for domestic gassupply.

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annex S.2Page 6 of 7

Chart A

INONESIA

NA?.TURAL GAS DEVE OMN? PLANNING STUDY

The Laws and Regulations Governing the Safety, Health and Environmentof Oil and Gas Operations

- Law No. 44 PRP/1960, regarding the mining of mineral oil and gas.- Law No. 8/1971, regarding the state oil and gas mining onterprise.- Law No. 4/1982, regarding the provisions for the management of the

environment.- Mining ordinance No. 38/1930.- Mining Police Regulation No. 341/1930 regarding safety of mining.- Petroleum Storage Ordinance No. 199/1927 regarding: the safetypetroleum storage.

- Government Regulation No. 17/1974 regarding: the supervision of offshoreoil and gas exploration and exploitation activites.

- Government Regulation No. 11/1979 regarding: the safety of refining andprocessing.

in addition to these are also other regulations and procedures issued by theNinister of Mines, E.G.:

- 04/P/M/PERTANB/1973 regardings the pollution prevention in offshore operations.- 02/P/M/PERTAMS/1975 regarding: the safety of pipeline.- O5/P/N/P3RTAMB/1977 regarding: the certification of offshore platform.- 01/P/M/PBRTAMB/1980 regardings of inspection of equipment.

Source: MICAS

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Annex 5.2Page 7 of 7

CHART B

DELEGATION OF AUTHORITY

MINISTRY OFMINES AND ENERGY

I

DIRECTORATE GENERAL OFOIL AND GAS

-'1

SAFETY ASPECTS IN OIL AND GAS INDUSTRIES

DIRECTORATE OF OIL AND GASENGINEERING

HEAD OF MINING INSPECTION

Nt/

INSPECTORTECHNICAL HEAD

URCE: MIGAS

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