Report No. 10293-IND

IndonesiaSector ReportNatural Gas Development Planning StudyJuly 20, 1992Industry 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 dayMCM = thousand standard cubic metersMMCM = million standard cubic metersBCF = billion standard cubic feetTCF = 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 hourMW = megawattKm = kilometerHP = horse power

CONVERSIONS

1 BOE = 5,800 standard cubic feet natural gas1 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 CorporationPPTMGB 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 ........................................... 9Current 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 . . 17Future 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 . . . . . . . . . . * * . . * 35Regulatlon . . . . . . . . . . . . . . . . . . . . . . . . . . 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 attr