INDONESIA FOCUSES UPSTREAM TOWARD SWEETER TERMS, GAS

With the prospect looming this decade of losing its status as a net oil exporter, Indonesia is sweetening the pot for foreign petroleum investors and refocusing on natural gas.

The decline in the discovery rate of oil reserves and low world oil prices have caused Indonesian hydrocarbon exploration in 1992 93 to fall short of expectations after the boom in drilling during 1989 91.

The trough Indonesia hit in reserves additions will combine with a projected 6%/year growth rate in domestic oil consumption to set the stage for the country possibly becoming a net oil importer by 2000.

Under its budget projections, Indonesia's crude oil and condensate production is pegged at 1.53 million b/d for fiscal 1994 95 beginning Apr. 1. Oil exports are projected at slightly more than half that level. Both figures are expected to be about flat with levels estimated for fiscal 1993 94 ending Mar. 31.

That compares with crude and condensate production of 1.59 million b/d and oil exports of about 905,000 b/d in fiscal 1990 91, production of 1.56 million b/d and exports of 876,000 b/d in fiscal 1991 92, and production of 1.5 million b/d and exports of 777,000 b/d in fiscal 1992 93.

Indonesia's government earlier this month disclosed a long awaited incentive package designed to attract new oil investors to high risk and remote areas of the archipelago (OGJ, Jan. 10, Newsletter).

The incentives, said Faisal Abda'oe, president of state owned oil and gas company Pertamina, are intended to delay the onset of net oil imports to 2010. Indonesia, a member of the Organization of Petroleum Exporting Countries, is Asia's biggest oil exporter.

But assuming a healthy rate of discoveries as well as successful implementation of the government's energy diversification policy away from oil, oil production could be expected to be maintained at 1 million b/d the next 25 years, said Said Djabbar, general manager of Pertamina's foreign contractors ventures and development unit.

Current government estimates of combined proved and probable oil and condensate reserves in Indonesia hover at 9.5 11 billion bbl, down from a peak of 25.7 billion bbl.

Indonesian oil and gas reserves generally are easily accessible in Java, Sumatra, and East Kalimantan in western Indonesia, where most of the country's oil and gas producing areas and basins lie.

The eastern part of the archipelago, especially offshore, is virtually unexplored because of high risks in deepwater areas and remoteness of sparsely populated areas from infrastructure.

INCENTIVE PACKAGE

The government's fourth incentive package since August 1988 centers on two main points: an improved equity split between Pertamina and the operating contractor to 75 25 from 80 20, effective immediately, and a higher price paid by Pertamina for the first tranche petroleum (FTP) it buys from contractors. FTP is a volume of production Pertamina takes before recovery of operating costs.

For production from a frontier site, after 5 ears from start up, the price Indonesia pays for FTP volumes will rise to 25% from 15% of official Indonesian crude prices. At the same time, frontier volumes subjected to FTP will be cut to 15% from 20% of production. In conventional areas, the equity split will remain 85 15 in favor of Pertamina.

In the case of natural gas, production sharing remains unchanged at the 55 45 equity split for frontier areas and in waters deeper than 1,500 m, terms introduced in the third incentive package in August 1992.

The latest package is the fourth issued since Aug. 31, 1988, under what Pertamina describes as the third generation production sharing contract (PSC).

The first package included deregulation measures to be taken in procurement procedures.

The second package, introduced Feb. 22, 1989, was the first to deal with incentive equity splits for marginal fields, oil produced from pre-Tertiary pay, and tertiary enhanced oil recovery projects as well as investment credit incentives for deepwater contract areas.

It also dealt with data assessment and acquisition, extension of exploration periods, gas prices, and valuation of domestic market obligation (DMO) oil. DMO oil is a percentage of crude and condensate that contractors are required to sell at an agreed price to Pertamina.

The fourth package came as no surprise because it had been announced almost 3 months prior.

Indonesia has some of the toughest contract conditions in Asia. It is believed Pertamina had been pushing for even sweeter terms than those disclosed because it recognizes the difficulty of drawing foreign investment that is flowing increasingly to more competitive areas such as China, Viet Nam, and republics of the former U.S.S.R.

Last year total outlays for exploration and production under Indonesian PSCs totaled $4.5 billion. Pertamina hopes to boost the figure to $5 billion this year.

PRODUCTION SHARING CONTRACTS

Indonesia's oil and gas industry is the third oldest in the world after the U.S. and Russia. It was the first country to introduce PSCS.

There have been three peak investment periods in Indonesia coinciding with increasing oil prices: 1968, 1979-81, and 1989. Capital investment dropped in the late 1970s despite rising oil prices because of changes in U.S. tax policies. Investment also declined in the mid 1980s and recently because of low oil prices.

During the earlier boom times, U.S. multinationals dominated Indonesia's upstream operations. They still do. But overall, new PSCs dropped from a peak of 24 in 1991 to six in 1992 and eight in 1993.

The discovery rate, however, remains relatively high. Of 100 exploratory wells drilled in 1991, 25 discoveries were made. The 92 wildcats drilled in 1992 yielded 30 discoveries. In 1993, only 60 wildcats were drilled, but the discovery rate remained strong at 20 discoveries.

Although declining in recent years, the number of active PSCs in Indonesia remains high. As of August 1993, they totaled 43 in western Indonesia of which 16 are in Sumatra, 14 in Kalimantan, seven in the Natuna Sea, and six in the Java area. Another eight contracts in western Indonesia are represented by joint operation agreements (JOAs) in which Pertamina has a 50% participating interest, including six in Sumatra, one in Java, and one in Kalimantan. In addition, there are eight enhanced oil recovery contracts (EORCs), including seven in Sumatra and one in Kalimantan.

In eastern Indonesia there are 20 active PSCs of which four are in Sulawesi, eight in Irian Jaya, five in the Maluku Timor area, and three in the Nusa Tanggara area west of Timor. One JOA is in Irian Jaya.

In addition to PSCs, JOAs, and EORCs, Indonesia offers other contractual arrangements, including contracts of work (COWs), technical evaluation contracts, joint operating bodies, and loan agreements.

Stanvac, a joint venture of Esso Indonesia Inc. and Mobil Oil Indonesia Inc.; and Caltex, the joint venture of Chevron Corp. and Texaco Inc.; have long maintained small blocks in Sumatra as COWs. All COWs were to have expired in 1993, according to the U.S. Embassy at Jakarta.

Of 94 blocks covered by all types of contracts, 72 are in western Indonesia, broken out as 39 exploration, 26 production, and seven EOR, and 22 in eastern Indonesia, broken out as 19 exploration and three production.

RESERVES, PRODUCTION

Most of Indonesia's remaining proved and probable crude and condensate reserves are in Sumatra, with a total of 6.47 billion bbl. Of the rest, 1.336 billion bbl are in Kalimantan, 1.329 billion bbl are in the Java area, and minor reserves are in the South China Sea, Sulawesi, Irian Jaya, and Ceram.

An earlier peak estimate of proved natural gas reserves, developed and undeveloped, of 117 tcf has fallen to 94 tcf. Of that total, 45 tcf are in the Natuna area, 25.4 tcf are in East Kalimantan, and 18 tcf are in North Sumatra. Smaller reserves are scattered among Java, Sulawesi, and Irian Jaya.

Oil and gas reserves discovered during 1972 93 totaled 1.514 million bbl of oil equivalent (BOE). That's a steep drop from the 1.933 billion BOE discovered between 1966, when production sharing contracts were introduced, and 1972. While oil reserves discovered remained about the same in a comparison of the two periods, the decline stems from a big drop in gas reserves discovered.

Oil reserves discovered by contractor companies during 1985 92 totaled 723 million bbl of oil with Maxus Energy Co. accounting for 38%, followed by Conoco Inc. 21%, Marathon Oil Co. 18%, Canada Northwest Energy Ltd. 8%, Trend International Ltd. 7%, and Hudbay and Mobil Oil Corp. 4% each. Of 16.4 tcf of gas reserves discovered during the same period, Total accounted for 39%, ARCO 37%, Asamera Oil Indonesia Ltd. 12%, Mobil 6%, and Maxus and Royal Dutch/Shell Group 3% each.

Although a large number of companies are engaged in upstream operations in Indonesia, seven account for the biggest share of the country's hydrocarbon production.

Main oil producers are Caltex with 630,000 b/d of liquids plus small volumes of gas, Mobil with oil production of about 100,000 b/d and more than 350,000 BOE/day of gas, Virginia Indonesia Co. (VICO) more than 200,000 BOE/day of production that's mainly gas, Maxus about 180,000 b/d of oil and small volumes of gas, Total about 180,000 BOE/day split about 50 50 oil and gas, and ARCO with 160,000 BOE/day split two thirds gas and one third oil.

Of the 60 Tertiary sedimentary basins identified in Indonesia, 35 have been explored and 22 proven productive. The remaining 25, described as frontier areas, lie mainly in eastern Indonesia.

It is believed that pre Tertiary plays in underexplored eastern Indonesia could prove rewarding because some oil and gas discoveries have been made in the region. The risks are high, as are the costs. Mobil recently drilled a $20 million wildcat in the region.

That is why some operators consider the recent new government incentives to be disappointing.

Pertamina's management, for one, is bullish about potential of these frontier areas. The state company believes they could contain a further recoverable 216 tcf of natural gas and 48.4 billion bbl of oil, which it breaks down as 15.4 billion bbl of oil and 44.9 tcf gas onshore and 33 billion bbl of oil and 171.9 tcf gas offshore.

For the time being, Indonesia's oil production will continue to be dominated by mature western fields and EOR.

"It is still on these old blocks that the best discoveries are made," noted one foreign operating contractor. About 50% of the PSCs signed in 1993 by Pertamina involved small Indonesian companies intent on working over small, older finds.

A GAS FUTURE

The roughly 10 year reserve life for Indonesia's oil production compares with 40 years for gas production.

The government's energy policy, which focuses on curtailing the rate of increase in domestic consumption of oil products from the current 6%/year to 3%/year, hinges on energy diversification and oil conservation. A noteworthy move in this direction came when subsidies on oil products were scrapped in the 1992 93 budget with a resulting price hike of 20%.

Energy diversification relies not only on increased development of natural gas but also on increased use of coal, hydropower, and geothermal potential to back out oil for industrial development and power generation.

Liquefied natural gas also is taking up the slack of declining oil exports. Indonesia is the world's 14th largest gas producer but the leading exporter of LNG with a capacity of 24.4 million metric tons/year.

Under PSCs and COWs with Pertamina, gas is produced at a rate of 7.07 bcfd. Of that, 4.10 bcfd is exported as LNG and 100 MMcfd equivalent as LPG. The balance is used in fertilizer production, electrical power generation, as city gas, in refineries, and other industrial uses. Only 480 MMcfd still is flared, and 1.44 bcfd is reinjected for gas lift or used as fuel in fields.

Pertamina figures show annual gas use the past 10 years has jumped from 797 bcf to 516 bcf for field operations, from 429 bcf to 1.416 tcf for LNG and LPG production, from 50 bcf to 178 bcf for fertilizer production, and from 38 bcf to 64 bcf for steel mills and city gas. Gas burned to produce electricity has grown from zero to 10 bcf/year. At the same time, there has been a 70% reduction of gas flared.

The two main gas producing areas are in northern Sumatra, where the 12 tcf Arun gas field operated by Mobil accounts for 47% of Indonesia's gas production, and East Kalimantan, where fields with combined reserves of 23.4 tcf operated by Total, ARCO, and VICO account for 32.4% of the country's gas output.

Those two producing areas feed the two LNG plants built to serve export contracts.

The Arun plant consists of six LNG trains with combined capacity of 12.3 million metric tons/year. The Bontang plant, the world's biggest, has just brought on stream its sixth LNG train, boosting total capacity to 15.4 million tons/year. A seventh train, scheduled for 1997 at a cost of $750 million, will add 2.6 million tons/year to capacity. It wig be fed by Total's Peciko gas field off East Kalimantan (OGJ, Jan. 24, p. 12).

By far the leading buyer of Indonesia's LNG is Japan, which lifts 18.44 million tons/year. More recent buyers are South Korea with 4.3 million tons/year and Taiwan with 1.7 million tons/year.

Pertamina is negotiating 10 year extensions to Japan's two long term contracts.

Pertamina plans a third LNG complex on Natuna Island intended to serve uncommitted gas supply contracts and based on development of Esso Indonesia Inc's giant gas field on the Alpha block in the Natuna Sea. That project has been stalled by disputes between Pertamina and Esso over price and other terms of the PSC (OGJ, Dec. 13, 1993, Newsletter).

The Alpha block holds proved and probable reserves estimated at as much as 46.5 tcf. Natuna gas development and LNG infrastructure would require an ultimate outlay of $17 billion. About 70% of the huge upstream investment would go to stripping and reinjecting into an aquifer the 71% C02 content of the field's gas reservoir.

Observers in Indonesia do not see the Natuna gas field project taking off in the foreseeable future. At the same time, development of Total's Peciko field has reduced the urgency of the Natuna LNG project.

DOMESTIC GAS USE

Indonesia also has a number of other gas producing areas in and around the islands of Java and Sumatra, where most of the population is concentrated.

They consist of small fields of which the largest, in South Sumatra, account for 12.2% of Indonesia's total gas production. Production from these fields is intended to meet Indonesia's current and future domestic gas needs either for city gas, power generation, or industry.

The government is pushing for rapid development of domestic gas use that is currently at a low level.

To bolster gas use, a number of pipeline projects are under way or being planned generally for the long term. The purpose is to set up a pipeline grid linking the fields to end users as well as linking the islands to one another.

Among the main pipeline projects, two gas lines are planned to feed power plants that are near completion. In East Java, the 28 in., 430 km Trams Java Pipeline will transport 300 MMcfd gas from Pagerungan to Gresik to feed a 1.5 million kw power plant. In East Java, an 8 26 in., 94.4 km pipeline will transport gas from ARCO's Offshore Northwest Java fields to Nuara Karang and Tanjung Prick, near Jakarta.

The Asia Development Bank and state owned gas utility PGN have commissioned a study by from France's Beicip on the feasibility of a pipeline linking Asamera's North Corridor block Palembang gas field in Sumatra with steamflood operations in giant Duri oil field farther north on the island. Under consideration is a possible spur from Duri to the Indonesian island of Batan near Singapore. Batan is being developed as a potential rival to Singapore as a world class industrial complex, including petrochemical plants.

PGN also is mulling a pipeline from South Sumatra's Prabumulih field, also in the Palembang area, to Cilegon in Northwest Java to feed an industrial and power generation complex planned there.

More ambitious and for the longer term are projects to lay pipelines to link a number of gas fields in North Sumatra, South Sumatra, East and West Java, Central Java, East Kalimantan, and South Sulawesi to industrial and power plant projects. Interconnection of these pipelines ,would form the Trans Indonesia Gas Pipeline System, joining all these far flung islands within a vast integrated gas network.