Hanan Nugroho

Hanan Nugroho Perencanaan Pembangunan No. IX/03 Juni 2004

INCREASING THE SHARE OF NATURAL GAS IN NATIONAL

INDUSTRY AND ENERGY CONSUMPTION: INFRASTRUCTURE DEVELOPMENT PLAN?

Hanan Nugroho 1

Abstract – While petroleum supplies in Indonesia are shrinking, the country is still the largest exporter for LNG in the world and contains of considerable natural gas reserves. It is natural then using more natural gas domestically as an attractive option in pursuing a national policy on energy diversification and industry development. However, the decision is constrained not only by current energy prices, but also the lack of available natural gas infrastructure. This need for additional infrastructure has hindered the economic benefits of energy diversity for quite sometime. This paper stresses the importance of

natural gas infrastructure development. The groundwork for which requires developing a formal and legitimate national master plan for natural gas transmission and distribution networks. With the need for energy diversification and expanding the role of natural gas in particular, this paper looks at Java Island as the center of energy demand and national industry, describes alternatives for natural gas transportation and natural gas transportation development projects finance. In addition, it discusses the structure of Indonesia’s natural gas industry, regulation and deregulation that has been initiated for oil and gas industries, and potential problems faced by the government in developing the natural gas industry. This paper also sheds light on a set of agendas to be implemented within the coming five years. They include the development of database that is required for the industry to forecast the domestic market capacity and demand for natural gas usage, management of gas fields data, formulation of master plan for national natural gas transmission and distribution networks, financing schemes for natural gas transmission and distribution projects, and redefinition the national energy and natural gas prices policy.

1 Hanan Nugroho, Sr. Energy Economist, Directorate of Energy, Telecommunication, and Informatics, National Development Planning Agency (BAPPENAS). E-mail: [email protected]. An earlier version of this paper has been presented at Roundtable discussion between Bappenas and Fortune Magazine, March 2004 in Jakarta.

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1 Introduction

The policy of energy diversification to reduce the dependency on oil has been a main theme of Indonesia General Policy on Energy (KUBE) since the post oil boom in the 1980s. This initiative has resulted in the form of decreased share of oil fuels and the increased share of natural gas and coal in the domestic energy mix. The decrease of oil share, however, is not significant. On the contrary, in the nominal terms, oil consumption (as final products and crude to be refined domestically) is still increasing. Figure 1 shows the development of Indonesia’s final energy consumption, in barrel oil equivalent (BOE).

Figure 1. Indonesia Final Energy Consumption (Million BOE)

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1995 1996 1997 1998 1999 2000 2001 2002

Year

Mill

ion

BO

E Oil FuelsNatural GasCoalElectricityLPG

Source: DG Electricity & Energy Development; http://www.djlpe.go.id

One major constraint that has prevented the implementation of energy

diversification policy is the lack of available infrastructure. Most of the energy resources (gas, coal) are situated out of Java, the most populous island as well as the center of national energy demand. The network of infrastructure primarily to transport natural gas (and coal) from their mining locations to the center of energy demand is not sufficient. This is because the development of gas (and coal) infrastructure requires high investment costs and at the same time the demand for natural gas and coal is still limited, and because the price of domestic oil fuels is low.

Compared to the other alternative energy resources available in Indonesia, natural gas has its advantage to substitute/to reduce oil’s share in the national energy mix. Why

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natural gas? Because its reserves in Indonesia are quite large, the price is low compared to that of oil, its burning capacity is very good and because natural gas is environmentally very friendly. In addition to the above energy diversification policy reason, natural gas is also important for strengthening security of energy supply and promoting energy conservation through the application of high efficient combined cycle and co-generation. In power generation, natural adds its advantage for lower investment costs and faster construction period compared to that of hydro and other thermal plants. The regulation and institution set-up for natural gas development in Indonesia are so far quite ready compared to that of the country’s other alternative energy.

The proven reserves of Indonesia’s natural gas from its producing fields are continuously increasing, from 35 trillion cubic feet (TCF) in 1977 to about 90 TCF in 2002. The gas reserves to production ratio (R/P), although smaller than that coal, are far larger than that of oil. Table 1 shows Indonesia energy reserves and their reserves to production ratios.

Table 1. Indonesia energy reserves, 2002

Energy Unit Proven reserves

Reserves/ production

Crude oil Million barrel 5.0 11.1 Natural gas Trillion cubic feet 2.62 37.1 Coal Million ton 5,370 52.0

Source: http://www.bp.com 2 Energy demand: Java, the national center of consumption

Energy consumption in Indonesia is continuously increasing, by approximately 5-7 percent growth in average annually. This figure is higher than that of the world’s average, Asia-Pacific region (except for China recently) and that of its ASEAN neighbors. The growth for electricity consumption, in particular, has always been the highest. However, the magnitude of Indonesia’s energy consumption per capita is far smaller than that of industrial countries and that of ASEAN average. Using energy intensity figure, a ratio between energy consumption and the country GDP, shows that the use of energy in Indonesia has not been used as productively as it us used in ASEAN neighbors.

Oil fuels (known in Indonesia as BBM: kerosene, gasoline and diesel fuels) have been the largest types for Indonesia’s energy consumption. Data on national total final energy consumption (TFC) in 2000 show the share of oil fuels in the country energy mix was 75%, natural gas was 8%, coal was 4%, and electricity was 11%. During the same year, the share of each energy resources in the country’s total primary energy supply (TPES) for crude oil is 58%, natural gas is 27%, coal is 10%, hydro is 4%, and geothermal is 1%. Transportation sector was the largest energy consumer amounting to 38% of the national commercial energy demand, followed by industry with 36% and households with 26%. Figure 2 presents Indonesia’s energy consumption by source and sector in 2001. It is shown clearly in the figure that transportation is the largest consumer, while oil fuels is the largest energy consumed.

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Figure 2 Energy consumption by sector and source, 2001.

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Oil Fuels Natural Gas Coal L P G Electricity

Energy Source

Con

sum

ptio

n (M

illio

n B

OE)

TRANSPORT

HOUSEHOLDS

INDUSTRY

Source: DG Electricity & Energy Development; http://www.djlpe.go.id

Java is known to be the most populated island where large industries reside and

where transportation and other major economic activities take place. It is also the center for energy consumption activities in the country. In addition, it is the island where energy conversion centers, such as oil refineries (Balongan, Cilacap, etc.) and power generations (gas, coal, oil fuels) are located, scattered around in the northern part of the island. About 80% of national energy consumption is for Java. In contrast, almost all of the country’s productions for primary energy are located out of Java. It is not surprising that the increasing demand for energy in the island has to be fulfilled or supplied form outer islands/abroad. The figure of energy supply from abroad for the island is growing. The national oil fuels consumption in 2001 was approximately 57 million kilo litter or equivalent with 5,650 MMSCFD (million standard cubic feet daily). About 62 % of this consumption was for Java. During the same year, PGN (State-owned Gas Company) transported natural gas by about 570 MMSCFD, which is very small compared to the country’s oil fuels consumption. Substitution to oil fuels to prevent its growth can be a main target for the efforts to increase natural gas consumption, especially for Java.

Natural gas has been primarily used in Java as fuel for electricity, industry, as feedstock for industry, as a result of gas field development in, especially, the western and eastern parts of the island. The development of gas pipeline was pioneered by Pertamina (the state oil and gas company) in 1970s for transporting natural gas from Cilamaya field

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(near Cirebon) to industrial complexes, such as fertilizer (Cikampek), cement (Cibinong), steel (Cilegon) and city gas (Bogor), and all regions in West Java. Networks of city gas distribution have been built only for a limited coverage. Liquefied petroleum gas (LPG) has been produced and transported from gas area in Java (i.e., Mundu of West Java) and imported from domestic LPG plants, from Kalimantan in particular. The use of gas for transportation (to substitute car’s gasoline) has been promoted in capital city of Jakarta, but this effort has not been successful due the lack of infrastructure.

In years to come, demand for natural gas in Java will increase due to capacity expansion in gas-based electricity generations and the replacement of oil fuels based generations. Electricity generations are anticipated to be the largest customers (anchor) for natural gas industry. PLN (the state electricity company)’s combined cycles Muara Karang, PLN Tanjung Priuk, PLN Gresik and other power generations will consume about 55 % of natural gas flown to Java. One may ask what will be the role of natural gas in JAMALI (Jawa-Madura-Bali) electricity generation system. The increasing demand for gas will also come from city gas, industry and feedstock fertilizer and petrochemical in particular.

It is not surprising that the increasing demand for gas in Java can not be fulfilled from the existing gas supply system. Therefore it is necessary for the island to have more supply from outside Java, such as natural gas from Sumatra, Kalimantan, and Papua. When this deems to be possible, infrastructure necessary to transport and distribute the flow of natural gas needs to be expanded. 3 Transporting natural gas: several options

The development of gas transmission networks requires at least two primary factors. First is of course a significant amount of natural gas production (supply) and second is the main customer or anchor, who will eventually consume gas (demand). It is observed from other country experiences that once the transmission and distribution for gas are built, the demand for gas goes through the roof. Due to its natural characteristics, gas must be transported with great handling and safety that requires higher investment costs than that for transporting crude oil, oil products and coal. Natural gas can be transported through various alternatives. Transporting natural gas by pipelines is the most common method, especially if the distance from the location of gas production to its destination less than 1,000 km. A range of pipeline diameter varies, depending on the volume of the gas to be transported (16-42 inches is the common diameter). For long distance/crossing the ocean and huge gas volume, transporting natural gas using LNG (liquefied natural gas) tankers is more appropriate, although it is part of LNG transportation chain.

For a lesser gas volume, transportation using CNG (compressed natural gas) tubes and ships is a suitable method, especially for sending natural gas to the remote river/sea-shore areas. With this method, gas is compressed to the CNG tubes then transported as CNG on ships or CNG on wheels. Transporting natural gas using “cable” (after converting it to electricity in the mine mouth) is another transportation option, but it is rarely used. LPG (liquefied petroleum gas), in many cases is a by-product of LNG production, can be transported in simpler way. In addition, gas can be converted to liquid phase (GTL or gas to liquid), which is important in the development of stranded gas fields, before transporting. Figure 3 shows “the rule of thumb” for the selection of natural gas transportation methods

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taking into account the distance between the location of gas production and that of final demand, gas throughput and technology options.

Figure 3. Rule of thumb for natural gas transportation

Source: Hetland, 2002.

Indonesia has implemented three different methods to transport natural gas, including LNG tankers, LPG ships/tubes and pipelines. LNG is transported from LNG plants in Bontang (E. Kalimantan) and from Arun (Aceh) to export destinations overseas, such as Japan, South Korea, and Taiwan. Indonesia (1977) is a pioneer in using LNG tanker for transporting natural gas, and the LNG tanker traffic volume originated from Indonesia is considered to be the largest.

LPG is exported from Indonesia (mainly to Japan) and also distributed domestically, in urban areas in particular. The LPG exports come from Bontang/Arun plants, whereas domestic consumptions are supplied from domestic LPG plants and oil refineries.

The natural gas transmission pipelines that have been constructed is still very small yet, i.e., less than 2,000 km, compared to that in US with about 500,000 km. The system is not integrated and it is concentrated close to the production areas and large industries that need natural gas as their fuel and feedstock. In addition to developing natural gas pipeline networks, Indonesia has pipelined crude oil from its gathering centers to refineries and from refineries to a number of distribution centers.

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4 Natural gas transportation project development finance

Gas transportation using LNG tankers cannot be separated from the development of LNG project chain as a whole. The chain ranges preparation for gas production fields, to construction of gathering pipelines to LNG plants, gas processing at the LNG plants, transporting gas using LNG tankers, and the construction of LNG receiving terminals (LNG storage tanks, re-gasification units, and connection to transmission/distribution networks). The LNG project requires long-term commitment (20-30 years) from many parties and calls for very large investment expenditures. The cost for the Tangguh - Guang Dong LNG project, for instance, is approximately US$ 13 billion.

The financing for LNG project development in Indonesia (Bontang and Arun) has been made through a great cooperation among consortiums of gas producers, consortiums of gas consumers (the Japanese utilities/electricity generation companies), a finance syndicate representing gas producers, a finance syndicate representing consumers, a trustee company, a sales off-taker, Pertamina as the coordinator/project owner, and several engineering, procurement and construction (EPC) companies from all over the world.

Project finance for CNG transportation using CNG ships can be simpler and less expensive than that of LNG projects. Project finance for natural gas transmission development projects using pipeline, although it requires quite large investment, is also simpler than that of LNG project. PT PGN for example, in developing its transmission (and distribution) pipelines, has combined financing sources that consist of the company’s own equity, budget from the Government’s Project List (DIP), and loans from several multilateral/bilateral financing agencies (WB, ADB, EIB, JBIC) channeled by the Government’s subsidiary loan agreement (SLA) schemes. Recently, PT PGN has launched initial public offering (IPO) in the international and domestic bond markets, and has combined the funds generated through the IPO into PGN projects finance portfolio, which will be spent firstly for the South Sumatra – West Java gas transmission project.

During the early period (1970s), the development of natural gas gathering pipeline was an element of cost to be reimbursed (cost recovery) in Indonesia’s production sharing contracts (PSC) terms. Then, for several gathering pipeline projects, Pertamina took over the finance by using the company’s equity and some amount of overseas loans. An alternative to be explored soon is that the finance for such kind of gas pipeline projects can be done through BP MIGAS (Government) using the State’s budget or overseas loans.

5 The structure of Indonesian natural gas industry

Indonesia is the largest LNG exporting country in the world, shipping the LNG using LNG tankers to Japan, South Korea and Taiwan. The country also exports natural gas through pipeline networks to its neighbors, such as Singapore and Malaysia. In the domestic market, the players for Indonesia gas industry comprise three major groups: a) gas producers, b) consumers, and c) transporters. Transportation to consumer areas, for some parts, is still being carried out by the gas producers, while PT PGN, for example, as a major gas transporter (transmission), is also the dominant local distribution company (LDC).

The production of natural gas in Indonesia is relatively flat, from 8,674 MMSCFD in 1997 to 8,427 MMSCFD in 2003. Almost all of the gas productions are carried out by PSC contractors: BP, ExxonMobil, Unocal, TotalFinaElf, etc. Gas production activities are

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located in South Sumatra/Jambi, Aceh (Arun), East Kalimantan (Badak, Bontang), Sulawesi (Sengkang, Donggi) and Papua (Tangguh). TotalFinaElf is currently the largest gas producer in Indonesia with its production activities located in East Kalimantan. ExxonMobil was a dominant producer, but its production is decreasing naturally, for instance that in Aceh.

In the early stage of Indonesia’s natural gas development (1970-es), gas was directed for export, as LNG. This is making sense because the gas was found in some giant fields (Badak, Arun) and as non-associated one. On the other side, demand for gas from Japanese utilities was very high. Until 2003, Indonesia exports 58% of the national gas production. The domestic consumption for natural gas is increasing with the largest gas consumers are fertilizer and petrochemicals (8%) and electricity generations (6%). Table 2 presents the use of Indonesia’s gas for exports and domestic markets in 2003.

Table 2. The use of Indonesia’s natural gas, 2003.

Consumer MMSCFD Percentage

Domestic

• Fertilizer and petrochemical 696.5 8.3 • Refinery 63.0 0.7 • LPG/LEX Plant 77.5 0.9 • PGN 435.4 5.2 • Cement 7.9 0.1 • Electricity 500.2 5.9 • Krakatau Steel 71.5 0.8 • Other industry\ies 273.2 3.2 • Own use 968.8 11.5 • Flare 473.7 5.6

Subtotal 3,567.3 42.4 Export

• LNG 4,516.0 53.6 • LPG 15.5 0.2 • Gas (pipeline) 321.5 3.8

Subtotal 4,853.2 57.6

TOTAL 8,420.5 100.0

Source: DG Oil & Gas

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6 Indonesia gas pipeline networks

Pipeline networks for natural gas transmission have been developed on project per project basis and are not integrated. The networks can be grouped into gathering lines and sales lines. The gathering lines serve the flow of gas from gas fields/block stations to gas processing plants (LNG, LPG, purification) or booster compressions, while the gas sales lines are that from gas processing plants to gas consumers.

The development of gathering lines has been carried out in line with the finding of gas fields, which are spread out in Aceh, South Sumatra, East Kalimantan, Natuna and Java-Bali islands. The diameter for these gathering lines range between 16” and 42”, with the approximate length for each pipeline segments about 10-109 km and their capacities between 200 to 2000 million standard cubic feet daily (MMSCFD). The gathering lines were developed in Java and Aceh areas since the early 1970s.

The developed sales line are mostly located in Java Sea-Tanjung Priok/Muara Karang, Cilamaya-Cilegon, Pagerungan-Gresik,Prabumulih-Palembang, Grissik-Duri, Natuna-Singapore, Grissik-Sakernan, and Sakernan-Batam-Singapore. PGN is now developing a transmission pipeline from South Sumatra to West Java (under construction) and conduct a feasibility study (funded by US Departement of Trade) on a transmission pipeline connecting East Kalimantan, Center Java and West Java. The development of gas transmission pipelines have been carried out in Indonesia mostly by Pertamina and its production sharing contractors (for gathering line), and by Pertamina and PGN for sales lines. Table 3 shows the national natural gas transmission pipelines.

Table 3 Indonesia natural gas pipe line

No. Pipe Name Diameter

(inch) Length (km)

Capacity (MMSCFD)

Location Remark

Gathering Line 1. Offshore-L. Seumawe 30 109 1,000 Aceh LNG Plant 2. Onshore-L. Seumawe/Arun 16 - 42 30 - 34 200 - 2,000 Aceh LNG Plant/ Industry

3. Badak-Bontang 42 57 2,000 E. Kalimantan LNG Plant

4. Field-Badak-Bontang 20 - 36 10 - 70 300 - 1,500 E. Kalimantan Gas processing

5. Offshore-W. Java 16 - 26 20 - 70 200 - 600 West Java Proc. Platform 6. Grissik Fields 16 - 26 13 - 50 200 - 600 S. Sumatra To Sales Line

Sales Line

7. Offshore-T. Priok/ Muara Karang 16 - 26 10 - 55 200 - 600 N. Java Power Plant

8. Cilamaya-Cilegon 24 220 500 W. Java Industries 9. Pagerungan-Gresik 24 - 28 3 - 370 500 - 700 E. Java Power Plant/ Industry 10. Prabumulih-Palembang 20 - 28 15 - 50 300 - 500 S. Sumatra Power Plant/ Industry 11. Grissik-Duri 28 550 700 Sumatra Duri Steam Flood 12. Natuna-Singapore 16 - 28 10 - 470 200 - 700 S. China Sea Export/Power Plant 13. Grissik-Sakernan 28 135 700 C. Sumatra Transmission

14. Sakernan-Batam- Singapore 28 335 700 Riau (Sumatra) Export/Power Plant

Source: DG Oil & Gas

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7 Oil and gas industry regulation: a great transformation in motion

The Law No. 22/2001 on Oil and Gas, with its special concern on downstream market liberalization, changes many aspects of the natural gas industry. The main features of Law are the promotion of unbundling and “clear, transparent, and competitive environment” policies in oil and gas business, the establishment of two (Executing and Regulating) Bodies and the changing role of Pertamina from “a player, regulator and the Holder of Mining Right” to a Limited Liability Company (PT Persero). The two new bodies mark critical milestones of the on-going domestic oil and gas market deregulation.

Government Ordinance No. 42 Year 2002 was issued marking the establishment of Executive Body for Upstream Oil and Gas Business Activity (BP MIGAS) which takes over Pertamina’s role in managing the upstream production sharing contracts. Government Ordinance No. 67/2002 was issued marking the establishment of Regulatory Body for Oil & Gas Downstream (BPH MIGAS) to regulate and supervise the downstream sectors. The Presidential Decree No. 57/2002 was passed inaugurating the Pertamina’s new organization structure. In 2003 BP MIGAS started taking over Pertamina’s role in representing the government in the upstream business. It is important to note that Pertamina’s assignment to supply and distribute oil fuels to domestic market will be ending by November 2005.

Law also emphasizes explicitly the importance of the development of natural gas for domestic usage. The BPH MIGAS is responsible for promoting more natural gas usage to meet domestic energy demand and gas-based industry development plans. The Regulating Body also functions to determine tariff (toll fee) for natural gas transportation via pipeline networks, to set-up natural gas prices for households and other small users, and to regulate natural gas transmission and distribution business.

While the two important bodies have been established and some works are in progress, it is not clear yet how the Law will then be translated into its respected Government Ordinances. The Government Ordinance Concerning Upstream and Government Regulation Concerning Downstream, which will serve as the basic information for investors in oil and gas business and many other stakeholders, have not been released yet. A blue print for the transformation of Indonesia’s natural gas industry has not been clearly pictured out.

8 Problems faced in natural gas development

There are some problems faced in developing the natural gas industry in Indonesia, such as pricing, domestic consumption, infrastructure, and planning and coordination.

• Pricing policy

The implementation of energy pricing policies, both for energy in general and natural gas used in domestic market in particular, is so far not promoting the development of the national natural gas industry. The prices for oil fuels, which are heavily subsidized by the Government for quite a long period, have made oil fuels look cheaper than natural gas. The prices for natural gas in domestic market, which were historically decided through Government intervention with quite wide price differentials among usages, are so far not reflecting the opportunity costs of the gas

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production (especially that for fertilizer). In the long term, this may discourage investors for doing natural gas exploration and production business. Table 4 presents Indonesia natural gas prices for different usages in domestic market.

• Low domestic consumption and lack of infrastructures

Indonesia is one of the most advanced countries in the development of LNG industry for exports. However, the domestic natural gas consumption is still very low, even when it is compared to the countries where Indonesian natural gas is exported. Natural gas consumption by households represents only a small part of Indonesia natural gas usages. For a large part, this due to the lack of city gas distribution networks. Compared to the industrial countries, Indonesia’s natural gas transmission and distribution network is still very limited, and even compared to the other infrastructures within the country (electricity, telecommunication and road) the infrastructures for natural gas lags behind the others.

Table 4. Gas prices for domestic use

Type of use Price (US$/MMBTU)

Fuel 1. Fertilizer 1 – 2 2. Steel industry 2 3. Electricity 2.45 – 3 4. Cement industry 2.70 – 3 5. Paper industry 130 6. Refinery 1.49 7. Plywood 0.97 8. City gas Rp. 2500-4150

Feedstock 1. Fertilizer 1-2 2. Steel industry 0.65 3. Methanol plant 1.42 – 2

Source: DG Oil & Gas; PT PGN.

• Weak planning and coordination

Development of natural gas industry has a long and complex project chain: exploration and production in the upstream side, various types of natural gas usages in the downstream, and gas transportation which may take some different infrastructure development options in between. Several government agencies and other stakeholders have their interests and point of views on the development of natural gas industry, but so far a good coordination so that the long gas development project chain can be carried out/maintained smoothly has not been found. The development of natural gas industry is not integrally approached yet, even by and

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within the energy sector itself. Planning and implementation of natural gas transmission and distribution projects has so far been carried out, mostly, by the state own enterprises (SOE), taking into account their interests but with a little coordination among other stakeholders/sectors. A blue print for an integrated national natural gas development policy and a formal/legitimate master plan for national natural gas transmission and distribution networks have so far not been published.

9 Action plan (short and mid terms) 9.1 Preparation for the master plan of natural gas transmission and distribution

networks

Natural gas transmission should be a regulated, natural monopoly business. The gas producers/consumers may access the transmission pipelines but need to pay a certain amount of toll fee for transporting their natural gasses. The operation of gas distribution network for a certain distribution area is not open for competition.

The master plan of natural gas transmission and distribution networks has to accommodate the characteristics of gas transmission and distribution business. The master plan has also to be intended to increase the capacity and flexibility of transporting national natural gas domestically. The master plan may include different scenarios for feasible gas developments. The development of the master plan for Indonesia should take into account the existence of Trans ASEAN Gas Pipeline (TGAP) plan.

Preparation for the master plan is very critical in the era of downstream liberalization to come, as new players will enter the national natural gas transmission and distribution business. The master plan, which has to take account inputs from several stakeholders in its preparation processes, will then serves as reference, among others, for BPH MIGAS in the process of company selection to develop a segment of the natural gas networks (planned). The master plan will also serve a reference for potential investors/businesses in identifying business opportunities in the national natural gas infrastructures and markets.

The preparation for the master plan of natural gas transmission and distribution

networks will require some intermediate and complementary works, among others: • The development of reliable database for the existing natural gas fields, prediction of

their productive life, development plan of each gas fields, committed and un-committed gas fields, rule of thumb for the usage of new gas fields found.

• Extensive assessment for domestic market capacities to absorb natural gas, as fuels

(for industries, electricity generations, transportation, households energy) and as feedstock for domestic fertilizers and petrochemical industries. The domestic capacities to develop natural gas-based industry that promise large value added and employment opportunities musts be assessed carefully; however, it also needs to take into consideration that the largest parts of natural gas usage will be left for fuels. Natural gas potential to substitute domestic oil fuels consumption in particular, has

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to be assessed in quite detail by type of usage for each sector (cooking for households, fuel for industry, etc.).

• The preparation of Mid Term and Long Term Scenarios of domestic gas

consumptions and their supply allocations. 9. 2 Natural gas transmission and distribution projects development finance

With an objective to accelerate development of infrastructure projects for gas transmission and distribution networks based on the gas master plan (that should be prepared /published soon), it is necessary for the government to develop alternative financing schemes for the development and operation of the planned gas projects. A breakthrough in incentives system, options for public-private partnerships, and creation of new institution to finance the gas infrastructure projects must be assessed and realized in the short future.

Basically, larger government initiatives, responsibilities and involvement in the planning/implementation processes will be required, both in the preparation of national gas master plan and the development of projects financing options. The involvement of SOE dealing with gas infrastructures will be important, but the most important thing is that the government should act as the leader of the gas sector development thorough its policy direction.

There are some alternatives for financing natural gas infrastructures development

projects to be assessed. These are the following:

• Direct incentives (tax reduction) by government to potential investors. Government guarantees a level of tariff (toll fee) that provides investors with a stream of revenues and reasonable rate of return for their capital invested. Give assistance to local investors in finding and negotiating low-interests financial sources, for instance, by offering the subsidiary loan agreement (SLA) schemes with low rate.

• Reconsider that the costs of gas pipeline projects development (the gathering lines)

spent by production sharing contractors as the type of costs that can be reimbursed by government, some periods after projects completion.

• The government, through its capabilities to raise funds from bilateral/multilateral

sources and domestic ones (including the issuance of government bonds), develops a segment of natural gas infrastructures, especially in the areas where gas market is not competitive yet, then transfer their operation and maintenance to private/SOE transmission and distribution companies.

• Establish infrastructure funds, with natural gas projects taken as a priority to be

funded by the funds. The creation of infrastructure funds requires strong commitment from the government/regulator, which may provide fiscal incentives and potential returns from investing in the funds. The government may act as a sponsor, facilitate conducive business environment or to provide partial guarantee in the establishment of the infrastructure funds. It is still remember that, following the

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economic crises in 1998-2000, the domestic stocks market collapsed and a quite significant amount of stock/bond values taken out by foreign/domestic investors. One might approaches those investors to participate in the creation of such infrastructure funds or to imitate their works. Other possible sources for the funds are domestic pension funds and life insurances, but it needs a changing of government regulation concerning their maturity.

• For State-Own Enterprises deal with gas infrastructure development projects,

offering a part of their (government) interests to public, as PGN is currently doing, is an appropriate option to increase the company’s capacity to finance particular gas transmission/distribution projects. The offering of the company’s shares to public is also a good vehicle for the company to improve its transparency and good governance.

9. 3 Prices, subsidy and tariff:

• Redefine domestic gas pricing to a system, which is more accommodative to direct negotiation between gas consumers and producers. In the medium to long terms, prices level that reflects opportunity costs of doing natural exploration and production will encourage investors to develop marginal/stranded gas fields.

• Reduce oil subsidies (Law No. 25 Year 2000 Concerning National Development

Program orders for this task). The lifting of oil subsidies will encourage society to consume more natural gas and enlarge gas potential to substitute oil in domestic energy mix.

• Gas pipeline toll fee. The determination of toll fee for gas pipeline must take into

consideration investment costs of pipeline development, the fact that some larger parts of the transported gas are owned by the state (through PSC schemes) and government policy to develop downstream industries.

9. 4 Urgent (very short term):

• To accelerate the development of gas fields and to improve the gas infrastructures to overcome the current gas supply crises in several areas (i.e., fertilizing industries in Aceh/E. Kalimantan and gas shortage in E. Java).

10 Summary and conclusion

In addition to natural gas, Indonesia is endowed with abundant energy resources such as coal, geothermal and many others renewable energy. The dependency on oil, therefore, can be reduced further through the development of these resources. Java, the center of Indonesia’s population and economic activities will always experience growing energy demand. To meet the growing demand, natural gas is a good option to be developed either in Java or by importing them from outer islands. Natural gas has its advantage in the

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regulation and institution set-up, as well as economy, technical and environmental factors, compared to other energy resources available in Indonesia.

The lack of gas transmission and distribution infrastructures is still a major constraint for natural gas to take more active role in supplying national energy demand and gas-based industry development. The subsidized oil price is another critical factor that prevents a faster growth for natural gas consumption in the domestic market. The amount of uncommitted reserves for the country’s natural gas is still quite large, and these can be developed to increase gas usages in domestic market. A breakthrough for gas infrastructures development must be made, firstly, by preparing the national master plan for gas transmission and distribution networks. The searching for financing options to develop gas transmission and distribution projects should be carried out and realized as soon as possible.

The development of natural gas transmission and distribution networks needs to be supported by all stakeholders in a nation wide. However, the planning and development of natural gas infrastructure projects must follow all the respected rules, especially Law No. 20 Year 2001 Concerning Oil and Gas. It is stipulated in the Law that “the Government prioritizes the use of natural gas for domestic market … ” (article 8:1) and that “Minister determines master plan for national transmission and distribution networks” (article 27:1). The efforts for developing our natural gas infrastructures must be carried out respecting this spirit.

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