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Energy & Mining | Indonesia’s Oil and Gas Sector – Upstream Challenges

Underinvestment has hampered progress in Indonesia’s oil and gas industries since the Asian financial crisis in 1998. Major oil and gas fields are drying up and are not replaced by new ones, due to a lack of exploration. As a result, the upstream sector, which accounted for about 4.6% of GDP in 2012, is failing to meet the country’s growing thirst for energy. Yet, while oil production is suffering from an obstinate decline in proven reserves, the prospects for natural gas look decidedly brighter.

Indonesia’s Oil and Gas Sector – Upstream Challenges
Many Indonesian basins have yet to be extensively explored for oil and gas deposits, making for potentially large additional reserves.

It is believed that most of the discoverable hydrocarbon deposits lie in less-explored eastern regions of the country. Finding and exploiting them will require heavy investment and a lot of deep-sea drilling. With energy security and state revenues in mind, government officials regularly stress the need to boost upstream production. Yet regulatory policies and public statements have sent out mixed signals about just how welcoming the sector is of foreign involvement.

Realized upstream investment in the oil and gas sector rose by 15% to $16.1 billion in 2012, continuing an upward trend (MEMR). A mere $1.4 billion USD of that sum, however, was spent on exploration, while $13.7 billion USD went on production and development activities and the remaining $1 billion USD on administrative expenses, according to government figures. In other words, the lion’s share of investment was needed to cover rising costs and prop up output from existing fields rather than discover new ones.

The upstream sector still depends overwhelmingly on foreign capital and expertise. Chevron Pacific Indonesia was the country’s top crude producer in 2012, accounting for more than 40% of national output. State-owned Pertamina EP held second place with around 15%. Other oil majors are Total E&P Indonesie and ConocoPhillips Indonesia. Gas production in 2012 was dominated by Total, with significant market shares also held by BP, ConocoPhillips and Pertamina.

Production & Reserves

National crude oil output has been on a declining path for more than a decade, sliding from a peak of around 1.6 million barrels per day (bpd) in 1995 to 860,000 bpd in 2012, government figures show. Amid rising domestic consumption, Indonesia turned into a net importer of oil in 2004 and left the Organization of Petroleum Exporting Countries (OPEC) five years later. Output dropped to 831,000 bpd per day in the first half of 2013 and was expected to once again miss the target stated in the state budget. Underlying this trend is a lack of exploration and development work to replace maturing oil fields. Proven reserves fell from 5.6 billion barrels in 1992 to 4.7 billion in 2002 and then down to 3.7 billion barrels by the end of 2012, according to oil company BP.

Unlike oil, natural gas has seen a gradual increase over the past decade, albeit with strong fluctuations from year to year. Annual output rose from 69.7 billion cubic meters in 2002 to 71.1 billion cubic meters in 2012, making Indonesia the tenth largest gas producer, according to BP figures. Indonesia’s proven gas reserves rose from 1.8 trillion cubic meters in 1992 to 2.6 trillion in 2002 and to 2.9 trillion cubic meters by the end of 2012, the third biggest in the Asia Pacific region and about 1.6% of global supply.

New Frontiers

Many Indonesian basins have yet to be extensively explored for oil and gas deposits, making for potentially large additional reserves. While the main producing fields are currently in Sumatra and East Kalimantan (for gas), the focus for exploration is moving eastwards and offshore. The most significant discovery in recent history, the ExxonMobil-operated Cepu block in East and Central Java, is believed to hold some 600 million barrels of oil and 48 billion cubic meters of gas. The government is pinning high hopes on Cepu, which is expected to achieve peak production in 2014, more than a decade after its discovery. The schedule was disrupted numerous times due to technical difficulties and lengthy negotiations with Pertamina, the other major shareholder in the project.

Hopes for boosting natural gas output in the near future rest particularly with the Natuna field in Riau Islands, which is believed to contain a massive 1.3 trillion cubic meters of gas (though a lot more exploration is needed). Its development, too, has seen numerous delays. The consortium of contractors, comprising Pertamina, ExxonMobil, Total and PTT EP from Thailand, expects to begin production in 2024. The Arafura Sea in the southeast of the country, home to the Inpex-operated Masela block, is also seen to offer lots of potential, as is West Papua, where BP is in the process of expanding operations at its Tangguh LNG project in Bintuni Bay. Meanwhile, the Makassar Strait has turned out to be a disappointment for a number of prospectors.

Domestic Market Shift

Domestic demand for both oil and gas is growing rapidly, which can be expected to prompt a voluntary or mandated shift towards the home market. For upstream producers, this entails both opportunities and risks. In the case of oil, additional demand will increasingly come from the petrochemical industry, though Pertamina’s monopolistic grip on distribution and refinery capacity takes some of the shine off this market. That said, domestic pricing will need to remain competitive if the government hopes to boost production.

In the case of gas, market growth is being driven by rapidly rising demand for electricity as state-owned utility PLN endeavours to extend its power grid into remote regions. Since Indonesia’s gas industry has traditionally been heavily export-led, the shift to the domestic market poses immense infrastructure challenges. State-owned gas distributor Perusahaan Gas Negara (PGN) is investing into its insufficient pipeline network, but it will take time to efficiently connect the gas deposit areas across the archipelago with the main industrial centres. And similar to oil, gas producers are faced with a de facto midstream monopoly. However, the government is in the process of lifting purchasing prices to more attractive levels, which is crucial to spur development of fields, many of which reside in hard-to-access regions.

Unconventional Gas

In addition to natural gas (and gas condensate), unconventional resources are attracting increasing interest in Indonesia (See Opportunities in Energy: Beyond Fossil Fuels). According to estimates from the Ministry of Energy and Mineral Resources, the country boasts some 12.8 trillion cubic metres of coal bed methane, which amounts to a multiple of conventional proven gas reserves. Exploitation of these resources, which lie mainly in Sumatra and Kalimantan, has barely commenced and it is believed that many commercially viable deposits remain to be discovered.

Indonesia’s shale gas potential is believed to be even greater at 16.3 trillion cubic metres, although that government figure remains speculative at this point. Pertamina in May 2013 signed a contract to explore and develop shale gas in North Sumatra. Because of the relatively high production costs, commercial viability of shale gas in Indonesia will hinge on future gas pricing. Regulations on unconventional gas are still being devised, which will likely keep private investors cautious in the foreseeable future about engaging heavily in the sector.


Industry representatives such as the Indonesian Petroleum Association (IPA) have blamed the regulatory framework for insufficient upstream investment. In particular, the risk of drilling dry holes is considered too high given that cost recovery only kicks in if and when production commences. The production sharing contract (PSC) system forces contractors to take bear of the upfront risk. Almost half of the 750 oil and gas exploration wells drilled between 2002 and 2012 were dry, according to upstream regulator SKK Migas. Several multinationals have surrendered blocks following fruitless exploration in recent years. Other industry complaints pertain to problems with land acquisition and cumbersome permit procedures.

The government commonly makes promises to cut red tape and improve incentives for upstream investment. Yet the changeable legal framework has kept many investors reluctant to commit large capital to long-term projects. Discussion revolves particularly around the following three aspects:

  • The split in PSCs: Reiterating previous statements, SKK Migas said it was planned to give contractors a greater share of production in forthcoming projects. As mandated in the 2001 Oil and Natural Gas Law, the government’s current basic take is 85% of oil and 70% of natural gas, leaving the contractor with just 15% and 30%, respectively (more attractive splits can apply in frontier areas). However, since the oil and gas sector currently contributes around a quarter of total government revenue, there is also resistance to such plans.
  • Cost recovery: Government Regulation 79 of 2010 states that contractors can recover operating costs through their share of production, but there remains some uncertainty about the application of these rules. GR 79 reduces the number of items that qualify for cost recovery and contains unclear language, such as the requirement for good business practices. Recurring political statements attacking cost recovery may also erode trust in the durability of existing regulations.
  • The domestic market obligation (DMO) requires contractors to sell up to a quarter of their PSC share on the home market to help satisfy domestic demand. The exact amount and sales price for this allotment depends on the specifics of the PSC and market conditions. This creates uncertainty and a risk of political interference, which, in addition to low prices paid on the strictly controlled market make the DMO unattractive for investors.


A more general concern is the unsettled institutional setting in the oil and gas sector. The abrupt disbandment of former upstream regulatory agency BP Migas at the hands of the Constitutional Court in November 2012 left investors worrying what this might mean for existing contracts and future regulations. To many, the court decision against BP Migas looked like a politically motivated move against foreign corporations, since the plaintiffs that initiated the judicial review included a number of nationalist-minded groups and individuals. The central government assured companies of the sanctity of contracts signed with BP Migas. Moreover, it moved BP Migas’ entire staff over into the swiftly instituted successor, SKK Migas. However, since SKK Migas was expressly created as a temporary taskforce pending changes to the Oil and Gas Law, uncertainties remain.

The dissolution of BP Migas, which had enjoyed a certain degree of autonomy in its day‐to‐day operations, and its replacement by a unit under direct control of the Energy and Mineral Resources Ministry, suggests that the issuance and administration of PSCs could become a less pragmatic and more political affair. While there was no visible shift in policies following the handover of control to SKK Migas, the situation fuelled concerns that the central government could become more susceptible to parliamentary lobbying and resource nationalism, which in turn could affect the issuance or extension of PSCs to foreign contractors. However, authorities are under pressure to increase upstream oil and gas production, not least to mitigate Indonesia’s trade deficit. President Susilo Bambang Yudhoyono has stressed that the financial muscle and knowhow of global players were still very much needed, nurturing hope that nationalist sentiment will take a back seat to energy security.

Global Business Guide Indonesia - 2014

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Indonesia Energy Snapshot

Contribution to GDP: 3.44% (2016) Oil & Gas Imports: $1.22 billion USD (Jan 2016)
Proven Oil Reserves: 3.69 billion barrels (2016)
Proven Gas Reserves: 2.85 trillion cubic metre (2016)
Proven Coal Reserves: 28 billion tonnes total reserves (2015)
Proven Potential in Geothermal Energy: 27 GW
Proven Potential in Hydropower: 75 GW
Other Energy Sources: Coal Bed Methane, Biomass, Waste, Ocean Current, Solar, Wind.
Current Energy Mix: Petroleum 41%, Coal 30%, Natural Gas 23%, Renewables 6% (2014).