Indonesia has long been a key supplier to global energy markets, with the first oil discovery made in North Sumatra in 1885. Energy production has grown since then to include gas, coal and renewables, but the industry’s role within the country has evolved as oil fields have matured and the population has continued to grow. The focus has shifted from export-oriented production towards meeting domestic demand. Meanwhile, Indonesia is currently a net importer of petroleum products – a status that may place the country in good stead given the dramatic fall in international oil prices as a result of the Covid-19 pandemic.
Current objectives include meeting the demand for consumer fuel through crude and palm oil, addressing electricity demand via coal and renewables, and using natural gas to supply predominantly industrial consumers. The Indonesian government aims to consolidate control over upstream crude oil activities, primarily through the state-owned enterprise (SOE) Pertamina, but still welcomes foreign investment in the sector.
Structure & Oversight
The legal framework governing the sector is provided by Law No. 22 of 2001, but in 2012 the Constitutional Court ordered the disbandment of the former upstream regulator, leading to expectations of an updated version of the law. Drafts of an amended legal framework have circulated in recent years, including a version in 2018 that was made publicly available for stakeholder feedback. However, as of early 2020 the passage of a new energy law seemed to be on the backburner as other major laws were pushed through. Nonetheless, the drafts provide an indication of how policymakers will look to reshape the sector, stating that oil and gas are to be controlled by the state, with many assets to be consolidated within SOEs.
“The restructuring for SOEs is really going to help if it is done right,” Greg Arnold, an associate at Jakarta-based consulting firm Vriens & Partners, told OBG. “SOE heads are going to need to be open to new ideas and there are plenty of qualified people for the roles.”
Some of what is expected under the reformed law has been set in motion. This includes the government making Pertamina the holding company of SOEs in the oil and gas industry in 2018, and combining its business with that of Perusahaan Gas Negara (PGN), whose primary role is owner and operator of the country’s network of gas pipelines. PGN is still publicly listed on the Indonesia Stock Exchange, but majority ownership was acquired by Pertamina in February 2018, when it bought the government’s 57% stake in the company. Upstream oil and gas activities are now under Pertamina, while Perusahaan Listrik Negara (PLN) is the sole electricity distributor and produces most of Indonesia’s power.
The Ministry of Energy and Mineral Resources (MEMR) creates and applies energy policy and awards contracts. Downstream usage is overseen by the National Energy Council, while policy direction is formulated by the organisation’s National Energy Policy. Among the targets established by the latter is to increase the contribution of renewables and new energy sources to 23% of the energy mix by 2025 and at least 31% by 2050. Furthermore, the policy aims to reduce the cumulative contribution of crude oil, coal and natural gas to the energy mix from a ceiling of 77% in 2025 to 69% in 2050. Since 2012 the upstream sector has been regulated by the Special Taskforce for Upstream Oil and Gas Business Activities (SKK Migas). The main downstream regulator is the Oil and Gas Downstream Regulatory Agency (BPH Migas), which assumed the role from Pertamina in 2002.
While SOEs predominate, Indonesia’s energy sector is partially open to foreign investment, though local-content stipulations require energy companies to give priority to Indonesian employees and subcontractors. Restrictions on foreign investment were issued through Presidential Decree No. 44 of 2016, which stipulates that onshore acreage is off limits and caps ownership of offshore drilling at 75%. Foreign entities may hold up to 49% of services companies involved in surveying, offshore pipe installations and spherical tanks, and 75% of entities which construct oil and gas platforms. Areas that remain off limits to foreign investment include onshore pipe installations, production installations, and the installation of tanks and storage facilities. All contracts must be settled in Indonesian rupiah, and can be subject to exemptions and phase-in periods.
At the end of 2018 Indonesia had total proven oil reserves of 3.2bn barrels, down from 3.7bn a decade earlier, according to the latest figures from BP. Meanwhile, gas reserves stood at 2.8trn cu metres at the end of 2018, only slightly lower than in 2008, when they totalled 2.9trn cu metres. Crude production averaged 808,000 barrels per day (bpd) in 2018 – down from 838,00 bpd a year earlier – and represented 0.9% of global production.
At current levels of production, reserves and technological capacity, Indonesia is set to enjoy another 10.7 years of output before its wells run dry. As of early 2020 full-year production figures for 2019 were unavailable, but projections for 2020 were roughly 705,000 bpd. However, with both domestic and international demand for oil at a record low in early 2020 as a result of policies aimed at containing the spread of the global Covid-19 pandemic, production is likely to be below this figure.
Natural gas production reached 73.2bn cu metres in 2018, up from 72.9bn cu metres the year before. This represented an annual increase for the first year since 2010, which marked a peak for output, with production of 87bn cu metres and 2.6% of the global total. The 2018 figure accounted for 1.9% of global production and ties Indonesia with neighbouring Malaysia as the 11th-largest producer. The reserves-to-production ratio implied another 37.7 years of output, given current metrics. Revenue from oil and gas climbed from Rp85trn ($6bn) in 2004 to Rp143.3trn ($10.1bn) in 2018, with the state budget targeting Rp159.8trn ($11.3bn) in 2019. During the 2004-18 period, sector income peaked at over Rp200trn ($14.1bn) between 2012 and 2014, when prices for Brent crude were above $100 per barrel. However, the sector’s contribution to total state revenue has gradually declined, dropping from a 21.1% share of total state revenue in 2004 to 7.38% in 2018 – a trend which roughly correlates with Indonesia’s reduced crude oil output. Oil and gas contribution to overall revenue peaked at 24.9% in 2006 and dropped as low as 2.8% in 2016. With the Brent crude price having fallen precipitously in early 2020 to around $20 per barrel in late April as a result of the economic impact of the global Covid-19 pandemic, hydrocarbons revenue and its contribution to national coffers is set to fall lower.
Indonesia was a member of the Organisation of the Petroleum Exporting Countries from 1961 until it suspended membership in 2009. It rejoined briefly in January 2016 but suspended membership again in November of that year. Roughly three-quarters of all exploration and production occurs in the western half of the archipelago. Most oil is produced on or around Sumatra; East Kalimantan; Natuna, which is part of the Riau Islands; and the Java Sea. East Kalimantan and Natuna are also major gas-producing provinces, along with South Sumatra and Papua. The production of crude oil is currently dominated by three companies: Pertamina and the Indonesian subsidiaries of the US multinationals Chevron and ExxonMobil. Chevron Indonesia had a 28.7% share of production as of 2018, and Mobil Cepu accounted for 26.9%. Pertamina, which is set to take over Chevron’s main block and the country’s second-largest field, Rokan, had a 10.3% share, the licence for which will expire in 2021. While production in this major field has flagged since 2018, Pertamina’s takeover is expected to result in savings of $4bn per year in crude imports. While some stakeholders cite the transition to Pertamina as indicative of a broader trend of “resource nationalisation”, whereby international investors are not granted an extension of their concessions, the Indonesian energy firm has also been a major partner with a participating interest in large-scale projects. This was the case in November 2019, when foreign investors ConocoPhillips and Repsol, along with Pertamina, were granted a 20-year extension to the Corridor natural gas block, which Pertamina had expressed an interest in taking over.
Gas production accounts for about 60% of overall upstream hydrocarbon output. As in the oil sector, Pertamina has been inheriting some major assets from foreign companies as their licences expire. This includes the Mahakam gas field, which was formerly operated by a consortium led by France’s Total. In comparison with the relatively mature oil sector, there is considerably greater potential for new gas finds. In 2019 a consortium led by Spain’s Repsol and Malaysia’s Petronas found an estimated 2trn cu feet of gas in the Sakakemang block, marking the largest gas discovery in Indonesia in 18 years. Four companies have at least a 10% share of gas produced, namely BP, with a 16.9% share of production; ConocoPhillips, at 13.2%; Eni, at 10.5%; and two divisions of Pertamina, which, if taken together, constitute the largest single stake, at 25.8%.
In early 2017 the government introduced a significant reform for upstream investors, adopting a new gross-split production-sharing contract model, replacing the previous cost-recovery model used for over 40 years. Under the new system, the state no longer contributes to costs, but in exchange grants operators freedom to allocate capital expenditure and receives a smaller cut of revenue. The split between government and producer is adjustable based on a plan of work, from a baseline of a 57% government share in oil and 52% in gas. In limited cases, investors can choose between the new and old contract structures. “The benefit is lighter regulation, but that is possibly not overall a better economic deal for companies given the longer period it will take to recover the overall investment, particularly for new exploration or higher-risk projects,” Sacha Winzenried, lead adviser of energy, utilities and resources for PwC Indonesia, told OBG.
The government initially hoped that the new mechanism would boost investment, as 2017’s total investment figure of $10.2bn was the lowest in a decade. However, so far the returns have been modest. Larger companies are generally holding on to their key projects but are not necessarily focused on exploration. The investment figure ticked up in 2018, reaching $10.9bn, but remained below the target of $14.2bn. In the first half of 2019, however, investment jumped 16% year-onyear to $5.2bn, but the large drop in oil prices in early 2020 is likely to drag on future investment.
Even in a challenging environment, the country has attracted major investors. In March 2020 SKK Migas said it was aiming to double gas production by 2030, with major projects such as Inpex Japan’s Masela Project and Repsol of Spain’s Sakakemang block in South Sumatra, which has an estimated 2trn cu feet of gas.
Pertamina is Indonesia’s primary oil refiner and owned seven of the country’s nine refineries as of early 2020. The remaining refineries belong to the MEMR’s Research and Development Agency and a private entity. Total capacity was 1.12m bpd in 2018, or 1.1% of global capacity, according to BP. Throughput was 916,000 bpd, leaving a gap of about 350,000 bpd covered by imports. In line with the objective of reducing imports, the Refinery Development Master Plan in 2014 was launched with the goal of refurbishing existing facilities and increasing domestic production. Under the plan, Pertamina aims to spend $60bn to reach 2m bpd of capacity by 2026. Preparations are also under way for the establishment of new privately owned refineries in Musi Banyuasin, Batam and Bojonegara.
The country’s gas pipeline network is most developed on Sumatra and Java, near the most productive fields and a number of population centres. However, plans include the expansion of on-land networks on Sulawesi, in the provinces of Kalimantan, and on the eastern islands of Maluku and West Papua. Major pipelines are operated by Pertamina Gas and PGN, though private pipelines can also be developed. Regulations state that pipe owners must allow third-party access.
The government takes the lead in allocating domestically produced energy through SKK Migas. Domestic sales are prioritised over exports, which are monitored by SKK Migas. Law No. 22 of 2001 caps domestic market obligations for producers at 25% of output, and there are no specific thresholds in the draft law to replace this. In the oil sector, as of September 2018, all producers are required to offer to sell their total output directly to Pertamina, for use in its refineries. Regulations also require that Pertamina prioritise domestic purchases over imports. Prices are set by the MEMR every month based on international crude prices. In April 2020 the MEMR announced industrial gas prices would be capped at $6 per million British thermal units (Btu) to reflect upstream prices and associated transport costs.
For gas producers, domestic supply contracts can be negotiated directly with domestic users, but the government retains involvement through SKK Migas and encourages domestic sales rather than imports. Official policy direction is to use the gas available to attract new industrial users of the fuel, though some gas is used by PLN to produce electricity. Upstream producers typically receive $5 per million Btu, and industrial users generally pay about $9 per million Btu. In 2019 domestic gas supply was expected to average 3.935trn Btu per day, down from 3.995trn Btu per day in 2018, according to the latest available figures from SKK Migas.
Indonesia remains a leading exporter of liquefied natural gas (LNG), despite a decline in volume, with a global share of 4.7% as of April 2019, putting it seventh in the world. Its global export position has been falling since 2006, but this is in line with the government’s policy of reorienting gas production for domestic use rather than export. Exports fell from 2.7trn Btu per day in 2018 to 2.1trn Btu per day in 2019, less than half the 4.4trn Btu per day recorded in 2003.
There are three LNG export facilities: Bontang in East Kalimantan, Tangguh in West Papua, and Donggi Senoro in Sulawesi. Another is being developed as part of a joint project between Japan’s Inpex and Shell to develop the Abadi natural gas field in the Arafura Sea. This will entail the creation of an offshore production facility and an onshore LNG plant with the capacity to process 9.5m tonnes per year. Inpex has a 65% stake in the project while Shell holds 35%. The government approved a revised development plan for the project in mid-2019, but several challenges still lie ahead for the project, including the remoteness of the onshore facility and the need to install 150 km of pipeline.
An expanding population and economy has led to rising annual power consumption, widening the gap between exports and imports and adding to state spending. Growing expenditure is exacerbated by the fact that consumer fuels in the retail market are subsidised. Among the main drivers of rising consumption is an increase in demand from the transport industry. While industry accounted for 46.2% of energy consumption in 2008, its share had fallen to 33.5% by 2018. Over the same decade, transportation rose from a 31.1% share of energy consumption to 45.1%. Household and commercial use have remained steady, at 15% and 5%, respectively. Energy consumption reached 185.5m tonnes of oil equivalent in 2018, up 4.9% from 176.9m tonnes in 2017, according to BP. Oil accounted for 38.8% of primary energy supply in 2018, according to the MEMR, while coal accounted for 33% and gas 19.7%. Due to the share of coal in the mix, consumption represented 1.3% of global energy consumption but emissions accounted for 1.6%.
Pertamina is the main provider of consumer fuels through its distribution network, in addition to operating 90% of filling stations. However, the SOE’s formal monopoly over downstream marketing ended in July 2004, and foreign investors in this segment have since included Shell, ExxonMobil, Total and BP. Overseas firms compete largely in the non-subsidised fuels market. The subsidised prices for consumer fuels and power have been frozen since 2018, with the government bearing the brunt of any commodity price hikes through its subsidy programme. Expected price hikes following the 2019 election have not come to pass, with pump prices for petrol falling as of early 2020. These are expected to fall further given current oil prices.
The subsidy system uses quotas for specific fuels based on a per litre price. In 2019 the value of subsidies was Rp85.7trn ($6bn), which is projected to fall to Rp70.5trn ($5bn) in 2020. Long-term reform plans include more targeted subsidies to ensure that only those who cannot afford to pay receive aid. The plan is structured to allow prices at the pump to increase, with rebates given to those qualified based on use.
Work is ongoing to reduce dependence on imported fuels by blending diesel with crude palm oil, with Indonesia positioned as the world’s top producer of the commodity (see Agriculture chapter). Biodiesel blends with 30% crude palm oil are in use, after the contribution was hiked from 20% in January 2020. The government’s goal is to further increase the concentration of crude palm oil in the future – potentially as high as 40%. The 30% blend – the highest mandatory mix in the world – is expected to reduce fuel import costs by Rp63trn ($4.4bn). Nevertheless, in late 2019 President Joko Widodo, better known as President Jokowi, announced that operators of trucks and state-owned power plants had reported that palm-oil blends can be harmful to machinery, particularly at higher concentrations. As a result, the MEMR revealed in early 2020 that testing is ongoing in order to improve performance.
Electricity is a priority sector for development, with the government seeking to enhance reliability in areas that already have services while also extending it to regions that lack supply. Electrification rates are at 100% in much of western Indonesia, but in less populated areas it is as low as 59.9%, according to PwC. In addition to accounting for the lion’s share of power generation and all transmission and distribution functions, PLN is the off-taker for all utility-scale independent power producers (IPPs). “Larger players wield considerable influence in the power sector, which makes it difficult for smaller companies to increase market penetration,” Henry Maknawi, president director of domestic firm Kencana Energy, told OBG. “Nevertheless, there are opportunities for the private sector in the fast-moving green energy industry.”
Installed generation capacity stood at 64.9 GW in 2018. Of this, 62.3 GW was on-grid capacity, up from 31.5 GW a decade earlier. On-grid production stood at 267.1 GWh in 2018, of which 188.7 GWh was sourced from PLN plants. PLN purchased the remainder, or 29.4% of supply, from IPPs. Large-scale users can build their own capacity and sell excess to the grid, while IPPs can sell directly to consumers in a set area, subject to licensing and tariff approval from the relevant authorities. Moving forwards, the state anticipates greater private sector participation in generation, with new capacity coming primarily from IPPs. However, investors in renewables have reported some difficulty in securing project approval from PLN as renewables often are more expensive to produce than coal-fired energy.
Current plans include increasing coal-fired thermal power to make use of Indonesia’s abundance of coal deposits and the low cost of using these. While the share of new and renewable energy in the energy mix has been targeted to reach 23% by 2025, as of 2019 only 13% of power was derived from such sources. Considering the slow progress made towards the 2025 target, some stakeholders want to see reforms accelerated to incentivise renewable energy investment and usage, such as a progressive feed-in-tariff scheme.
“I would like to see PLN encouraged to use more renewable energy in their production mix. Strong and favourable feed-in tariffs without frequent policy changes could be big drivers for investment in renewables,” KK Ralhan, chairman of Kaltimex Group, told OBG. PLN has experimented with off-grid solar installations in remote areas. For instance, Multi Buana Group, a Jakarta-based diversified industrials conglomerate, has built a solar-powered mini-grid system in the eastern section of the island of Sumba, part of the East Nusa Tenggara province in the south-central part of the country, where on-grid access is about 30%. The project covers 140 villages in the area, and PLN awarded the company a 20-year power-purchase agreement at $0.25 per KWh. The company is also experimenting with a smaller model suitable for around 100 households. This involves collaboration with local governments and investors, and asks people to pay for battery-storage backup to solar power, according to Budi Yulianto, CEO of Multi Buana Group. “Solar power is only attractive where the electrification rate is very low,” he told OBG.
Given Indonesia’s maturing oil fields and growing population, prioritising production for domestic use rather than for export has led to a shift in expectations for upstream producers. Even so, the state has indicated a willingness to be more flexible on issues such as contract structure in the hope that foreign producers with exploration expertise will increase their investment in the country. There is optimism that the gradual increase in exploration spending from 2018-20 will lead to greater payoffs in the future and contribute to the goal of achieving energy self-sufficiency.
As lawmakers tweak the investment environment on the supply side, measures to reduce energy imports could help to address the current account deficit, especially if the technical obstacles to mandating higher blends of crude palm oil in biodiesel can be overcome. The fuel import bill is set to be lowered in the immediate term by low oil prices resulting from the Covid-19 pandemic. However, the pandemic will also have a negative impact on the sector, with SKK Migas estimating in April 2020 that the state’s gross revenue from oil and gas would be nearly halved from previous projections, from $32bn to $19bn, as hydrocarbons production falls.