Replacing diminishing reserves and guaranteeing domestic energy security are two of Indonesia’s policy priorities. As such, oil and gas exploration and development are key areas in which the government is eager to progress. To encourage this, policymakers have adopted a series of reforms aimed at ushering in a new wave of foreign investment into the sector. Similarly, in a bid to offset declining oil fields in western Indonesia, the government is working to incentivise contractors to explore deepsea areas along the eastern frontier.
As part of these efforts, the government has sought to reduce red tape and promote transparency. One such reform was the adoption of new gross-split production-sharing contracts (PSCs) in early 2017, replacing the previous cost-recovery model used for over 40 years. As of March 2019 the impact of the gross-split mechanism was yet to be seen, but the authorities remain optimistic that it will encourage exploration and production (E&P). Two large discoveries were made in 2018 and early 2019, namely the Kaliberau Dalam Well 2X in the Sakakemang block and the Merakes East reserve in the East Sepinggan block, which is estimated to deliver 70m standard cu feet (scf) of gas per day.
However, efforts to safeguard the nation’s hydrocarbons resources have seen the state reclaim significant oil blocks, which has raised concerns over future investment inflows. “Under the administration of President Joko Widodo, regulation and ownership rules have been a challenge for foreign direct investment (FDI) in the natural resources sector,” Maxwell Abbott, associate at government affairs consultancy Vriens & Partners, told OBG. “A sense of sovereignty over natural resources is an important part of the political culture in Indonesia.”
In addition, a legacy of regulatory uncertainty has hindered new exploration investment. As a result, reserve depletion remains a major challenge for Indonesia’s energy sector. At the same time, the question of how to balance environmentally sustainable power production and economic growth is an ongoing dilemma for policymakers.
Size & Performance
Despite a recovery in oil prices, the industry’s contribution to GDP dropped in recent years, with state revenue from oil and gas falling from 14% of GDP in 2014 to 5% in 2017. According to data from Statistics Indonesia, the supply of electricity and gas by state entities accounted for only 1.2% of total GDP in 2018, or Rp179trn ($12.7bn). At the same time, energy consumption has been rising. According to BP’s “Statistical Review of World Energy 2018”, primary energy consumption amounted to 175.2m tonnes of oil equivalent throughout 2017, 5% more than in 2016. Between 2006 and 2016 energy consumption grew at an average of 2.9% per annum.
At the end of 2017 Indonesia had total proven oil reserves of 3.2bn barrels, representing a 0.2% share of the global total. Throughout 2017 the country produced an average of 949,000 barrels per day (bpd), equating to 1% of global production and a 7.6% increase from 2016 levels.
From a longer-term perspective, oil output fell by an annual average of 1.4% between 2006 and 2016. This is due to the steady decline in reserves and a gradual shift towards greater gas production. “Oil production has been in steady decline over the last 10 years due to maturing fields and limited exploration activity, particularly in eastern Indonesia,” Sacha Winzenried, lead adviser for energy, utilities and resources at PwC, told OBG. “As Pertamina [the state-owned energy provider] takes over more of Indonesia’s large producing fields, it will face the challenges of technology investment and large funding requirements to maintain production decline rates.”
While output has been declining, domestic oil consumption has increased at an annual average of 2.4%. Indonesia has therefore become a net importer of oil, with declining crude production offset to some extent by new, highly productive natural gas fields. Oil refinery capacity and throughput are limited, amounting to 1.1m bpd and 887,000 bpd, respectively, with each figure representing a 1.1% global share.
Indonesia’s reserves have enabled the country to play an important role on the global stage in the natural gas export market. As of the fourth quarter of 2017 Indonesia was home to 102.9trn scf of natural gas, or 1.5% of the worldwide total. The wider Asia-Pacific region accounted for 10% of proven gas reserves, and Indonesia had the third-largest share in the region, behind only China and Australia. Local natural gas production amounted to 68bn cu metres in 2017, which marks a decline of 3.6% on 2016. Consumption, meanwhile, grew by 2.6% to reach 39.2bn cu metres. Indonesia’s pipeline natural gas exports totalled 8bn cu metres. With shipments of 21.7bn cu metres in 2017, Indonesia was the fifth-largest exporter of liquefied natural gas (LNG), behind Qatar, Nigeria, Australia and Malaysia. Indonesia is expected to fall to sixth place, however, since the US is set to emerge as the third-largest exporter by end-2019 as new capacity comes on-line.
Structure & Oversight
In terms of oversight, the Ministry of Energy and Mineral Resources (MEMR) is in charge of both energy policy and the national master plan for the transmission and distribution of natural gas. Under the MEMR, the Directorate General of Oil and Gas is responsible for the preparation and implementation of various upstream policies, such as the offering of new E&P blocks, as well as other policy matters related to oil and gas.
Commission VII of the House of Representatives has a number of key responsibilities, including research and technology, dealing with environmental matters relating to oil and gas activities, and drafting legislation and government policy. Regional governments give approval for Plans of Development (PoDs) through the issuance of local permits and land rights.
The Special Taskforce for Upstream Oil and Gas Business Activities (SKK Migas) is the state institution that controls upstream activities and manages oil and gas contractors on behalf of the government through cooperation contracts.
The Downstream Oil and Gas Regulatory Agency (BPH Migas) is tasked with a number of important responsibilities: regulating downstream activities; distributing business licences related to gas and petroleum products; ensuring sufficient natural gas and domestic fuel supplies; and managing the safe operation of downstream facilities.
In addition to entering into a number of high-profile joint operations, Pertamina’s scope of responsibilities includes gas, renewables and upstream operations within Indonesia, as well as several international operations. As part of the government’s resource nationalisation initiative, Pertamina recently took over a handful of key fields, including the Mahakam block, the largest field in East Kalimantan, in January 2018.
It is also set to take control of the Rokan block from US firm Chevron in 2021 once its PSC expires. The Rokan block is Indonesia’s second-largest crude oil-producing field (see analysis).
The company provides aviation fuel services at 10 international airports. In a bid to promote Indonesia’s energy sector, Pertamina acquired a 72.7% stake in French oil and gas company Maurel et Prom in early 2017. In doing so, Pertamina expanded its operations to 12 countries across four continents.
Perusahaan Gas Negara is another key stakeholder, tasked with operating a natural gas distribution and transmission pipeline network. The firm is 57% owned by the government of Indonesia and has subsidiaries involved in upstream and downstream activities, as well as a floating storage and regasification terminal.
In terms of electricity generation, state-owned utility Perusahaan Listrik Negara (PLN) is the dominant player within the power plant segment and the sole off-taker, transmission system operator and distributor. Best known as a coal-fired power plant operator, PLN also uses diesel power plants for power generation in some remote areas. Given its role as a state-owned utility, PLN remains constrained by low end-user tariffs and limited public service obligation subsidies, which in turn has hindered its ability to invest in grid development.
Global Oil Prices
A wave of geopolitical events has weighed heavily on oil market prices in recent years. From a peak of $147 per barrel in mid-2008, oil prices collapsed on the back of the global financial crisis to $40 per barrel by the end of that year. Driven by demand in emerging markets, crude oil prices recovered to approximately $94-98 per barrel between 2011 and 2014; however, the recovery was short-lived. The introduction of shale technology saw prices plummet once again as the US went from a net importer to a net exporter of oil. By the beginning of 2016 the price of oil had fallen below the $30-per-barrel mark, leading to a major drop in revenue for oil firms and a significant cutbacks on spending on E&P.
To help alleviate the strain felt by the industry, the Organisation of the Petroleum Exporting Countries restricted oil production at the end of 2016. Because of these efforts and increased international demand, the price of oil surpassed the $60-per-barrel mark by the end of 2017, at which time the Indonesian crude price reached $51.19 per barrel.
In mid-2018 the government announced a protection plan against increasing global oil prices. The government raised energy-allotted subsidies by $6.7bn in 2018, offsetting oil price hikes and currency depreciation to a degree. By mid-2018 Brent crude futures was up nearly 20% to $80 a barrel, while the rupiah fell in value from Rp13,400:$1 to Rp14,000:$1. While rising crude prices gave a boost to export revenue, a large portion of this was allocated to energy subsidies.
According to a preliminary budget document submitted to the Parliament by the Ministry of Finance in 2018, Indonesian crude prices were anticipated to average between $60 and $70 per barrel in 2019, while the rupiah exchange rate is expected to fluctuate between Rp13,700:$1 and Rp14,000:$1. At the end of February 2019 the price of Indonesian crude stood at $61.31 per barrel, and the exchange rate stood at approximately Rp14,300:$1.
In addition to crude subsidies, the government also introduced a coal price ceiling in 2018 for sales of PLN to reduce the impact of energy price increases on consumers. In March 2018 policymakers announced that the price of domestic coal purchased by power stations would be capped at $37-70 per tonne for two years, depending on coal type (see analysis).
Indonesia is one of the world’s largest producers and exporters of coal. Coal-fire power plants continue to be a key part of the country’s energy mix despite environmental concerns of coal-fired power plants. As such, Indonesia’s thermal coal reference price, the Harga Batubara Acuan (HBA), was set at $92.41 per tonne in January 2019 by the MEMR. The HBA price reflected a downturn of 0.1% month-on-month and a drop of 3.3% year-on-year.
Although oil prices have stabilised somewhat in recent years, the lack of upstream activity remains a concern in Indonesia, with only two new contracts signed from a total of 17 contracts offered in 2016. The downturn has persisted following the replacement of the traditional cost-recovery PSC by a new gross-split methodology introduced in 2017. In broad terms, under the conventional PSC, unrecovered investment costs could be carried forward and extended. Under the new gross-split PSC, hydrocarbons will be shared from first production; however, unrecovered investment costs from an expiring PSC will be taken into account as an additional split/take for the existing contractor. If a new contractor enters the fray, then it will proportionately bear the unrecovered costs. This effectively delays cost recovery for the contractor. In addition to lower levels of investment, numerous oil and gas working areas were relinquished between 2016 and 2017. By the third quarter of 2017 SKK Migas reported 46 oil and gas exploration blocks were in the process of termination due to insufficient output.
With a legacy of policy fluctuations, the investment profile has also suffered. The industry attracted around $10.2bn in investment in 2017, the lowest in a decade. However, there are concerted efforts under way to encourage exploration. Coupled with a rise in global oil prices, there is hope these efforts will result in increased investment. Total investment in the country’s upstream sector reached $11.9bn in 2018, up from $10.1bn in 2017. According to the MEMR, three oil and gas auctions alone recorded $11m in investment in 2018. SKK Migas is targeting upstream investment of $14.8bn in 2019.
The government carried out a number of measures in 2018 to boost investor appeal. One such step was the easing of taxes by granting a 100% corporate income tax (CIT) reduction to new FDI projects across all business sectors, provided that they meet certain requirements. Previously, the tax holiday was only available for certain investments in value-added industries, such as power plant machinery.
Under the new regulation, companies with a minimum investment of Rp500bn ($34.5m) are entitled to the CIT exemption for a period correlating to the size of their investment. For investments between Rp500bn ($34.5m) and Rp1trn ($70.9m), a CIT exemption is granted for the first five years, while those investing more than Rp30trn ($2.1bn) are permitted an exemption period of 20 years.
Following the exemption period, investors are entitled to a 50% tax cut in the transition period of two years. In order to apply for the CIT reduction a company must have a debt-to-equity ratio of no more than 4, and the new foreign investor must submit an application for the tax holiday to the Indonesia Investment Coordinating Board, either during the capital investment registration process or within one year of the issuance of the capital investment registration.
In addition to the new tax holiday policy, a number of foreign ownership restrictions were scrapped in an attempt to encourage greater FDI inflows. The government removed 22 of 51 restrictions for business licences in the energy sector, including for oil and gas, mineral resources and electricity. On top of these measures, tax deductions of up to 200% are set to be made available for companies carrying out research and development activities, while downstream investment is expected to be bolstered by a host of pipeline initiatives. BPH Migas announced in January 2018 that the government was preparing to auction three gas pipeline projects: the 687-km Natuna-West Kalimantan, the 1800-km West Kalimantan-Central Kalimantan, and the 162-km Central Kalimantan-South Kalimantan developments.
A number of upstream projects also made progress in 2018, including the Indonesia Deepwater Development (IDD) project located within the offshore Kutei Basin. The IDD project encompasses the joint development of the Bangka field and the Gendalo-Gehem projects. Partners in the Bangka project include Chevron (62%), Italy’s multinational Eni (20%) and Tiptop Energy (18%), a subsidiary of China’s Sinopec. Finished in 2016, the Bangka project was the first phase of the IDD project. According to official estimates, the field holds proven natural gas reserves of about 1trn cu feet, while the Gendalo and Gehem fields are estimated to hold natural gas resources of 882.5bn scf and 698bn scf, respectively.
The Gendalo-Gehem project, of which Chevron owns a 63% stake, is based around two separate hubs, each equipped with a floating production unit (FPU), subsea drill centres, natural gas and condensate pipelines, and an onshore receiving complex with separate facilities. Technology will be used to create a maximum production capacity of 1.1bn scf of natural gas and 47,000 barrels of condensate per day. According to local media, the natural gas from the project has been proposed for liquefaction by the state-owned Bontang LNG facility in East Kalimantan. The engineering-procurement-construction contract for the Gendalo-Gehem project has been awarded to the joint venture of US-headquartered McDermott International and Encona Inti Industri, while process simulations for the topside facilities on the FPUs were developed by local firm Synergy.
Another major upstream development is the Masela Project under Inpex Japan, which comprises the Abadi gas field and LNG project. The LNG portion of the project was identified as a National Strategic Project by the Indonesian government and was given priority status in September 2017 in an effort to accelerate development. In November 2018 the vice-minister of energy and mineral resources, Arcandra Tahar, told OBG that Inpex had already begun preliminary front-end engineering design for the Masela block in the Arafura Sea. Inpex, which holds a 65% stake in the block, plans to produce 9.5m tonnes per year of LNG and 150m scf per day of natural gas. According to SKK Migas, Inpex was expected to complete the Masela PoD before 2019 and commence production by 2027, but as of March 2019 the government had not yet approved the project.
In February 2019 Spain’s Repsol announced that it had made the largest gas discovery in Indonesia in 18 years. Located in the Sakakemang block in South Sumatra, the Kaliberau Dalam Well 2X is estimated to hold at least 2trn cu feet of gas.
In April 2018 plans for the Merakes gas field were approved. Under the operation of Eni, which holds a 75% interest, developers will leverage the nearby Jangkrik field to reduce the length and cost of execution. Eni also has a 55% share in the Jangkrik gas field, which commenced producing in 2017 from 10 offshore wells linked to a FPU with a production of 650m scf per day. In December 2018 Eni signed a gross-split PSC for the development of its Merakes field. In addition to its existing assets, Eni was also awarded a 100% stake in the East Ganal deep offshore exploration block located in the Kutei Basin in May 2018.
On the power front, inadequate infrastructure, high building costs and a lack of scalability have driven up the price of installing and generating electricity in recent years. The country has also been slow to adopt energy efficiency technology. “Local manufacturers are still not quite aware of the benefits of energy-saving technologies,” Isao Tsumura, CEO of Daikin, told OBG. “Partnerships with local universities, in addition to increased government support, are necessary for manufacturers and distributors to have a better understanding of the positive role these technologies will play in the future.”
The electrification rate of Indonesia reached 94.9% in the fourth quarter of 2017, with electricity consumption hitting 1 MWh per capita. Total installed generation capacity stood at 60 GW during this period, with 45 GW (75%) coming from the stateowned utility PLN, 12.5 GW from independent power producers and 2.5 GW from private power utilities.
The national transmission system, meanwhile, consisted of almost 50,000 km of lines and more than 77,000 MVA of transmission transformer capacity at the end of 2017. At the same time, the distribution system included around 950,000 km of lines and more than 40,000 MVA of distribution transformer capacity.
According to the National Electric Generation Plan (NEGP) 2018-27, electricity demand is set to grow by 6.9% per year, to reach 443 TWh by 2027. To help meet rising demand, the government had an initial target of adding 35 GW of generation capacity by 2019 at a cost of $72.9bn. This included the development of power plants, 732 transmission lines and 1375 unit substations.
However, on the back of a number of market shortfalls the 35-GW target was postponed to 2024, with 20 GW of new capacity set to be added by end 2019. As of April 2018, 1584 MW, or 4%, of the 35-GW programme had reached commercial operations; 4509 MW, or 13%, was still in the planning and procurement phase; 12,690 MW (36%) had been contracted; and 17,024 MW (48%) was under construction.
In line with an official ASEAN target, the NEGP 2018-27 includes a goal of 23% renewable energy generation by 2025, up from 11.9% in 2017. Bioenergy is set to comprise 10% of the energy mix, hydropower 3%, geothermal power 7% and other renewables the remaining 3%. According to statistics from the Directorate General of New and Renewable Energy and Energy Conservation in 2016, Indonesia has potential renewable energy reserves of 75 GW of hydropower, 29 GW of geothermal, 33 GW of biomass, 208 GW of peak solar, 61 GW of wind and 18 GW of ocean power.
“The MEMR’s Regulation No. 50 of 2017 requires new renewable energy generation to be contracted by PLN either at, or in many cases, below the stateowned company’s local average generation cost. This ensures that the adoption of renewables in Indonesia is helping to reduce generating costs, particularly in eastern Indonesia, where current costs are high,” Daniel Astbury, managing director for the Indonesian branch of Asian-Pacific renewable energy firm VENA Energy, told OBG. “Power purchase agreements for renewable energy such as wind and solar are becoming more common, giving independent power producers the confidence to invest significantly in renewable project development. However, challenges remain, including lengthy contracting timelines, remote sites requiring investment in transport infrastructure and lower tariffs in larger grid systems dominated by coal.”
There are sizeable opportunities for the private sector in renewables, Astbury added. “In addition to PLN’s cost-effective wind and solar projects, strong regional players have a role to play in helping the government reach its target of 23% by 2025.”
Volatile global oil prices have played a major part in driving Indonesia’s energy mix away from diesel-fired power plants. Formerly heavily reliant on oil imports, the country is looking to significantly reduce the use of oil in the energy generation mix from 5.8% as of 2017 to 0.4% by 2023. However, coal continues to dominate power generation, accounting for 57.2% of total power output in 2017.
With recent estimates predicting that oil reserves could be exhausted before 2030, much will depend on the industry’s ability to develop new fields while boosting the production at existing ones. As such, gas reserves present a major opportunity. In order to maximise their potential, lawmakers will need to carefully address investor concerns, particularly with regard to the recent nationalisation of assets, as well as divestment regulations. As far as power generation is concerned, with the high initial price of installation, achieving the renewable energy targets set out in the NEGP 2018-27 will pose challenges, particularly as the MEMR is working to balance reliability and cost with environmental concerns. However, recent advancements in renewable technology may help PLN find a way to balance its objectives of improving profitability while keeping power prices low while maximising renewables in the power mix.