Development of Indonesia’s energy sector to meet rapidly rising demand and sustain economic growth is arguably the most daunting challenge facing the administration of President Joko Widodo. A combination of economic growth, increased urbanisation and cheap energy supplies, resulting from fuel and electricity subsidies, have all led to sharp demand growth. Total primary energy consumption has risen by 70% over the last decade, while electricity demand growth has exceeded annual GDP expansion over the same period.
At the current rate of economic growth, demand for energy is forecast to rise by around 7% per year, while electricity demand is forecast to grow by upwards of 8% per annum over the next decade, according to the Ministry of Energy and Mineral Resources (MEMR). The country has abundant fossil fuel and renewable energy resources, but chronic underinvestment in the oil, gas and power sectors, and long-standing legislative, administrative and regulatory obstacles to private sector investment have seen falling oil and gas production and rising power supply shortages. While the increased use of indigenous resources has been prioritised to ensure security of supply, the government now faces hard choices going forward over the future energy mix to strike the right balance between affordability and sustainability.
Despite significant oil and gas reserves, Indonesia has witnessed a steady decline in production as falling output at mature fields has not been replaced with supply from new fields due to underinvestment. As a result, crude oil production has decreased by nearly half over the last 20 years, while gas output has fallen steadily over the last five years since peak production in 2010 of 85.7bn cu metres, according to the “BP Statistical Review of World Energy 2016”. In 2015 oil and gas production dropped to 786,000 barrels per day (bpd) and 8.078bn standard cu feet per day (scfd), respectively, according to MEMR data, while according to BP’s 2016 review, oil production fell 3% year-on-year (y-o-y) to 825,000 bpd in 2015 and gas output by 0.3% y-o-y to 75b cu metres.
Underinvestment in the oil and gas sectors is underlined by low reserve replacement ratios (RRR), which have seen proven oil reserves decline from 5bn barrels in 1995 to 3.6bn barrels in 2015 and proven gas reserves rise negligibly from 2trn cu metres to 2.8trn cu metres over the same period, according to BP. The RRR for oil was at 139% in 2015, but has averaged only 53% over the last decade, according to upstream regulator SKK Migas. In sharp contrast the RRR for gas was only 17% in 2015, but averaged 114% since 2007 – although this figure was distorted by a RRR of 309% in 2010.
Uptick In Demand
Indonesia’s sharp decline in oil production since the late 1990s has coincided with strong growth in domestic oil demand, resulting in change from net exporter to net oil importer in 2004. Over the last 20 years, demand has almost doubled as a result of rapid economic growth and a dramatic rise in the use of oil in the transport sector, which has been exacerbated by fuel subsidies built into government pricing for oil products.
Gas demand has also gone up as a result of its increased use as a feedstock for power generation. Gas consumption by the power sector has risen over 88% over the last 10 years to 319.5bn standard cu feet (scf) in 2014, while industrial demand has grown by around 44% over the last decade to 683.18bn scf, according to the MEMR’s 2015 statistical handbook. Gas usage by households and businesses remains very low, but has increased from 1.75bn scf in 2005 to 8.97bn scf in 2014.
The domestic impact of the global economic slowdown saw both oil and gas demand stagnate in 2015, marking a brief hiatus in an otherwise upward trend. Oil consumption fell 3.2% y-o-y to 1.63m bpd in 2015, from a peak of 1.68m bpd in 2014, while gas demand slipped 2.7% y-o-y to 39.7bn cu metres in the same period, from a peak of 43.4bn cu metres in 2010, according to BP.
Crude oil production is set to rise in 2016, though not as high as targeted under the state’s 2016 budget. The government had set an increased crude oil production target of 830,000 bpd for 2016, but in June of that year it proposed revising this target down by 2.4% to 810,000 bpd as some producers had reduced their output due to lower energy prices. Looking forward, Sudirman Said, the minister of energy, proposed lowering the target by 8-10% in 2017 to 740,000-760,000 bpd.
According to SKK Migas, production by Chevron in East Kalimantan, Pertamina Hulu Energi in the offshore north-west Java block, and Petronas in the Ketapang block are below estimates. As of mid-2016 there had been no change to targeted gas production for 2016 of 7.83bn scfd. However, figures from the MEMR for the first three months of 2016 show production on or above schedule, with average output of 835,000 bpd and 8.3bn scfd of gas. Volumes rose over the first quarter, with Indonesia pumping 819,000 bpd in January, 840,000 bpd in February and 847,000 bpd in March.
Increased production has come chiefly from the Banyu Urip field in the ExxonMobil-operated Cepu oil and gas block, which raised production to 165,000 bpd in early 2016, and as of May 2016 was producing at a rate of 185,000 bpd, according to the US-based major. The field, which at 185,000 bpd accounts for around 25% of Indonesia’s liquids output, is key to the country maintaining oil and condensate production at 750,000-800,000 bpd over the next few years.
In May 2016 ExxonMobil announced that it could produce 200,000 bpd if required on the basis of well performance, reservoir quality and low production costs. The Cepu block straddles the border between Central Java and East Java and is estimated to contain about 600m barrels of oil. Banyu Urip, the block’s major oil discovery, is estimated to hold more than 250m barrels. First production began at the field in 2008. ExxonMobil and Indonesia’s state-owned oil and gas company Pertamina hold a 45% stake each. ExxonMobil disclosed in May 2016 that it had submitted a development plan to the government for the Kedung Keris field, adjacent to Banyu Urip, which if approved as expected could start producing 5000 bpd by the end of 2019.
In addition, in November 2015 Malaysia’s state-owned oil and gas firm Petronas began supplying oil and gas to East Java and Central Java from two of its upstream projects. The Bukit Tua field, an integrated oil and gas project located in the Ketapang block, is expected to produce 20,000 bpd of oil and up to 50m scfd of gas, while the Kepodang field in the Muriah block in Central Java is expected to deliver 116m scfd of gas. Under the production-sharing contract (PSC) for the Ketapang and Muriah blocks, Petronas, through its subsidiaries, holds an 80% equity share in both projects, with the remaining 20% held by Saka Ketapang Perdana and Saka Energi Muriah. Petronas, which ventured into Indonesia’s oil and gas sector in 2000, is currently involved in 10 PSCs and operates four oil and gas blocks across the country.
On the gas side, initial output of 120m scfd of gas and 2880 bpd of condensate are expected in 2017 from the Bangka field, which is the first stage of the Chevron-operated Indonesia Deepwater Development (IDD) project in the Makassar Strait, according to energy analysis and research firm Platts. First gas is also expected in the same year from the Eni-operated Jangkrik project in the Kalimantan offshore area under a deal signed in June 2015 for the sale of 1.4m tonnes per annum (tpa) of liquefied natural gas (LNG) from 2017 onwards to Pertamina, which will be supplied to the Bontang LNG terminal, according to Platts.
Meanwhile, Pertamina, which operates the gas fields in the Cepu block, is in the process of awarding engineering, procurement and construction contracts for the Jambaran gas field. Production at Jambaran, which is being developed under a unitised development plan with the state oil firm’s 100%-owned Tiung Biru field, is estimated at 185m scfd when it comes on-stream in 2019.
Significant new gas production could be brought on-line over the coming years, if the government can address long-standing concerns among investors, chiefly the future of PSCs upon expiry. This is in sharp contrast to the oil segment where increased crude production, principally from the Cepu block, is not expected to offset declining production at maturing fields. With no major new discoveries oil production is expected to fall to no more than 700,000 bpd by 2019, according to MEMR projections in its 2015 report. On the other hand, major gas production projects include: Chevron’s IDD project, with peak daily production forecast to reach as high as 1.1bn scfd of gas and 47,000 barrels of condensate; Eni’s Jangkrik field in Muara Bakau; and the Inpex-operated Abadi field in the Masela gas block in the Arafura Sea, which is estimated to contain 14trn scf of gas. Inpex has a 65% operating interest in the Abadi project, with Shell holding the remaining 35%.
Significant new gas is also expected from the East Natuna block, which contains an estimated 222trn scf, but with a high CO content at around 70%. About 46trn scf of the gas is thought to be recoverable, although the separation of CO is challenging and costly, according to Platts. In December 2015 the contractors – ExxonMobil, Pertamina and Thailand’s PTT – were awarded a 30-month extension to continue evaluation of the block.
Investing In The Future
Production to date has largely been based on relatively low-cost exploration and development of the onshore and shallow offshore regions of West Java and Sumatra. But replacing these maturing fields will require moving into deeper waters in more remote areas with higher risks and costs. This will lead to the need for more foreign investment and technology at a time when international market conditions are characterised by low prices and oversupply, and international exploration and production (E&P) players have cut spending. Competition is also intensifying among countries for new investment.
In acknowledgement of this, the administration of President Widodo has made an effort since coming to power in 2014 to address some investor concerns and attract investment. The government has sought to minimise red tape by streamlining the permits process and speeding up project approval. In mid-2015 it announced that the number of licences required by the MEMR had been cut from 52 to 42. Other initiatives to spur E&P include bringing oil and gas investments under the purview of the Investment Coordinating Board. In January 2015 the board launched a one-stop service for investment licences. A total of 22 ministries and government bodies have each delegated representatives to the board in order to simplify investment procedures. In addition, it has set up the National Exploration Committee to assist with tackling the challenges confronting the upstream industry. Finally, the MEMR set up a new committee which aims to achieve a 75% RRR by halving the time between awarding a block and discovery.
However, many more changes will be needed given that the Indonesian Petroleum Association estimates that new exploration investments will require 341 separate permits across state ministries and another 101 from local governments. This is underscored by the level of upstream activity, or lack thereof, in the first half of 2015. According to SKK Migas, only 26 wells were drilled in the first half of 2015, representing 17% of the original target of 157, and only 12 new seismic surveys were carried out, down from the planned 46. Meanwhile, upstream capital expenditure in 2016 is set to fall y-o-y to $17.21bn, comprising $1.26bn on exploration blocks and $15.95bn for drilling and development of producing blocks, according to SKK Migas.
There are signs that the government realises that more needs to be done to encourage investment in challenging exploration opportunities. In May 2016 the MEMR announced that the state would offer more attractive terms for 15 blocks it is due to tender in its first licensing round of the year. No date has been set for the tender, which will comprise 14 conventional oil and gas blocks and one shale gas block, but the new terms and conditions will offer more flexibility on future production, Djoko Siswanto, upstream business director at the MEMR, said in an April 2016 statement. Under the new conditions, investors will be able to propose the production split, which will be among the factors considered in deciding the winner. Previously, Indonesia had applied a fixed production split for oil projects of 85:15 between the government and investors, and 70:30 for gas projects. Additionally, investors will be able to propose the size of the signature bonus in the bid; until now this has been decided by the state.
Block By Block
The 14 conventional blocks are split evenly between seven regular tenders and seven direct tenders. The former include: South CPP block, which is onshore Riau in central Sumatra; South-east Mandar, offshore of South Sulawesi; North Aguni and Kasuri II, both onshore in West Papua; Oti offshore of East Kalimantan; and Suremana I and Manakarra Mamuju, both offshore in the Makassar Strait. The Batu Ampar shale onshore block in Kalimantan will also be offered through a regular tender. Blocks to be tendered directly include: Bukit Barat, which is offshore the Natuna Islands; Batu Gajah Dua onshore in Jambi, Sumatra; Kasongan Sampit onshore in central Kalimantan; Ampuh in the Java Sea; Ebuny offshore south-east Sulawesi; Onin and West Kaimana, which are both onshore and offshore in West Papua.
The government has at least another 27 oil and gas blocks under consideration for tenders over the course of 2017-19. Given the MEMR’s announcement, investors are hoping that the new terms will prove more attractive. In a 2014 licensing round only 11 out of 13 blocks attracted bids, eight of them conventional, with awards in March 2015 to Anglo-Dutch Shell, Norway’s Statoil and Petronas, among others, for eight conventional and three shale gas blocks. The winning bidders committed to spend $144.25m on exploration activities over three years in 11 blocks, with the government earning $12m in signature bonuses.
However, the main obstacles to the development of Indonesia’s resources are rooted in strong resource nationalism, the continuing lack of coordination among ministries, regional governments and other state bodies, and the need for more structured decision-making within central government. Darmin Nasution, coordinating minister for economic affairs, highlighted this state of affairs in a statement at the opening of the 40th Indonesian Petroleum Association Conference in Jakarta in May 2016. Nasution said, “In the last two years investment declined, not only due to the price, but also the design of our policies.”
Reform of the upstream sector can no longer be delayed, he added, saying, “Simplification of the licensing process is not enough. We need to get down to the basic design of this sector.” Nasution also said that any restructuring should involve not only the MEMR, but other ministries, such as the Ministry of Finance, Ministry of Environment and even the Ministry of Maritime Affairs and Fisheries.
The most glaring example of unclear lines of decision-making and conflicting interests is the Inpex’s Abadi field in the Masela block, which is creating a global record for the length of time between discovery and commercial start-up. The Japanese investor signed a PSC for the Masela project in 1998, but first production is now not expected before 2025 as a result of disagreements between the MEMR and the Coordinating Ministry for Maritime Affairs (CMMA) over whether the LNG project should be developed as a floating model, as originally planned, or be built onshore. In 2010 the MEMR had approved Inpex’s original plan of development, which involved a 2.5m-tpa floating LNG (FLNG) plant and condensate production of 8400 bpd.
In September 2015 Inpex submitted for approval a revised plan that increased the FLNG plant’s capacity to 7.5m tpa and 24,000 bpd of condensate production after it discovered additional gas reserves. However, the CMMA, which is charged with coordinating MEMR’s activities with those of other ministries, has since instructed the MEMR and SKK Migas to review the FLNG concept as an onshore plant, which it argued would be more economically viable and beneficial to the eastern Indonesian island of Maluku, where the plant could be built. In September 2015 Rizal Ramli, former coordinating minister of maritime affairs, told The Jakarta Post that an onshore plant would cost an estimated $15bn, compared with $19.3bn for an FLNG plant. The final decision rests with Widodo, who in March 2016 released a statement to the press saying he needed more time to decide given the project’s scale and complexity. With general elections scheduled for 2019, it is unlikely that a final investment decision will be made before then, which in turn would mean a start of operation date no earlier than 2025-26, just two years before the PSC expires. The companies are still in negotiations with the government for an early 20-year extension to the Masela PSC, which expires in 2028.
On The Dotted Line
The government’s stance on extending expiring PSCs is a major disincentive for investment, as seen in the slow development of Chevron’s IDD project and the Masela project. The lack of a clear timetable and process for handling renewals, extensions or divestment of PSCs under the Oil and Gas Law No. 22 of 2001 was expected to be clarified by new amendments. However, delays in approval led the MEMR to issue a new regulation in May 2015 that essentially transferred control of expiring PSCs to Pertamina. Furthermore, the government’s decision in June 2015 not to extend the PSC for the Mahakam block – which is operated by Total and Inpex and is due to expire in 2017 – and instead hand over operatorship to Pertamina sent a negative signal to other investors.
Given the importance of the Mahakam block, which accounts for a quarter of Indonesia’s gas production, as well as the significant annual investment and technical experience required to maintain production, the decision to give Pertamina a 70% stake and reduce the current operator’s holding to 30% will raise concerns among foreign players that their blocks may face similar futures. Chevron’s IDD project and Inpex’s Abadi LNG are two examples of projects that are unlikely to move forward until they are guaranteed PSC extensions.
Producing more gas is one thing. Delivering it to consumers is quite another. The main demand centres in Java and Sumatra are currently supplied by onshore fields with gas delivered on a point-to-point basis by pipeline. However, as gas production at mature onshore fields in Java and South and Central Sumatra continues to decline, Indonesia will increasingly need to bring gas from Kalimantan, Sulawesi and Papua, as is already the case with LNG supplied from the Tangguh plant in Papua to the Lampung floating storage and regasification unit (FSRU).
This will require new pipelines to connect new gas fields and to interconnect existing pipelines in Java and Sumatra, as well as the development of floating and land-based LNG regasification terminals to receive LNG from domestic and foreign sources. Development of a series of mini-LNG terminals is also planned to provide power to remote islands and reduce the use of petroleum-based fuel. It will also require significant investment.
According to the MEMR’s natural gas development roadmap published in September 2015, which runs through 2025, investment of at least $32.42bn will be required. As much as $8.5bn will be needed to expand the pipeline network to connect gas fields to gas stations in major cities. This will see the gas pipeline network more than doubled to 27,273 km by 2025. As of the end of 2014 the country had 12,034 km of pipeline, consisting of open-access pipeline, dedicated upstream and downstream pipeline, and private pipeline. In addition, $13bn will be required for the construction of gas stations, $8bn for liquefaction and regasification projects, $2.5bn to establish city gas networks and $420m for liquefied petroleum gas processing and distribution facilities.
In terms of liquefaction facilities, the country plans to build six large plants and 10 mini-plants by the end of 2025. Meanwhile, for regasification as many as 11 FSRUs and 66 land-based facilities are expected to be in operation by 2025. Under the plan nine new FSRUs will be built, located in Cilacap, Central Java; Banten and Pomalaa in Southeast Sulawesi; East Kalimantan; Ambon and Halmahera in Maluku; and Porong in East Java.
Existing Facilities & Expansion Plans
At present, the country has two FSRU facilities, in West Java and Lampung, and one land-based regasification terminal, namely, the converted Arun LNG plant in Aceh. It also has three liquefaction plants: the 22.5m-tpa Bontang LNG plant on Kalimantan, the 2m-tpa Donggi-Senoro LNG on Sulawesi and the 7.6m-tpa, BP-owned Tangguh LNG in Irian Jaya.
The government is counting on Pertamina and national gas transport and distribution firm Perusahaan Gas Negara (PGN) to spearhead its ambitious infrastructure investment programme. In April 2016 PGN announced that it aims to build 1680 km of transmission and distribution pipelines, as well as 60 gas field stations – known by their Indonesian acronym SPBG – to be located in Jakarta, West Java, East Java, Banten, Batam, Lampung, Riau and North Sumatra by the end of 2019. In addition, it also plans to develop gas networks in a number of cities and regions. PGN currently operates 7026 km of gas pipelines across the country and five SPBGs, and distributes gas to 14 other SPBGs operated by PGN’s partners. In 2015 it supplied 1.6bn scfd gas through its grid. PGN also said it will optimise its existing gas infrastructure, including the Lampung FSRU, with the aim of increasing LNG supply to consumers in Java and southern Sumatra.
Pertamina, via its gas subsidiary Pertagas, has disclosed plans to construct seven regasification terminals and five liquefaction plants by 2019. Its most advanced project is an FSRU in Cilacap, Central Java, which is designed to import up to 1.6m tpa and is scheduled to come on-line in 2018. Pertagas invited prequalification bids in June 2016 to build the facility on a build-own-operate-transfer basis. Meanwhile, Pertamina and Tokyo Gas are jointly developing a 4m-tpa, LNG-receiving terminal at Bojanegara in West Java at an estimated investment of $810m, following the signing of a memorandum of understanding (MoU) in February 2015. Other projects planned by Pertamina include three land-based LNG terminals in Benoa (Bali), Porong (East Java) and Makassar (South Sulawesi), and three mini-LNG plants each in Simenggaris and Nunukan (both in North Kalimantan) and Salawati (West Papua). Pertamina also signed an MoU with Osaka Gas in March 2016 to jointly develop LNG infrastructure in Indonesia, with plans to design, build and operate LNG-import terminals.
A massive investment programme in the power sector is ongoing in a bid to meet sharply rising demand growth and provide close to universal access to electricity (see analysis). Indonesia has nearly doubled its installed capacity over the last 10 years to 52,889 MW as of the end of 2015, from just 27,241 MW in 2005, with a corresponding rise in electricity production, but this increase has failed to keep pace with rising demand. Over the last decade, electricity demand growth has consistently exceeded annual GDP growth. Following the Asian financial crisis of 1997-98, annual demand growth averaged 8.7% between 2009 and 2013. While this pace of expansion has eased in recent years as a result of the economic slowdown and the impact of electricity price increases since 2014, it is still outpacing new supply. Total electricity production in 2015 rose by 5.7% to 233,982 GWh, up from 228,553 GWh in 2014, while total sales of electricity in 2015 increased 5.9% y-o-y to 202,846 GWh. However, peak power demand in Indonesia is growing at an average annual rate of 8.7%, equivalent to 3800 MW per year, and is expected to reach 74,536 MW by 2024. In 2015 it stood at 36,787 MW against total installed capacity of nearly 53 GW, but supply-demand margins are particularly tight in Sumatra and East Indonesia.
This level of growth combined with insufficient investment in sector infrastructure has led to falling reserve margins and rising power supply shortages. Supply disruptions are an increasingly common occurrence. In recent years, when the reserve margin has fallen to 15%, Perusahaan Listrik Negara (PLN), the state-owned power producer and operator of the country’s transmission system, has been forced to implement load shedding, leading to two-to-three-hour-long daily blackouts, according to a March 2016 report on the sector by tax consultancy PwC. Electricity demand is expected to continue to grow given the country’s low per capita electricity consumption, which was estimated at 787 KWh in 2015. According to PLN’s medium-term electricity supply business plan, demand is forecast to more than double to 464 TWh by 2025, at a rate of 8.7% per annum over the next decade. To meet projected demand growth, an estimated $132bn in investment will be required up to 2025, comprising $97bn for around 70 GW of new power generation capacity and $35bn for the development of the associated transmission and distribution infrastructure, including about 59,000 km of high-voltage lines and 164,000 km of distribution lines, according to PLN.
The first step in achieving its power generation target was launched in March 2015 with the 35-GW programme, which also includes a further 7 GW of capacity carried over from the first new-build plan, with an accompanying expansion of the high-voltage grid by 46,000 km (see analysis). Under the revised 35-GW generation programme, which spans the 2016-25 period and was released by PLN in mid-2016, 70%, or 25 GW, of total capacity will be developed by independent power producers (IPPs), with the remaining 30%, or 10.6 GW, produced by PLN. The share of capacity to be developed by IPPs and PLN up to 2020, as well as the generation mix, remains almost unchanged from the original plan. Coal-fired capacity is still set to account for 55% of total new capacity, or 19,813 MW, confirming expectations that it will continue to be the main source for electrical power in Indonesia for the foreseeable future.
However, the share of gas-fired capacity in the revised programme has been reduced from 38% to 36%, with 1 GW less of capacity planned up to 2020. There were also marginal increases in the expected additions of geothermal and wind capacity to 725 MW and 180 MW, respectively. According to PLN’s plan, of the total 70 GW of new capacity planned to be installed by 2025 around 60% will be coalfired generation, 20% gas-fired and 20% renewable. As a result, based on current projections, coal will account for a 57% share of total installed generation capacity by 2025, followed by gas (24%), renewables (17%) and oil (2%).
Major investments in hydrocarbons and electricity production, as well as supply infrastructure will be required over the coming years if Indonesia is to meet demand and drive economic growth. The success of these investment programmes will depend on the country’s ability to attract private sector players, which in turn will rely on the government setting the right pricing signals, regulations and investment policies. The ability to harness and manage sustainable sources of energy will be critical to the country’s future.
With oil and gas production continuing to decline at same time as domestic consumption is rising, increasing exploration and development of its untapped reserves, most notably those in deeper waters, will be vital. Uncertainty surrounding permits and licensing, PSCs, domestic market obligations, cost-recovery procedures and tax obligations has reduced investor confidence and is undermining efforts to attract the required investment and expertise at a time when the country is competing globally and regionally for reduced investment by international players in a market environment of low prices and oversupply.
However, policy initiatives undertaken since 2014 signal that President Widodo and his government have understood the challenges. Efforts have been made to streamline the regulatory process for investors, most notably in terms of licensing, while the government is offering more attractive and flexible terms and conditions for the PSCs on offer in the next licensing round in 2016. Furthermore, increased use of gas and renewable energy will help Indonesia meet its international commitments to reduce greenhouse gas emissions by constraining the growth of coal-fired generation, as well as allowing the government to meet targets to supply power to its entire population and reduce the use of oil-fired generators on remote islands. Geothermal power offers a viable base-load alternative to coal power, while gas could provide much-needed peaking power for the grid (see analysis).
Progress on mid-stream development will in many ways dictate the further development of the domestic gas sector. Delays to the construction of new gas transport, processing and storage facilities will likely result in the deferment of final investment decisions by upstream projects designed to supply the domestic market and off-takers in industry and power generation. Development of renewables will now depend on new support mechanisms planned for wind, solar and geothermal, and the establishment of a stable source of financing that will help PLN cover the higher off-take costs (see analysis).
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