As Indonesia’s economy keeps chugging along with annual growth rates around 6% in recent years, its appetite for energy continues to expand in parallel. Demand for primary energy hit 130m tonnes of oil equivalent (mtoe) in 2013, and GDP growth of 8% a year through to 2025 forecast by the National Energy Council (NEC) is expected to push growth in energy consumption up to 7.3% a year in 2013-25, under a business-as-usual scenario. This would put primary energy demand at 277 mtoe within a decade, well above the 2013 supply of 189 mtoe.
A big dilemma for policymakers is where to derive all of this new energy. In the short term, a good deal of it will come from increased use of the country’s plentiful and inexpensive coal, but in light of rising concerns about global carbon emissions, cleaner and more diverse alternatives will be preferred in the long term. Renewable sources fit this bill nicely, yet their smaller size and greater expense is likely to relegate them to a supporting role.
This leaves natural gas as a middle ground compromise. Here, too, however, there are tough trade-offs. Should the country forgo revenues from exports of liquefied natural gas (LNG) to divert gas towards domestic use? Or should it accept larger energy bills at home, boosting energy imports and buying expensive renewable technologies? Either way, all of the country’s current energy development plans assume flat or rising domestic use of natural gas.
The volume of gas used to meet local demand rose by 155% over the past decade, from 1480bn British thermal units (Btus) per day in 2003 to 3774bn Btus per day in 2013, according to the 2013 annual report from oil and gas regulator SKK Migas. Gas used locally that year surpassed the gas sales commitment to export markets by 5.2%, and the country could become a net exporter by 2020. The 2013 local-use allocation of 3774bn Btus per day (up from 3550bn Btus the previous year) outstripped the export sales commitment of 3402bn Btus per day (down from 3631bn Btus in 2012). According to SKK Migas, in 2015 domestic commitments will hit 4403bn Btus per day, equal to 61% of domestic output, while the volume set for exports is estimated at 2836bn Btus per day.
Simply boosting production may seem the best way to avoid both of these compromises. Years of under-performace in exploration and development, however, have caused output to decline since 2010, falling to less than 3bn standard cu feet per day (scfd) in 2013, with average output for the year at 2.97bn scfd. Meanwhile, the NEC projects primary demand for natural gas to more than double by 2025, to 9bn scfd from 4bn in 2013. Plans from the Ministry of Energy and Mineral Resources call for a substantial increase in gas output to maintain its contribution at around 20% of primary energy supplies through to 2025. Yet with gas prices for domestic use below the selling price for exports, plus lengthy commercialisation periods (7-8 years from drilling to production), much investment has been deterred.
The country’s output goals are supported by ongoing development of natural gas transport networks, consisting of pipelines, gasification units and liquefaction terminals. While all of these could conceivably be used for LNG exports, the network is being designed primarily to provide natural gas to as yet unserved locations. The islands of western Indonesia will rely on expansion of existing pipelines and gasification terminals, while the eastern parts will rely on LNG shipments.
Its geography has limited Indonesia’s natural gas pipeline network so far to a few isolated bands served by two state energy companies, Pertamina (via its subsidiary Pertagas) and Perusahaan Gas Negara (PGN). While PGN owns and runs more than 5900 km of pipelines covering North and South Sumatra, Batam, and West and East Java, Pertamina’s network adds another 3800 km, serving North and South Sumatra, West and East Java, and East Kalimantan. Pertagas is also building a new line to connect the markets of West and East Java.
Given the country’s lack of connectivity, the chief means of getting natural gas outside these networks has been to build shipping and receiving terminals. This current solution also allows producers to remain flexible in their gas sales, by putting LNG gasification plants in surplus areas like Tangguh and Bontang and then shipping it, either abroad as part of export deals, or to high-demand local areas serviced by regasification terminals.
The first LNG receiving terminal facility opened in 2012, when the floating storage regasification unit (FSRU) Nusantara Regas opened in the waters of Tanjung Priok, Jakarta. A joint venture between PGN and Pertamina, the Nusantara Regas unit is contracted to receive LNG of around 1.1m tonnes per annum (tpa) from Indonesia’s 22.6m-tpa Bontang LNG plant for 10 years.
The country’s second regasification facility, located in Lampung off the southern tip of Sumatra, received its first shipment of LNG in July 2014. Sourced from the 7.6m-tpa Tangguh LNG plant operated by BP in Papua, this gas was the first of five scheduled deliveries to the FSRU for that year. With a handling capacity of 2m tpa of LNG, a storage capacity of 170,000 cu metres and a distribution capacity of 240m standard cu feet per day (scfd), the Lambung unit will supply gas to power generators and industrial users in West Java via the South Sumatra-West Java pipeline.
A third terminal followed less than a year later, coming on-line in the first quarter of 2015 after the Arun facility completed its conversion from an LNG export operation to an import terminal. A microcosm of Indonesia’s evolving energy sector, Arun was refitted to receive gas cargos for Aceh and North Sumatra after the fields that supplied it became unproductive. With its new configuration, the terminal can process 12m tpa of LNG, part of which will be piped to the Perusahaan Listrik Negara power plants, including those in Arun (40m scfd) and Belawan (95m scfd), as well as an additional 250m scfd that was earmarked for industrial use.
To maintain supply-demand balances in the country and allocate gas supplies where they are most needed, the government sets the number of LNG shipments each terminal is to receive each year, though these targets are not always met due to production shortfalls. The Nusantara Regas terminal is allocated 27 shipments per year through 2018, while the Arun terminal is to receive eight shipments in 2015, doubling to 16 a year for 2016-18.
Converting To Gas
Natural gas could also have an impact on Indonesia’s rising petroleum trade gap in the transport sector. With crude oil production set to continue declining, the only viable way to curb the country’s dependence on imports would be to shift the transport and power generation sectors gradually towards increasing use of natural gas and bio-fuels, instead of refined petroleum products. State incentives are one way this could be achieved.
In this vein, a major government initiative is currently under way to convert vehicles to gas use, as well as develop refuelling stations and transmission lines. Initial work in this area is focused on expanding networks of compressed natural gas (CNG) vendors in cities, including a CNG distribution contract signed in January 2014 by the two state-owned energy firms, Pertamina and PGN.
Under the terms of this contract, PGN will use its vast pipeline network to supply petrol stations throughout the country with gas, which will then be sold to the public as CNG for use in vehicles. Pertamina, for its part, will be responsible for equipping the petrol stations with CNG dispensers, compressors, gas dryers and other necessary equipment. By using the country’s existing network infrastructure, rather than constructing an entirely new distribution system from scratch, the government hopes to circumvent the initial supply problems that frequently accompany the roll-out of such programmes.