Production: 78.8 bcm, +1% since 2003 Exports: 34.8 bcm, -17.8% since 2003
Share of gas (2012): 16.4% of TPES and 23.2% of electricity generation
Consumption by sector (2012): 39.2 bcm (industry 48.7%, power generation 29.5%, other transformations 21%, commercial 0.6%, residential 0.1%, transport 0.1%)
OVERVIEW
BACKGROUND
Natural gas accounts for about 16% of Indonesia’s total primary energy supply (TPES) and faces growing domestic demand. The country is a mature player in the natural gas industry and has been present in the global liquefied natural gas (LNG) market since 1977. It was the world’s largest LNG supplier for three decades before Qatar surpassed it in 2006. In 2012, Indonesia was the fourth-largest LNG supplier.
The country is the largest gas producer in the Southeast Asia region, and benefits from ample gas reserves, estimated at 2.9 trillion cubic metres (tcm) as of year-end 2012.
Despite this, Indonesia’s natural gas industry may be following the same fate as its oil industry as it moves from net exporter to net importer. Over the past few years, natural gas production has been in decline. Consequently, the country has been facing a shortage as the domestic appetite for natural gas at low prices necessitates re-routing of gas supplies intended for export to its domestic market.
SUPPLY AND DEMAND
SUPPLY
Indonesia is endowed with large natural gas resources. Although crude oil has traditionally played a greater role in Indonesia’s energy supply and exports, the country’s oil production has declined in recent years. By contrast, natural gas production in Indonesia has steadily increased, and in terms of calorific value, natural gas production surpassed crude oil in 2002. As such, Indonesia’s energy policy has shifted its focus from the oil sector to the natural gas sector.
In 2013, Indonesia produced 78.8 billion cubic metres (bcm) of natural gas, being 2.1%
higher than in 2012 but 8% lower than the peak of 85.7 bcm in 2010. The current level of production makes Indonesia the world’s tenth-largest gas producer with a 2.2% share of global gas production. The country’s largest production areas are in Sumatra, East Kalimantan and Papua, mostly offshore. The Mahakam Block in East Kalimantan is one of the largest and oldest gas blocks in Indonesia. Operated by Total since the 1970s, the block produced about 18 bcm or one-fifth of Indonesia’s total gas output in 2013.
2015
One forthcoming development is the Ketapang 2 Block in East Java, which is operated by Petronas and is expected to start producing an estimated 0.77 bcm of natural gas later in 2014. Recently, companies have been paying greater attention to less-explored areas in the eastern part of the country, such as West Papua, Central Sulawesi and the Arafura Sea.
Indonesia’s gas production is envisaged to reach 139 bcm by 2035 (IEA, 2013).
Although the short- and long-term prospects for Indonesia’s gas production are optimistic, various obstacles also exist, such as stranded and marginal gas, heavy CO2
content in new fields (e.g. East Natuna), a lack of infrastructure to bring gas to market, and the domestic market obligation, hindering increases in gas production.
The prospects for unconventional gas production in Indonesia remain rather uncertain, although the government is actively encouraging investment in the sector, including coal-bed methane (CBM) and shale gas. Pertamina was awarded the contract for shale gas exploration in the Sumbagut Block in North Sumatra in 2013, which is estimated to possess about 525 bcm of shale gas (Jakarta Post, 2013). However, Indonesia’s geographic topography and lack of infrastructure will present a considerable challenge in bringing its unconventional resources into production.
Progress has been slow in bringing CBM projects into production, despite abundant resources and government incentives aiming to bring about production of 15.4 bcm of CBM by 2023. In 2011, Pertamina signed four CBM contracts, two located in East Kalimantan and two in South Sumatra, comprising in total 14 working areas, all at the exploration stage (Pertamina, 2013).
As of 2013, four commercially producing CBM blocks were operational in Indonesia under the Sanga-Sanga CBM production sharing contract (PSC) in Kutai Basin in East Kalimantan, operated by VICO Indonesia, a joint venture between BP and ENI. CBM from this project has been exported via Bontang as LNG since March 2011, being the world’s first CBM to LNG project (Thomas, 2013), although the quantities are very small.
DEMAND
The industrial sector is the main consumer of natural gas, accounting for 48.7% of domestic consumption in 2012 (the latest data available per sector). The power generation sector consumed 29.5%, while 21% was consumed in other transformations, such as in oil and gas extraction, petroleum refineries and liquefaction (LNG) or regasification plants. Less than 1% was used in the commercial, residential and transport sectors combined (Figure 3.1).
Over the ten years to 2012, overall natural gas consumption increased by 19.3%.
However, this period saw a significant shift away from using gas in LNG and regasification plants, and towards greater use in power generation, transport and commercial use. Consumption by industry also increased at a slightly faster rate compared to total final consumption, as did natural gas use in households. However, residential, commercial and transport use are still relatively negligible as a share of the total.
Indonesian gas production initially oriented towards exports, but the country's declining oil production led producers to shift increasing gas volumes towards domestic consumption. In 2012, Indonesia consumed 39.2 bcm of natural gas, or just under half of its total dry gas production. Although the industrial sector accounts for the largest portion of domestic consumption, industry analysts expect the power sector to be the most significant driver of future consumption growth.
2015
Indonesia's gas distribution utility, Perusahaan Gas Negara (PGN), currently operates more than 5 600 kilometres (km) of natural gas transmission and distribution pipelines, particularly in Java and North Sumatra. Limited pipeline distribution infrastructure is in place in East Kalimantan, South Sumatra, Jambi, Riau, South Sulawesi and West Papua.
The highly fragmented nature of domestic distribution infrastructure outside Java and North Sumatra and a lack of integration of gas infrastructure across Indonesia impede a nationally integrated gas market. PGN has plans to develop gas distribution networks for small and medium-sized enterprises in the commercial and transport sectors.
PGN began operating the South Sumatra-West Java pipeline in 2008, providing an important link between the gas producing region of South Sumatra and the densely populated market of West Java. The Grissik-Duri pipeline is another important domestic transmission pipeline, as it provides gas to Chevron's Duri oil field for its steam flooding and power generation activities.
Figure 3.1 Natural gas demand by sector, 1973-2012
Notes: TPES by consuming sector; Mtoe = million tonnes of oil-equivalent.
* Other transformations include oil and gas extraction, petroleum refineries and liquefaction (LNG)/regasification plants.
** Industry includes non-energy use.
*** Negligible.
**** Commercial includes commercial and public services, agriculture/fishing and forestry.
Source: IEA (2014a), Energy Data and Statistics, OECD/IEA, Paris.
TRADE
In 2013, Indonesia exported about 34.8 bcm of natural gas, making it the world’s ninth-largest gas exporter (Figure 3.2). The ninth-largest importer of Indonesian natural gas was Korea (25%), followed by Japan (21%), Singapore (20%), Malaysia (19%) and China (7%).
However, the share of the country’s natural gas production that is exported has been in steady decline in recent years, from 48.1 % in 2002 to 41.5% in 2013, due to increasing domestic gas demand (MEMR, 2014a). The government is strategically allocating natural gas to the domestic market to meet growing consumption primarily from the industrial and power sectors.
LNG, traditionally used for exports, is also likely to be directed towards domestic use.
The government is planning to convert the Arun liquefaction plant into a regasification terminal, while the Lampung FSRU (floating storage and regasification unit) came online in 2014. Domestic LNG will arrive via the Bontang LNG terminal. According to Indonesian 0
1973 1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009 2012
Mtoe
government forecasts, the country is projected to start natural gas imports from 2017 and will become a net importing country in 2022. To secure further supply, Pertamina signed a purchase agreement with US-based Cheniere Energy to receive about 1 bcm of LNG per year for 20 years, starting in 2018 (Reuters, 2013).
While the reorientation of domestic natural gas towards the Indonesian market is inevitable to meet growing demand, consideration should be given to the financial implications of such a policy. Indonesia’s revenue from LNG exports amounted to nearly USD 13 billion in 2013. While down from USD 18 billion in 2011, this amount nonetheless represented almost 7% of Indonesia’s total export revenue (United Nations, 2014).
Figure 3.2 Natural gas production and exports, 2002-13 (bcm)
Source: IEA (2014a), Energy Data and Statistics 2014, OECD/IEA, Paris.
RESERVES
Indonesia has the world’s 14th-largest natural gas reserves. At the end of 2012, the country’s proven natural gas reserves were estimated at 103.35 trillion standard cubic feet (tscf) or 1.5% of global natural gas reserves, while its ultimately recoverable resources are much larger at 17.7 tcm (BGR, 2013). The largest undeveloped gas reserves are located in the offshore East Natuna Block in the Riau Islands, which holds about 1.3 tcm of gas reserves. Other promising areas include West Papua and Sulawesi (Figure 3.3).
The country has also been focusing on developing its unconventional resources.
Indonesia’s CBM resources hold significant potential; estimated at 12.8 tcm, they are some of the largest in the world. The majority of these reserves are located in South Sumatra and Kalimantan.
Once commercial production comes online, the gas is expected to be utilised by the Bontang LNG plants or to be delivered to a compressed natural gas (CNG) plant that might be established in South Kalimantan (Jakarta Post, 2012).
The country’s shale gas resources are estimated to be 16.3 tcm. The Central and South Sumatra basins are known to offer the best potential in shale gas deposits, while Kalimantan’s Kutei and Tarakan basins also have potential. The Eastern Indonesian basins are small and tectonically complex (EIA, 2013).
0 10 20 30 40 50 60 70 80 90
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
bcm
Production Exports
2015
Figure 3.3 Natural gas reserves, 2012
Source: Directorate-General of Oil and Gas (2013), Natural Gas Reserves, Ministry of Energy and Mineral Resources, Jakarta.