A complex set of laws and regulations governs the operation of the natural gas sector.
Principal among these are the Constitution and Law No. 22/2001. This latter law formally liberalised the downstream market by opening the sector (processing, transport, storage and trading) to direct foreign investment and ending the former monopoly of Pertamina.
The upstream and downstream oil and gas sectors in Indonesia are regulated by the 2001 Oil and Gas Law, which is currently under revision. This is expected to be concluded in the first two years of the new 2014 government. In January 2014, parliament adopted a new National Energy Policy (NEP14), which is expected to be transposed as a Presidential Decree in mid-2014. Notably, NEP14 calls for the reduction and eventual phase-out of fossil fuel exports from Indonesia and their redirection to the domestic market. This has already resulted in the cancellation of a gas export contract with Singapore. The NEP14 projects that the share of natural gas in primary energy supply will remain relatively flat between 2012 and 2050 at 24%, albeit at much higher volumes as energy supply increases.
Indonesia’s constitution sets out the principles upon which national energy policy and the management of the nations’ energy resources need to be based. Article 33 (parts 2 and 3) states that “production sectors that are vital to the state and that affect the livelihood of a considerable part of the population are to be controlled by the state”
and that “the land and the waters as well as the natural riches therein are to be controlled by the state to be exploited to the greatest benefit of the people”. This article has been invoked to prevent changes to implement a more market and foreign investment-friendly structure in the energy sector. This partly explains why Indonesia struggles to attract sufficient investment to meet growing domestic energy consumption, together with inadequate infrastructure and a complex regulatory environment. Article 33 has prevented the establishment of independent regulators, the liberalisation of Indonesia’s energy markets, the unbundling and privatisation of state-owned companies involved in energy production, and the phase-out of energy subsidies.
In 2010, Indonesia introduced a new regulation, GR 79, amending the rules and regulations for cost recovery and income tax in the oil and gas sectors. GR79 represents the first comprehensive framework for these issues in the upstream and downstream sectors.
Indonesia’s natural gas upstream arrangements (in the form of PSCs) make producers responsible for meeting domestic natural gas demand. Government regulation GR 35 of 2004 (replaced by GR 55 of 2009), in respect of PSCs executed after 23 November 2001, established the producer’s DMO at 25% of its share of production (although this share is understood to be higher at times). In 2010, the government introduced a priority allocation mechanism for the use of DMO gas, by means of GR 3 of 2010. Accordingly, gas use is prioritised in the following order: oil and gas production, the fertiliser industry, the power sector, and lastly, other industrial sectors. This volume is in turn allocated among each sector at prices negotiated between the suppler and consumer. These
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prices are approved by MEMR and at present vary among sectors. They are estimated by the World Bank to average USD 6.95 per million British thermal units (MBtu), well below the export price and market prices throughout the region. It is forecast that Indonesia may have to import LNG at market prices in order to serve its domestic market.
INDUSTRY STRUCTURE
UPSTREAM
Multiple companies, both international and domestic, participate in the upstream natural gas sector in Indonesia. The top ten companies account for nearly 85% of total gas production, and in 2012 the largest producer was Total producing 20.8% of Indonesia’s gas, followed by BP (15%), Pertamina (12.9%) and ConocoPhillips Grissik (12.6%). Total had 16 PSCs as at the end of 2012, of which six were under the company’s operation. Most of its production comes from the Mahakam area. Several Chinese national oil companies, including PetroChina, are also active in the sector.
LNG
Indonesia has three operating LNG liquefaction plants, Bontang, Arun and Tangguh, with a combined capacity of 46 bcm per year. The country has plans to construct three additional liquefaction plants: two at Donggi-Senoro and Sengkang in Sulawesi and one in Masela. Furthermore, there is a plan to expand the Tangguh plant together with the Abadi floating LNG (FLNG) project in the remote Arafura Sea. Those projects will boost the country’s combined liquefaction capacity to over 60 bcm per year.
Table 3.1 LNG infrastructure in Indonesia
Terminal name Shareholders Location Receiving
capacity Start date LNG
(South Sumatra) PGN Labuhan
Maringgai 2-3 Mtpa 2014 Domestic
and imports PLN and local industries
East Central
Java FSRU Pertamina Semarang
(possible) 3 Mtpa post-2014
Bontang and
Facility Pertamina Aceh 3 Mtpa post-2015 Tangguh and imports
PLN (Belawan power plant) and local industries
in Aceh and North Sumatra Note: Mtpa = million tonnes per annum.
Source: Fesharaki, F. (2012), “Indonesian LNG in the global context”, presentation to the FACTS Global Energy (FGE) Indonesia LNG Forum, 12-13 July.
Rapidly rising demand and limited interconnections between countries in Southeast Asia have prompted the installation of several LNG regasification terminals in recent years.
Indonesia’s first regasification terminal, an FSRU with a capacity of 4.1 bcm in West Java, started receiving deliveries in 2012 with 1.4 bcm of LNG from the domestic Bontang LNG plant. A part of the Arun liquefaction plant has been subject to modification for conversion to regasification. The country also plans to construct three FSRU facilities
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with a combined capacity of 10 bcm. They are planned to be located in Lampung, Banten and Central Java, all close to the country’s largest demand centres on Java. If all planned development is completed, the country will have a total regasification capacity of around 18 bcm. These FSRU facilities would contribute to enhancing security of natural gas supply by providing alternative resources, more flexibility and adequate storage to shave peak demand (see Table 3.1 above).
TRANSMISSION
The Indonesian natural gas pipeline network is comprised of a number of fragmented point-to-point grid systems, which transport gas between supply sources and large consumers or demand centres. Most pipeline networks are unconnected, as the country is composed of more than 17 000 islands and natural gas production is located on several islands.
Transmission or distribution of gas by pipeline requires approval from the downstream regulator, BPH Migas, which grants licences only for specific pipelines in commercial regions.
Transmission pipelines are considered by government to be a natural monopoly, and Law 22 imposes the requirement for open access. Otherwise, no requirement is placed on operators of pipelines and storage facilities to expand their projects to accommodate third-party access.
Indonesia has three large gas transmission system operators (TSOs), two of which, PGN and Pertagas, are state-owned. A third, Transportasi Gas Indonesia (TGI), which is owned 60% by PGN and 40% by a consortium of ConocoPhillips, Petronas, Talisman Energy and Singapore Petroleum, owns and operates two transmission pipelines. Pertagas operates 42% of the country’s transmission system network, followed by PGN (28%) and TGI (27%).
Pertagas owns and operates approximately 1 600 km of pipeline network across South Sumatra, West Java, Banten, East Java, North Aceh, North Sumatra and East Kalimantan (Figure 3.4). PGN operates the high-pressure pipeline network in South Sumatra, North Sumatra and West Java. The PGN system is approximately 2 300 km in length and transports natural gas from the producing regions to consumers.
PGN receives a toll fee for the transport of the gas as specified in gas transport agreements (GTAs) operable over 10 to 20 years. However, the limited size of the network and the lack of interconnectivity have been obstacles to further domestic consumption. Given their common ownership, a merger between Pertagas and PGN has long been mooted, but was ruled out by government in May 2014. Rather than merge as a single entity, the companies agreed to co-operate to develop gas distribution facilities in the country.
TGI operates the only cross-border natural gas pipeline, from the Natuna Islands of Riau and South Sumatra across the Strait of Malacca to Singapore. In 2012, Indonesia exported 7.7 bcm of natural gas via TGI pipelines to Singapore.
The transmission system is complex owing to factors such as the lack of pipeline system operations integration, including with electricity system operators, and unsynchronised regulations between the different upstream and downstream regulators. Direct co-ordination of transmission regulations between regulators is limited as each authority operates a different policy for network charges. For example, self-consumption of natural gas production activities is granted precedence according to the priority allocation mechanism under the DMO for gas.
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Figure 3.4 Natural gas transmission network
Source: Directorate-General of Oil and Gas (2012), Master Plan of Transmission and Distribution National Gas Network 2012-2025, MEMR, Jakarta.