This country-specific Q&A provides an overview of the legal framework and key issues surrounding oil and gas law in Indonesia.
This Q&A is part of the global guide to Oil & Gas.
For a full list of jurisdictional Q&As visit http://www.inhouselawyer.co.uk/index.php/practice-areas/oil-and-gas
Does your jurisdiction have an established upstream oil and gas industry? What are the current production levels and what are the oil and gas reserve levels?
Yes. According to the BP Statistical Review of World Energy 2019 (“2019 BP Report”), as of the end of 2018, Indonesia’s proven natural gas reserves amounted to 97.5trillion cubic feet (“Tcf”) and its proven oil reserves to 3.2 billion barrels, putting Indonesia in the top 20 of the world’s oil producers. Oil production reaches 808,000 barrels per day. Gas production reaches 62.9 million tonnes per annum, representing 61% of total oil and gas production in Indonesia. According to the PwC Oil and Gas Guide 2019 (“2019 PwC Guide”), Indonesia has 453 Tcf of coalbed methane reserves, the sixth-largest in the world, while shale gas reserves are estimated at 574 Tcf.
How are rights to explore and exploit oil and gas resources granted? Please provide a brief overview of the structure of the regulatory regime for upstream oil and gas. Is the regime the same for both onshore and offshore?
Indonesia’s oil and gas sector is governed mainly by Law No. 22 of 2001 regarding Oil and Natural Gas (November 22, 2001) (the “Oil and Gas Law”) and Government Regulation No. 35 of 2004 regarding Upstream Oil and Gas Business Activities (as amended, “GR 35”). The State retains mineral rights throughout Indonesian territory and the Government holds the mining authority. The Minister of Energy and Mineral Resources (“MEMR”) determines upstream work areas for onshore and offshore operations based on consultations with and recommendations from the respective regional governments. Upstream activities include exploration and exploitation and are managed and supervised by the Special Task Force for Upstream Oil and Gas Business Activities (“SKK Migas”).
Private companies earn the right to explore and exploit oil and gas resources by entering into cooperation contracts, mainly based on a production sharing scheme, with the Government (through SKK Migas), thus acting as a Contractor to SKK Migas. One entity can hold participating interest (“PI”) in only one Production Sharing Contract (“PSC”), but several entities can hold PI in a single PSC.
What are the key features of the licence/production sharing contract/concession/other pursuant to which oil and gas companies undertake oil and gas exploration and exploitation?
A PSC is normally granted for 30 years, typically comprising six plus four years of exploration and 20 years of exploitation. There are two main types of PSC. In the traditional production sharing scheme used in Indonesia, production output is typically subject to a first tranche petroleum (“FTP”) requirement, cost recovery and certain taxes, and the remaining portion is distributed between the Contractor and the Government in the proportions set out in the PSC (the “Cost Recovery PSC”). All financial risks related to the operations under the PSC are borne by the Contractor. If a work area proceeds to the exploitation stage, the Contractor is entitled to cost recovery.
The other, newer type of PSC was introduced by the Government in early 2017 through MEMR Regulation No. 8 of 2017 regarding Gross Split PSC, as amended several times, most recently by MEMR Regulation No. 20 of 2019 (“MEMR Reg. 8/2017”). The Gross Split PSC employs a gross split production sharing scheme, by which production output is split at gross (without FTP, cost recovery or tax deductions) in proportions stipulated at the beginning of field development and subject to fluctuation depending on certain variables and progressive components.
Are there any unconventional hydrocarbon resources (such as shale gas) being exploited and is there a separate regulatory regime for unconventionals?
Yes. Unconventional hydrocarbon resources in Indonesia include shale gas, shale oil, tight sand gas, and coalbed methane.
Unconventional hydrocarbon resources are subject to the Oil and Gas Law and its implementing regulations, the same as conventional oil and gas resources. They are also subject to MEMR Regulation No. 5 of 2012 regarding Procedures for the Stipulation and Offering of Unconventional Oil and Gas Working Areas, which regulates the offering of unconventional working areas through a direct offer or regular tender.
Who are the key regulators for the upstream oil and gas industry?
The Ministry of Energy and Mineral Resources stipulates regulations and oversees the oil and gas industry, while SKK Migas manages and supervises the upstream sector.
Is the government directly involved in the upstream oil and gas industry? Is there a government-owned oil and gas company?
The Government regulates and supervises the upstream oil and gas industry through the MEMR and SKK Migas. PT Pertamina (Persero) (“Pertamina”) is the state oil and gas company. Pertamina is a state-owned enterprise and may hold PI in numerous PSCs as a Contractor of SKK Migas.
Are there any special requirements for or restrictions on participation in the upstream oil and gas industry by foreign oil and gas companies?
A foreign oil and gas company is permitted under the Oil and Gas Law to hold PI in a PSC as a permanent establishment. Foreign oil and gas companies can also establish foreign investment companies to engage in upstream oil and gas activities in Indonesia. Under the current negative list, which stipulates those business fields that are closed or restricted to foreign investment, upstream oil and gas activities in Indonesia are open to 100% foreign ownership.
What are the key features of the environmental and health and safety regime that applies to upstream oil and gas activities?
New-generation PSCs expressly oblige the PSC Contractor to, among other things, (i) implement occupational health, safety and environmental protection standards applicable in the oil and gas industry, take all reasonable and necessary precautions to prevent injury to or death of persons and damage to the environment and property, and comply with all applicable safety and environmental laws and regulations; (ii) conduct an environmental baseline assessment at the beginning of the PSC Contractor’s activities and thereafter fulfil all obligations pursuant to applicable legal requirements; (iii) take necessary precautions to protect ecological systems, navigation and fishing, and to prevent extensive pollution of the area, sea, rivers and others as the direct result of the petroleum activities; and (iv) carry out abandonment and site restoration (“ASR”) upon the abandonment of an oil and gas field or the relinquishment of any part of the contract area. The Oil and Gas Law also mandates post-operation obligations as a means of ensuring environmental management and protection, and GR 35 obligates Contractors to allocate funds for post-operation activities.
Under Law No. 32 of 2009 regarding Environmental Management and Protection (the “Environmental Law”), business actors must take steps to prevent environmental pollution and/or damage as a result of any business activity. To determine the existence of pollution, implementing regulations of the Environmental Law stipulate industry-specific quality standards for various environmental elements such as water, ambient air and emissions).
The Director General of Oil and Gas (“DGOG”), which is in the Ministry of Energy and Mineral Resources, is responsible for supervising the implementation of health, safety and environment (“HSE”) regulations in the oil and gas sector and imposing sanctions for non-compliance. The DGOG designates Mining Inspection Enforcement teams to examine work safety compliance at oil and gas businesses. If the facilities and techniques satisfy work health and safety standards, the DGOG will issue certifications for installations and equipment. Non-compliance with applicable HSE rules subjects the company to administrative sanctions up to the revocation of its licence.
How does the government derive value from oil and gas resources (royalties/production sharing/taxes)? Are there any special tax deductions or incentives offered?
Indonesia does not impose royalties on PSCs. In Cost Recovery PSCs, the State’s minimum income is secured through FTP. FTP is the first take of oil or gas immediately after production in a work area in one calendar year received by the State prior to cost recovery and profit calculation. The amount of FTP is determined in the relevant Cost Recovery PSC.
Taxes applicable to PSCs include income tax, VAT, import duties, regional taxes and other levies. The PSC can stipulate whether the tax laws and regulations applicable at the time the PSC is executed shall apply (stabilised) or whether the PSC will follow every tax law and regulation issued over time. In addition, Contractors are required to pay non-tax State revenues such as exploration and exploitation fees and bonuses, including signing bonus and production bonus.
Oil is typically split 85:15 and gas 70:30 between the Government and the Contractor under a Cost Recovery PSC. In a Gross Split PSC, the initial split between the Government and the Contractor is 57:43 for oil and 52:48 for gas.
Government Regulation No. 27 of 2017 (“GR 27”), which amends Government Regulation No. 79 of 2010 regarding Recoverable Operating Costs and Income Tax Treatment in the Upstream Oil and Gas Sector, provides for tax deductions during the exploration and exploitation phases. For Gross Split PSCs, Government Regulation No. 52 of 2017 (“GR 52”) eliminates taxes during exploration until the first year of production.
Are there any restrictions on export, local content obligations or domestic supply obligations?
Upon obtaining the requisite export approvals, a Contractor can export its production entitlement, subject to its Domestic Market Obligation (DMO), under which 25% of the Contractor’s production entitlement must be allocated for the domestic market.
Government Regulation No. 1 of 2019 regarding Export Proceeds from the Exploitation, Management and/or Processing of Natural Resources (“GR 1/2019”) requires foreign exchange proceeds deriving from the export of natural resources, including oil and gas, to be placed in the Indonesian financial system through a special account in an Indonesian foreign exchange bank, which must be licensed by the Financial Services Authority (Otoritas Jasa Keuangan or “OJK”). The Indonesian branch offices of overseas banks do not qualify as Indonesian foreign exchange banks. The placement of the export proceeds in a special account must be carried out no later than the end of the third month after the Registration of Export Declaration (Pemberitahuan Ekspor Barang). The funds in the special account can only be utilized by the PSC Contractor for certain payments, such as customs, loans, imports, profits/dividends and other purposes permitted by the Indonesian Investment Law (Law No. 25 of 2007 regarding Capital Investment). Such special accounts are eligible for a tax incentive in the form of the reduction of deposits tax (ranging from 0-10%), as opposed to the normal deposit tax of 20%.
To implement GR 1/2019, the Indonesian central bank, Bank Indonesia (“BI”), issued BI Regulation No. 21/3/PBI/2019 regarding Foreign Exchange Receipts from Exports from the Exploration, Management and/or Processing of Natural Resources, which revokes BI Regulation No. 16/10/PBI/2014, as amended by BI Regulation No. 17/23/PBI/2015 regarding the Receipt of Export Proceeds in Foreign Exchange and the Withdrawal of Offshore Loan Foreign Exchange.
PSC Contractors are required by law and contract to reserve 25% of their oil and gas production for the domestic market.
Does the regulatory regime include any specific decommissioning obligations?
New-generation PSCs stipulate an express obligation to carry out an ASR programme and to provide ASR funds. The Oil and Gas Law highlights post-operation obligations as a means of ensuring environmental management and protection, and GR 35 obligates Contractors to allocate funds for post-operation activities. MEMR Regulation No. 15 of 2018 regarding Post-Operation Activities in Upstream Oil and Gas Activities (“MEMR Reg. 15/2018”) and SKK Migas Guidelines No. 040 of 2018 (“PTK 040”) set forth the requirements and procedures to carry out ASR and ASR funds obligations.
More specific decommissioning obligations are contained in various regulations, such as MEMR Regulation No. 02P/1992, which requires land reclamation, and Government Regulation No. 17 of 1974 regarding Supervision of the Implementation of Offshore Oil and Gas Exploration, which requires the dismantlement of facilities that are no longer used. SKK Migas Guidelines issued in 2015 on work completion approval includes well-plugging as one of the items constituting the completion of drilling work.
What is the regulatory regime that applies to the construction and operation of offshore and onshore oil and gas pipelines?
Oil and gas pipelines may be constructed for upstream companies (by a service company) and operated by upstream companies as part of their production infrastructure or transportation activities, as an ancillary activity to their main activities under the PSC (but only after obtaining MEMR approval of the development plan). Oil and gas pipelines can also be constructed by downstream business entities that engage in and are licensed to carry out oil and gas transportation activities. We note that such license is not required if the gas transportation activities are ancillary to the downstream entity’s main processing, storage or trading activities.
MEMR Regulation No. 18 of 2018 regarding Safety Inspection of Installations and Equipment in Oil and Gas Business Activities (“MEMR Reg. 18/2018”) requires a PSC Contractor or a downstream business entity to ensure that the design, engineering, construction, operation, maintenance, testing, inspection and implementation of oil and gas installations and equipment, including pipelines, comply with applicable laws and regulations, technical standards acknowledged by the MEMR, and good engineering practices. It also requires inspections and operability approval for such installations and equipment.
What is the regulatory regime that applies to LNG liquefaction and LNG receiving terminals? Are there any such terminals in your jurisdiction?
Yes, there are LNG facilities, including liquefaction and receiving terminals, in Indonesia. LNG facilities may be operated by upstream players as an ancillary activity to their main activities under the PSC (with the approval of the MEMR), or by a downstream business entity that engages in and is licensed to carry out processing or trading activities. Other licenses that the downstream business entity may have to obtain from the central and regional governments include licences related to HSE and land.
What is the regulatory regime that applies to gas storage (not LNG)? Are there any gas storage facilities in your jurisdiction?
There are gas storage facilities in Indonesia. Gas storage is generally regulated under Government Regulation No. 36 of 2004 regarding Downstream Oil and Gas Business Activity (“GR 36”). Gas storage activities may be conducted by upstream players as an ancillary activity to their main activities under the PSC (with the approval of the MEMR), or by a downstream business entity that engages in and is licensed to carry out storage activities. We note that such license is not required if the gas storage activities are ancillary to the downstream entity’s main processing, transportation or trading activities. A company engaging in the gas storage business is obliged to offer facility sharing to a third party, as the technical and economic aspects allow. Facility sharing is specifically regulated under BPH Migas Regulation No. 6 of 2005, issued by the Downstream Oil and Gas Regulatory Agency (“BPH Migas”).
Is there a gas transmission and distribution system in your jurisdiction? How is gas distribution and transmission infrastructure owned and regulated? Is there a third party access regime?
The MEMR has established a transportation master plan that is relied upon by BPH Migas to, inter alia, determine transmission routes and distribution networks, tender Special Rights, determine tariffs in accordance with techno-economic principles, and organize access to such pipelines.
Is there a competitive and privatised downstream gas market or is gas supplied to end-customers by one or more incumbent/government-owned suppliers? Can customers choose their supplier?
The downstream gas market follows the allocation and utilization of natural gas stipulated by the MEMR. Please see our response to Question No. 17.
How is the downstream gas market regulated?
MEMR Regulation No. 6/2016 regarding Provisions and Procedures for Stipulating Natural Gas Allocation, Utilization and Price (“MEMR Reg. 6/2016”) stipulates the order of priority for natural gas allocation and utilization, namely to support the Government’s program to supply natural gas for transportation, households and small-scale customers, increase national oil and gas production, support the fertilizer industry and the natural gas-based industry, the provision of electricity, and to support industries that uses gas as fuel. MEMR Reg. 6/2016 also regulates the buyers for each of these allocations. PSC Contractors must apply to the MEMR through SKK Migas to receive a stipulation for the allocation and utilization of their natural gas. A prospective buyer can apply to the MEMR through the DGOG for the allocation and utilization of natural gas.
The MEMR can allocate gas for export if the domestic needs for gas have been fulfilled, if the local infrastructure is insufficient or if the domestic purchasing power is inadequate for the economics of a field.
Other than the allocation and utilization of natural gas as discussed in Question No. 16 above, PSC Contractors shall submit a gas price proposal to the MEMR through SKK Migas. The PSC Contractor shall also submit an application to the MEMR for the stipulation of gas price within three months prior to the expiration of the relevant gas sales agreement.
Have there been any significant recent changes in government policy and regulation in relation to the oil and gas industry?
In January 2019, the Government issued GR 1/2019, which requires foreign exchange proceeds deriving from the export of natural resources, including oil and gas, to be placed in the Indonesian financial system through a special account in an Indonesian foreign exchange bank no later than the end of the third month after the Registration of Export Declaration (Pemberitahuan Ekspor Barang). The funds in the special account can only be utilized by the PSC Contractor for certain payments, such as customs, loans, imports, profits/dividends and other purposes permitted by the Indonesian Investment Law. Please see our response to Question No. 10.
In November 2018, Supreme Court decision No. 69 P/HUM/2018 granted a request by the Pertamina United Workers Union Federation (Federasi Serikat Pekerja Pertamina Bersatu or “FSPPB”) related to the sequence of options for the management of oil and gas working areas with an expiring PSC as provided in MEMR Regulation No. 23 of 2018. The Supreme Court ruled that if the MEMR regulation prioritized the extension of a PSC by the PSC Contractor over a takeover of the working area by Pertamina, it would be in violation of, among others, Article 33 of the Indonesian Constitution and therefore have no legally binding force to the extent that it could be interpreted as giving any particular order of priority.
MEMR Reg. 3/2019 was enacted in April 2019 to amend MEMR Reg. 23/2018 and changed several provisions regarding the management of a working area with an expiring PSC. Those changes included a provision that if the future management of an expiring PSC is granted to Pertamina, Pertamina can partner with a private entity other than the Contractor of the underlying PSC but must maintain at least 51% PI in the renewed PSC. Another change is the provision that if the new PSC Contractor of a renewed PSC and the PSC Contractor of the expiring PSC cannot agree on provisions regarding funding or activities needed to be carried out before the renewed PSC becomes effective, the MEMR may step in and stipulate policies regarding such matters.
In August 2019, the MEMR issued Regulation No. 7 of 2019 regarding the Management and Utilization of Oil and Gas Data (“MEMR Reg. 7/2019”), revoking the previous regulation on the same subject matter enacted in 2006. MEMR Reg. 7/2019 contains more detailed provisions regarding the management and oil and gas data, including with respect to the management of the oil and gas data of an expiring PSC, the exchange of oil and gas data with an offshore party, and the destruction of oil and gas data.
What key challenges have been identified by the government and/or industry in relation to your jurisdiction’s oil and gas industry?
According to the Indonesia Energy Outlook 2019 published by the Secretariat-General of the National Energy Council, crude oil production in Indonesia declined from 346 million barrels (949 thousand bpd) in 2009 to 283 million barrels (778 thousand bpd) in 2018. The reasons for this decline include mature oil production wells and a limited number of new production wells. The Government has been encouraging exploration activities especially in eastern parts of Indonesia, where, according to the 2019 PwC Guide, there are 39 tertiary and pre-tertiary basins showing rich promise in hydrocarbon. Another Government initiative to attract investors to the oil and gas upstream sector is the tax deductions provided under GR 27 and GR 52, as discussed in Question No. 9 above.
Are there any policies or regulatory requirements relating to the oil and gas industry which reflect/implement the global trend towards the low-carbon energy transition?
In March 2017, Indonesian President Joko Widodo issued a National Energy Plan, through Presidential Regulation No. 2 of 2017 regarding National Energy General Plan. Through this regulation, the Government introduced a target to increase the share of renewable energy in the energy supply mix from 5% in 2015 to 23% by 2025 and 31% by 2050. Along with the targeted increase in the share of renewable energy, the share of oil is targeted to decrease from 46% in 2015 to 25% by 2025 and 20% by 2050. The share of gas, on the other hand, is targeted to be optimized proportionally due to the country’s large reserves. The share of gas in the energy supply mix is targeted to go from 23% in 2015 to 22% by 2025 and 24% by 2050. With the expected rise in renewable energy production, we expect a decrease in Indonesia’s dependence on oil, while a continued dependence on gas is expected in proportion to the country’s reserves.