1. Overview of Natural Gas Sector
1.1 A brief outline of your jurisdiction's natural gas sector, including a general description of: natural gas reserves; natural gas production including the extent to which production is associated or non-associated natural gas; import and export of natural gas, including liquefied natural gas ("LNG") liquefaction and export facilities, and/or receiving and re-gasification facilities ("LNG facilities"); natural gas pipeline transportation and distribution/transmission network; natural gas storage; and commodity sales and trading.
By the end of 2020, Indonesia's proven natural gas reserves recorded in the BP Statistical Review of World Energy 2021 ("BP 2021 Report") amounted to 44.2 trillion cubic feet ("Tcf"). According to the BP Statistical Review of World Energy 2022 ("BP 2022 Report"), gas production reached 59.3 million tonnes per annum, representing 64.2% of the total oil and gas production in Indonesia. Of the foregoing production, 14.6 billion m3 was exported as LNG and 7.5 billion m3 was exported through pipelines.
According to the PwC Oil and Gas Guide 2020 ("2020 PwC Guide"), Indonesia has the sixth-largest Coal Bed Methane reserves in the world at 453 Tcf. Shale gas reserves are estimated at 574 Tcf.
Indonesia's main areas for gas production are South Sumatra, East Kalimantan, the Natuna Sea, Sulawesi and West Papua.
In 2017, a number of upstream projects were declared strategic projects by the Government of Indonesia ("Government") in an effort to increase oil and gas production. These include Tangguh Train-3, the Chevron Indonesia Deepwater Development Project, the Jangkrik Field Development Project, and the development of the Jambaran-Tiung Biru block and Genting's Kasuri block.
According to the Special Task Force for Upstream Oil and Gas Business Activities ("SKK Migas") Bulletin in October 2020, SKK Migas targeted 12 projects to commence production in 2020. Despite the challenges faced during the COVID-19 pandemic, the following oil and gas projects were realised in 2020:
- the Buntal-5 field by Medco E&P Natuna Ltd;
- the MSTB field by EMP Malacca Strait;
- the EPF field by Excal Mahato;
- the Cantik field in the Belida Production Sharing Contract ("PSC") by Sele Raya Belida;
- the Randugunting field by PT Pertamina Hulu Energi and the PHE-12 Reactivation by Pertamina Hulu Energi West Madura Offshore;
- the Meliwis field in the Madura Offshore PSC by Ophir Indonesia Ltd and Grati Pressure Low by Ophir Indonesia Ltd;
- Bukit Tua Phase 3 by Petronas Carigali Ketapang II Ltd;
- the Betung Compressor, SKG-19 Musi Timur, Sembakung Power Plant and SP Bambu Besar by PT Pertamina EP;
- the Bukit Tua Phase 3 by Petronas Carigali Ketapang II Ltd; and
- the Peciko 8A field in the Mahakam PSC by Pertamina Hulu Mahakam.
In 2021, the Government opened tenders for the following six contract areas:
- South CPP (onshore Riau), through direct offering;
- Sumbagsel (onshore South Sumatra), through direct offering;
- Rangkas (onshore Banten and West Java), through direct offering;
- Liman (onshore and offshore East Java), through direct offering;
- Merangin III (onshore South Sumatra and Jambi), through regular bidding; and
- North Kangean (offshore East Java), through regular bidding.
LNG facilities in Indonesia include Bontang (East Kalimantan), Tangguh (West Papua), and Donggi Senoro (Sulawesi). In a 15-year road map published by the Directorate General of Oil and Gas ("DGOG") in April 2016, the Government forecasts a need for USD 24.8 billion in investment to enhance gas infrastructure.
A national gas transmission and distribution network has been developed by the Ministry of Energy and Mineral Resources ("MEMR"). Gas pipelines and storage facilities may be owned and operated by private companies, subject to the regulations of the MEMR and the Downstream Oil and Gas Regulatory Agency ("BPH Migas").
1.2 To what extent are your jurisdiction's energy requirements met using natural gas (including LNG)?
In 2021, natural gas satisfied roughly 20.09% of Indonesia's total energy requirements.
1.3 To what extent are your jurisdiction's natural gas requirements met through domestic natural gas production?
Currently, Indonesia's natural gas requirements are fully met by domestic production, particularly by the allocation of the domestic market obligation ("DMO") from every PSC Contractor. PSC Contractors are required by law and contract to reserve 25% of their oil and gas production for the domestic market. According to the BP 2022 Report, Indonesia produced 59.3 billion m3 natural gas in 2021, and consumed 37.1 billion m3 natural gas in 2021.
1.4 To what extent is your jurisdiction's natural gas production exported (pipeline or LNG)?
Nearly half of Indonesia's gas production is exported. According to the BP 2022 Report, LNG exports in 2021 reached 14.6 billion m3 to eight countries. The biggest customers include China, South Korea and Japan. During that same period, 7.5 billion m3 was exported by pipeline to Singapore and Malaysia.
2. Overview of Oil Sector
2.1 Please provide a brief outline of your jurisdiction's oil sector.
According to the BP 2021 Report, there were 2.4 billion barrels of proven oil reserves in Indonesia as of the end of 2020, putting Indonesia at number 22 among the world's oil producers. Oil production reaches 692,000 barrels of oil per day. This is a 6.8% decrease from the production rate in 2021. According to the 2021 SKK Migas Annual Report, Indonesia's oil and gas revenue has reached around USD 7 billion.
The 2021 SKK Migas Annual Report recorded that after terminating 13 PSCs in 2021, Indonesia had a total of 173 PSCs, comprising 60 PSCs in the exploration stage, 94 PSCs in the exploitation stage, and 19 Non-Conventional Hydrocarbon PSCs.
Most oil upstream activities are focused in western Indonesia, with the main areas for oil production being Sumatra, the Java Sea, East Kalimantan and the Natuna Sea. The Government has been encouraging exploration activities in eastern parts of Indonesia, where, according to the 2020 PwC Guide, 39 tertiary and pre-tertiary basins show rich promise in hydrocarbons.
Major companies are involved in oil exploration and exploitation in Indonesia, including BP Tangguh, ConocoPhillips, Medco, and Mobil Cepu Ltd.
In the downstream sector, there are nine oil refineries in the country with a combined installed capacity of 1.1 million barrels per day.
2.2 To what extent are your jurisdiction's energy requirements met using oil?
In 2021, oil satisfied roughly 28.82% of Indonesia's energy requirements.
2.3 To what extent are your jurisdiction's oil requirements met through domestic oil production?
According to the BP 2022 Report, Indonesia's oil consumption in 2021 reached 1.471 million barrels per day, 43% of which was met by domestic production.
2.4 To what extent is your jurisdiction's oil production exported?
According to the 2021 SKK Migas Annual Report, Indonesia exported around 43 million barrels of oil and condensate in 2021, with Thailand, Malaysia and Singapore as the top three countries to which Indonesia exported oil, at 18.649, 7.033 and 3.118 million barrels, respectively.
3. Development of Oil and Natural Gas
3.1 Outline broadly the legal/statutory and organisational framework for the exploration and production ("development") of oil and natural gas reserves including: principal legislation; in whom the State's mineral rights to oil and natural gas are vested; Government authority or authorities responsible for the regulation of oil and natural gas development; and current major initiatives or policies of the Government (if any) in relation to oil and natural gas development.
Indonesia's oil and gas sector is governed by Law No. 22 of 2001 regarding Oil and Natural Gas (November 22, 2001), as amended by Government Regulation in Lieu of Law No. 2 of 2022 (December 30, 2022) ("Job Creation Perppu") (collectively, the "Oil and Gas Law"). The State retains mineral rights throughout Indonesian territory and the Government holds the mining authority. We address the enactment of the Job Creation Perppu in more detail in question 14.2.
The oil and gas sector comprises upstream and downstream activities, which are regulated and organised separately. Upstream activities include exploration and exploitation and are regulated under Government Regulation No. 35 of 2004 regarding Upstream Oil and Natural Gas Business Activities, as amended most recently by Government Regulation No. 55 of 2009 ("GR 35"). The upstream sector is managed and supervised by SKK Migas.
Due to the unique territorial composition of the archipelagic State of Indonesia, upstream oil activities may be undertaken in onshore and offshore areas. Work areas for onshore and offshore operations are determined by the MEMR based on consultations with and recommendations from the respective regional governments.
Downstream activities encompass processing, transportation, storage and trading, and are regulated under Government Regulation No. 36 of 2004 regarding Downstream Oil and Natural Gas Business Activities, as amended by Government Regulation No. 30 of 2009 ("GR 36"). Downstream operations fall under the auspices of the MEMR and BPH Migas.
Through Government Regulation No. 79 of 2014 regarding National Energy Policy, the Government has stipulated national energy policy to be implemented from 2014 to 2050, focusing primarily on energy availability for national needs, prioritisation of energy development, utilisation of national energy resources, and national energy reserves. The target for the availability of primary energy, which includes natural oil and gas, is approximately 400 million tonnes of oil equivalent ("MTOE") in 2025 and approximately 1,000 MTOE in 2050.
The President of Indonesia, Mr. Joko Widodo, announced a list of national strategic projects through Presidential Regulation No. 3 of 2016 regarding the Acceleration of the Implementation of National Strategic Projects, as amended most recently by Presidential Regulation No. 109 of 2020. These national strategic projects include several downstream oil and gas projects, namely the development of the Bontang and Tuban refineries, upgrading existing refineries, and the construction of fuel oil and LPG tank storage in the eastern parts of Indonesia. A presidential decree and presidential instruction seek to accelerate these projects and mandate enhanced cooperation among relevant Government institutions for the achievement of these objectives.
3.2 How are the State's mineral rights to develop oil and natural gas reserves transferred to investors or companies ("participants") (e.g., licence, concession, service contract, contractual rights under Production Sharing Agreement?) and what is the legal status of those rights or interests under domestic law?
Private companies earn the right to explore and exploit oil and gas resources by entering into cooperation contracts (PSCs), mainly based upon a production sharing scheme, with the Government (through SKK Migas) and thus acting as a Contractor to SKK Migas. An entity can hold only one PSC, and a PSC is normally granted for 30 years, typically comprising six plus four years of exploration and 20 years of exploitation.
In the traditional production sharing scheme that has been used in Indonesia, the production output is typically subject to a first tranche petroleum ("FTP") requirement, cost recovery and certain taxes, and the remaining portion is distributed among the Contractor and the Government in the proportions set out in the PSC ("Cost Recovery PSC"). All financial risks of 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. In early 2017, the Government, through MEMR Regulation No. 8 of 2017 regarding Gross Split PSC, as amended most recently by MEMR Regulation No. 12 of 2020 ("MEMR Reg. 12/2020") (collectively, "MEMR Reg. 8/2017"), introduced the Gross Split production sharing scheme, in which the production output is split at gross (without FTP, cost recovery or tax deductions) in a sharing proportion stipulated at the beginning of a field development and subject to fluctuation depending on certain variables and progressive components ("Gross Split PSC"). Under MEMR Reg. 12/2020, existing PSCs shall be valid until their expiry and may be converted to Gross Split PSCs. For expiring PSCs, the MEMR will determine whether to adopt either a Gross Split PSC, a Cost Recovery PSC, or another form of cooperation contract, regardless of whether the expiring PSC is extended. The MEMR shall also determine the form of new PSCs based on the level of risk, investment climate and maximum benefit for the State.
The Job Creation Perppu requires business actors in the upstream sector to obtain at least a Business Identification Number (Nomor Induk Berusaha or "NIB") and a Business Licence from the central government before conducting business activities. Government Regulation No. 5 of 2021 regarding the Implementation of Risk-Based Business Licensing ("GR 5/2021") clarifies that the Business Licence for upstream oil and gas activities is in the form of a PSC and NIB.
3.3 If different authorisations are issued in respect of different stages of development (e.g., exploration appraisal or production arrangements), please specify those authorisations and briefly summarise the most important (standard) terms (such as term/duration, scope of rights, expenditure obligations).
In both Cost Recovery PSC and Gross Split PSC contexts, when a commercial discovery is made, the Contractor must prepare a Plan of Development ("POD") for the relevant field. The first POD is approved by the MEMR based on the considerations of SKK Migas and begins the exploitation stage. Subsequent PODs are approved by SKK Migas.
Other authorisations differ in each PSC model.
For a Cost Recovery PSC, expenditures throughout the PSC term are planned ahead by the Contractor in an annual Work Plan and Budget ("WP&B") to be approved by SKK Migas. A Contractor must also prepare an Authorisation for Expenditure ("AFE") for specific work and can only execute the work upon SKK Migas' approval of the relevant AFE.
For a Gross Split PSC, as there is no cost recovery mechanism, SKK Migas only approves the annual work plan. The budget is only presented to SKK Migas for its consideration in approving the annual work plan but is not subject to SKK Migas' approval. SKK Migas has the authority to adjust the production split for each field by considering the progressive components stipulated in MEMR Reg. 8/2017.
3.4 To what extent, if any, does the State have an ownership interest, or seek to participate, in the development of oil and natural gas reserves (whether as a matter of law or policy)?
Extracted oil and gas remains owned by the State until it passes the point of export or other delivery point. Thereafter, the Government is entitled to a certain percentage of the production output as apportioned under the PSC, as is the Contractor.
Under the Oil and Gas Law, entities in the form of a State-owned enterprise ("SOE"), regional-owned enterprise ("BUMD"), cooperative, small business, or private business entity may enter into a PSC with SKK Migas to undertake upstream oil and gas business activities. Pertamina, as an SOE and the State oil company, can hold participating interests ("PI") in numerous PSCs as a Contractor of SKK Migas. There is no maximum limit on the PI that an SOE, BUMD, or Pertamina may hold.
Upon the first POD approval, a Contractor is required to offer 10% PI in its PSC to a BUMD that (i) is a regional entity wholly owned by the regional government, (ii) is owned at least 99% by the regional government and the remaining by a regional government-affiliated entity, (iii) is established pursuant to a regional government regulation, and (iv) does not conduct any business activity other than the management of such offered PI. The BUMD may accept or decline the offer based on its financial capability, and in the latter event the offer must be tendered to an SOE.
In addition, MEMR Regulation No. 23 of 2021 regarding the Management of Oil and Gas Working Areas for which the PSC will Expire ("MEMR Reg. 23/2021") stipulates that Pertamina may elect to resume the operations of a work area whose PSC is expiring, irrespective of whether the initial Contractor has applied for an extension. If both Pertamina and the initial Contractor express a willingness to operate a work area, the MEMR has the authority to decide whether the operation will be resumed by Pertamina, the initial Contractor, or jointly between the two.
3.5 How does the State derive value from oil and natural gas development (e.g., royalty, share of production, taxes)?
Indonesia does not impose royalties on PSCs but secures the State's minimum income through the FTP mechanism in Cost Recovery PSCs. FTP is the first take of oil or gas immediately after production in a work area in one calendar year that is received by the State prior to cost recovery and profit calculation. FTP therefore secures the State's minimum income. The amount of FTP is determined in the relevant Cost Recovery PSC.
Taxes applicable to PSCs include income tax, value-added tax ("VAT"), import duties, regional taxes and other levies. The PSC may stipulate whether the tax laws and regulations applicable at the time of the PSC execution shall apply (stabilised) or whether the PSC shall 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 a signing bonus and production bonus.
The sharing ratio between the Government and the Contractor for a Cost Recovery PSC is typically 85:15 for oil and 70:30 for gas. For a Gross Split PSC, the initial sharing ratio between the Government and the Contractor is 57:43 for oil and 52:48 for gas.
3.6 Are there any restrictions on the export of production?
Subject to obtaining requisite export approvals, a Contractor is entitled to export its production entitlement, subject to its DMO by which 25% of the Contractor's entitlement must be allocated for the domestic market.
3.7 Are there any currency exchange restrictions, or restrictions on the transfer of funds derived from production out of the jurisdiction?
The Indonesian Currency Law and Bank Indonesia ("BI") Regulation No. 17/3/PBI/2015 regarding the Mandatory Use of Rupiah restrict most transactions within Indonesian territory from being carried out using foreign currency. Core upstream activities in Indonesia are exempted from this requirement for a certain period of time, such as expenditures in relation to the Firm Commitment, over/under lifting, and domestic oil and gas sales transactions by upstream players, which are exempted for 10 years as of February 23, 2016.
Minister of Trade ("MOT") Regulation No. 94 of 2018, as amended by MOT Regulation No. 102 of 2018 regarding Provisions on the Use of a Letter of Credit for the Export of Certain Goods, exempts the export of oil and gas products to be paid through a Letter of Credit ("L/C"). Payment using an L/C was previously required under MOT Regulation No. 94 of 2018.
In January 2019, the Government issued Government Regulation No. 1 of 2019 regarding Export Proceeds from the Exploitation, Management, and/or Processing of Natural Resources ("GR 1/2019"). This regulation 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"). 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 utilised by the PSC Contractor for certain payments, such as customs, loans, imports, profits/dividends and other purposes permitted by Law No. 25 of 2007 regarding Capital Investment, as amended by the Job Creation Perppu ("Investment Law"). Such special accounts are eligible for a tax incentive in the form of the reduction of deposit tax (ranging from 0-10%), as opposed to the normal deposit tax of 20%.
In order to implement GR 1/2019, 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, as most recently amended by BI Regulation No. 22/21/PBI/2020.
3.8 What restrictions (if any) apply to the transfer or disposal of oil and natural gas development rights or interests?
During the first three years of the exploration period (the "Firm Commitment" period), a Contractor is not permitted to (i) transfer the majority of its PI to a non-affiliated party, or (ii) transfer a certain percentage of its PI that would result in the PI transferee holding a higher percentage of PI than any other initial Contractors. Change of operatorship in a PSC during the Firm Commitment is also prohibited. After such period, transfer of PI may be conducted upon the approval of the MEMR based on the consideration of SKK Migas.
A PSC typically provides an approval or notification requirement for the transfer of all or a portion of the Contractor's PI to an affiliate or non-affiliated third party. From 2008 onward, PSCs have stipulated that transfers of PI to affiliates and changes of control in a party to a PSC require the prior written consent of the MEMR (through SKK Migas). Similarly, MEMR Regulation No. 48 of 2017, as last amended by MEMR Regulation No. 16 of 2021 ("MEMR Reg. 48/2017"), and SKK Migas Working Guidelines ("PTK") No. 057 of 2018 Rev.1 regarding the Administration of Cooperation Contracts, stipulate that a transfer of PI in a PSC requires the prior approval of the MEMR (through SKK Migas).
GR 35 also imposes a requirement that if all or a portion of the rights of the Contractor are transferred to a non-affiliate or to another company that is not a partner in the same working area, the MEMR can "request" that the Contractor offer the interest to a national company.
Pursuant to MEMR Reg. 48/2017, the indirect transfer of PI through the transfer of shares of the Contractor requires MEMR approval based on the consideration of SKK Migas if the transfer pertains to majority shares, thus resulting in a direct change of control of the Contractor. If the transfer of shares results in an indirect change of control of the Contractor, the transfer must only be reported to the MEMR through SKK Migas.
In addition, the direct and indirect transfer of PI, as well as a change of control, is subject to taxes imposed by Government Regulation No. 79 of 2010, as amended by Government Regulation No. 27 of 2017, as partially revoked by Government Regulation No. 93 of 2021 regarding Income Tax Treatment on the Transfer of Participating Interest in Upstream Oil and Gas Business Activities (as amended, "GR 79/2010"), and Minister of Finance Regulation No. 257/PMK.011/2011.
3.9 Are participants obliged to provide any security or guarantees in relation to oil and natural gas development?
A Contractor must provide a performance bond by the time of execution of the PSC, the amount of which depends on the type of contract area. The performance bond for open areas, a portion of the contract area that is carved out based on the PSC and areas for which the PSC has expired, is 10% of the total Firm Commitment value, with a minimum sum of USD 1.5 million. Areas that have never been developed or are being or have been produced are subject to a performance bond in an amount equivalent to 10% of the WP&B for the first two years of the exploration period, with a minimum sum of USD 1 million.
Further, a parental guarantee may be required by SKK Migas for a company intending to acquire PI in a PSC, subject to SKK Migas' assessment of the company's audited financial statements.
3.10 Can rights to develop oil and natural gas reserves granted to a participant be pledged for security, or booked for accounting purposes under domestic law?
PI in a PSC cannot be pledged as security. This is primarily because a PI transfer can only be conducted with the approval of the Government, and there is no guarantee that the Government will approve the transfer of PI to the pledgee if execution occurs.
3.11 In addition to those rights/authorisations required to explore for and produce oil and natural gas, what other principal Government authorisations are required to develop oil and natural gas reserves (e.g., environmental, occupational health and safety) and from whom are these authorisations to be obtained?
In conducting petroleum activities, PSC Contractors are required to comply with the provisions of occupational health and safety, environmental management and community development regulations. In the exploration phase, PSC Contractors must complete an environmental monitoring and environmental management ("UKL/UPL") report. During the exploitation of a proposed development, PSC Contractors must further conduct an environmental assessment ("AMDAL"), which is subject to the relevant Government authority's approval. PSC Contractors are also required to make periodic reports to the relevant Government authorities regarding their compliance with the UKL/UPL or AMDAL. In addition, Government Regulation No. 22 of 2021 regarding Environmental Protection and Management Implementation ("GR 22/2021") requires PSC Contractors to obtain Environmental Approval from the Ministry of Environment and Forestry ("MOEF") for any business and/or activity that has a significant or an insignificant environmental impact.
The DGOG 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 in oil and gas businesses. If the facilities and techniques satisfy work health and safety standards, the DGOG shall issue certifications for installations and equipment. Non-compliance with applicable HSE rules subjects the company to administrative sanctions up to revocation of the licence.
3.12 Is there any legislation or framework relating to the abandonment or decommissioning of physical structures used in oil and natural gas development? If so, what are the principal features/requirements of the legislation?
New-generation PSCs stipulate an express obligation to carry out an abandonment and site restoration ("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 Reg. 23/2021 also stipulates that outstanding post-operation obligations of a PSC nearing expiry are to be carried out by the entity that has been appointed by the MEMR to resume the PSC, which could be PT Pertamina (Persero) and/or another Contractor.
MEMR Regulation No. 15 of 2018 regarding Post-Operation Upstream Oil and Gas Business Activities ("MEMR Reg. 15/2018") requires PSC Contractors to conduct post-operation activities by using post-operation activity funds. A post-operation activity plan is required to be prepared and submitted to SKK Migas through the submission of a WP&B (if the PSC is in the exploration stage) or as part of the field development plan (if the PSC is in the exploitation stage). Prior to implementing post-operation activities, PSC Contractors are also required to obtain approval of the post-operation activity plan from the DGOG. PSCs that do not contain provisions regarding post-operation obligations are subject to MEMR Reg. 15/2018. The procedures to reserve and deposit ASR funds are also set forth in SKK Migas PTK No. 040 of 2018.
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. A PTK in 2015 on Work Completion Approval also lists well plugging as one of the items constituting completion of drilling work.
3.13 Is there any legislation or framework relating to gas storage? If so, what are the principal features/requirements of the legislation?
Gas storage is generally regulated under the Oil and Gas Law and specifically in GR 36 as a downstream activity. Based on the Job Creation Perppu's amendment of the Oil and Gas Law, gas storage activities may be conducted upon obtaining a downstream Business Licence from the central government. Such licence may also be used for other downstream oil and gas activities (e.g., transportation, processing and trading) (please see question 10.1 below). A company engaging in the gas storage business is obligated to offer facility sharing to a third party by considering the technical and economic aspects. Facility sharing is specifically regulated under BPH Migas Regulation No. 6 of 2005.
3.14 Are there any laws or regulations that deal specifically with the exploration and production of unconventional oil and gas resources? If so, what are their key features?
The general provisions on the exploration and production of unconventional oil and gas resources are subject to the Oil and Gas Law and its implementing regulations. Unconventional oil and gas resources are regulated under MEMR Regulation No. 35 of 2021 regarding Procedures on the Stipulation and Offering of Oil and Gas Working Area, which sets forth provisions on the offering of the unconventional working area through a direct offer or regular tender.
3.15 What has been the impact, if any, of the "energy transition" on the oil and gas industry in your jurisdiction, and are there any policies or laws/regulations that require the oil and gas industry to decarbonise? Are there any policies or laws/regulations relating to the development of low-carbon hydrogen and its use in conjunction with or in place of natural gas, or the development of carbon capture and storage?
In March 2017, the President issued a National Energy Plan, through Presidential Regulation No. 22 of 2017 regarding the 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 of 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 optimised proportionally due to the country's large reserves. The share of gas in the energy supply mix is targeted to move 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 and a continued dependence on gas in proportion to the country's reserves.
Currently, there are no policies or laws/regulations that specifically require the oil and gas industry to decarbonise. Existing carbon capture and storage regulations mostly encapsulate forestry business activities. However, the MEMR indicated in 2021 that the Government is drafting a regulation for carbon capture and storage (<a href="https://migas.esdm.go.id/post/read/pemerintah-susun-regulasi-ccus">https...).
Generally, Law No. 7 of 2021 regarding Harmonization of Taxation ("Taxation Harmonization Law") provides that entities that conduct carbon emission balancing or carbon trading may qualify for a reduction of the carbon tax. We also note that the Government increases tax imposition, particularly VAT, in the Taxation Harmonization Law, which will impact future carbon credit transactions arising from carbon capture or storage business activities.
4. Import / Export of Natural Gas (including LNG)
4.1 Outline any regulatory requirements, or specific terms, limitations or rules applying in respect of cross-border sales or deliveries of natural gas (including LNG).
Cross-border sales of natural gas can only be conducted if (i) the domestic need for natural gas has been fulfilled, (ii) there is insufficient domestic infrastructure, or (iii) domestic purchasing power is insufficient to satisfy the relevant gas field's economics. Pursuant to MEMR Regulation No. 6 of 2016 regarding Provisions and Procedures for Stipulating the Allocation and Utilization as well as Pricing of Natural Gas ("MEMR Reg. 6/2016"), the allocation of natural gas production is prioritised: (i) for the Government's programme to provide natural gas for transportation, households and small-scale customers; (ii) to increase national oil and gas production; (iii) for the fertiliser industry; (iv) for industries that use natural gas as a raw material; (v) for the provision of power; and (vi) for industries that use natural gas as fuel. Cross-border deliveries of natural gas are subject to import or export approvals from the MOT, which takes into account the import or export recommendation from the DGOG. The DGOG considers domestic supply and demand in issuing such recommendation. Regarding imports in general, an additional licence is required in the form of an NIB, in accordance with GR 5/2021. The NIB acts as an import licence issued by the Online Single Submission ("OSS") system implemented under the auspices of the Indonesian Capital Investment Coordinating Board ("BKPM"). Although the import of natural gas is not specifically subject to an NIB pursuant to GR 5/2021, in practice, entities importing natural gas are required to obtain an NIB. In addition, Article 42 (1) (k) of GR 5/2021 requires an export recommendation from the MEMR for the export of oil and gas resulting from upstream oil and gas business activities.
5. Import / Export of Oil
5.1 Outline any regulatory requirements, or specific terms, limitations or rules applying in respect of cross-border sales or deliveries of oil and oil products.
Cross-border sales of oil are subject to fulfilment of the DMO (for upstream players). With regard to crude oil, the MEMR issued Regulation No. 18 of 2021 regarding the Priority to Use Crude Oil for Meeting Domestic Needs. This regulation requires Pertamina and/or holders of the crude oil processing licence to prioritise the utilisation of crude oil from domestic PSC Contractors before considering importation, and prioritises the domestic sale of PSC Contractors' crude oil portion. No later than three months before commencing the export recommendation period for the entire Contractor's portion of crude oil, PSC Contractors or their affiliates are required to offer their portion to Pertamina and/or holders of the crude oil processing licence through a negotiation process using a business-to-business scheme. From the negotiation process, Pertamina may directly appoint a PSC Contractor for the purchase of the crude oil, which may be made in the form of a long-term contract with a period of 12 months. However, it is not yet clear exactly how this regulation will be implemented in practice.
As discussed in question 4.1 above, cross-border deliveries of oil are subject to import or export approvals from the MOT, which takes into account the import or export recommendation of the DGOG. The DGOG considers domestic supply and demand in issuing such recommendation. Specifically in regard to the import of oil, there is an additional licence in the form of an NIB issued by the OSS system administered by the BKPM.
6.1 Outline broadly the ownership, organisational and regulatory framework in relation to transportation pipelines and associated infrastructure (such as natural gas processing and storage facilities).
Gas transportation by pipeline is regulated under GR 36 and MEMR Regulation No. 4 of 2018 regarding the Business of Gas in Downstream Oil and Gas Business Activities, as amended by MEMR Regulation No. 19 of 2021, and is controlled by BPH Migas. It can only be carried out by a business entity established in Indonesia that has obtained a downstream Business Licence from the central government (please see question 10.1 below).
The MEMR, as mandated by the Oil and Gas Law, has established a transportation master plan. This master plan is relied upon by BPH Migas to, inter alia, determine transmission routes and distribution networks, tender Special Rights, and determine tariffs in accordance with techno-economic principles.
6.2 What governmental authorisations (including any applicable environmental authorisations) are required to construct and operate oil and natural gas transportation pipelines and associated infrastructure?
In addition to a gas transportation licence from the BKPM c.q. DGOG, a business entity must also obtain Special Rights from the MEMR to transport gas by pipeline within the stipulated transmission and distribution routes by way of tender. An Environmental Approval must also be obtained by preparing the relevant environmental document, which can be an AMDAL or a UKL/UPL, depending on the length and pressure of the pipelines.
6.3 In general, how does an entity obtain the necessary land (or other) rights to construct oil and natural gas transportation pipelines or associated infrastructure? Do Government authorities have any powers of compulsory acquisition to facilitate land access?
Generally speaking, land rights will be obtained by negotiating with owners and occupiers, in accordance with prevailing laws. To the extent that these facilities are used for upstream activities within the framework of a cooperation contract, the Contractor must comply with the Oil and Gas Law, GR 35 and the relevant implementing regulations to be issued thereunder. Contractors are responsible for the payment of these rights. Land that is purchased for a facility will become the property of the State, while land that is leased for a facility will be leased in the name of the Contractor.
Title to land purchased for facilities used for downstream activities outside of a cooperation contract may be held in the name of the business entity engaging in the transportation or storage activity.
Projects that serve the public interest may enjoy more Government involvement in the land procurement process, as stipulated in Government Regulation No. 19 of 2021 regarding Implementation of Land Procurement for Public-Interest Developments. The President has also issued Presidential Regulation No. 3 of 2016 regarding Acceleration of Implementation of National Strategic Projects, as amended most recently by Presidential Regulation No. 109 of 2020, as an instruction to enhance cooperation among governmental entities in facilitating the preparation and operation of national strategic projects.
6.4 How is access to oil and natural gas transportation pipelines and associated infrastructure organised?
Access to oil and natural gas transportation pipelines and associated infrastructure is organised by BPH Migas by relying on the transportation master plan stipulated by the MEMR.
6.5 To what degree are oil and natural gas transportation pipelines integrated or interconnected, and how is co-operation between different transportation systems established and regulated?
The MEMR periodically stipulates a transportation master plan for natural gas that is relied upon by BPH Migas in controlling and supervising the implementation of gas transportation activities by business entities, including determining the joint use of transportation and storage facilities as well as associated infrastructure.
6.6 Outline any third-party access regime/rights in respect of oil and natural gas transportation and associated infrastructure. For example, can the regulator or a new customer wishing to transport oil or natural gas compel or require the operator/owner of an oil or natural gas transportation pipeline or associated infrastructure to grant capacity or expand its facilities in order to accommodate the new customer? If so, how are the costs (including costs of interconnection, capacity reservation or facility expansions) allocated?
A pipeline or storage facility operator cannot be required to expand its facilities to accommodate new customers. Facility sharing is obligated by GR 36 only to the extent that the relevant facility has sufficient capacity so that the facility sharing will not impair the operations of the facility owner. Facility sharing is also subject to economic considerations, such as the facility owner's investment return rate. BPH Migas is the authority that oversees and regulates facility sharing.
6.7 Are parties free to agree the terms upon which oil or natural gas is to be transported or are the terms (including costs/tariffs which may be charged) regulated?
In general, and subject to the BPH Migas' authority to set tariffs for the transportation of natural gas through pipelines, parties may agree on the terms of the agreement for the transportation and storage of natural gas. A "contractual regime" is in its early stages of evolution.
BPH Migas has the authority to determine and supervise the tariffs for natural gas transportation through pipelines that will be charged by the operator of the pipeline to users. The relevant operator must submit the proposed tariff to BPH Migas, which will then verify and evaluate the proposed tariff. BPH Migas will discuss with the related pipeline operator and users before determining the tariff.
For the transportation of natural gas, the applicable regulation provides that the agreement between a gas pipeline operator and user must be set forth in a gas transportation agreement. The regulation also requires the operator of the gas pipeline to prepare an access arrangement outlining the terms and conditions for the joint use of the pipelines owned by the operator. This, as well as the tariff, must be approved by BPH Migas. The access arrangement will include management guidelines and technical and legal rules. The gas transportation agreement must be in accordance with the access arrangement.
Crude oil transportation is not subject to the Government's approval, whereas fuel oil is relatively more heavily regulated in terms of distribution, pricing and availability.
7. Gas Transmission / Distribution
7.1 Outline broadly the ownership, organisational and regulatory framework in relation to the natural gas transmission/distribution network.
Please refer to question 6.1 above.
7.2 What governmental authorisations (including any applicable environmental authorisations) are required to operate a distribution network?
Please refer to question 6.2 above.
7.3 How is access to the natural gas distribution network organised?
Please refer to question 6.4 above.
7.4 Can the regulator require a distributor to grant capacity or expand its system in order to accommodate new customers?
No; this requirement only applies to gas transportation and processing activities.
7.5 What fees are charged for accessing the distribution network, and are these fees regulated?
Under Government Regulation No. 48/2019, the monthly fees charged for accessing the gas distribution network are 2.5% or 1.5% of the transmission tariff per 1,000 standard cubic feet for up to 100 billion standard cubic feet or above 100 billion standard cubic feet, respectively.
7.6 Are there any restrictions or limitations in relation to acquiring an interest in a gas utility, or the transfer of assets forming part of the distribution network (whether directly or indirectly)?
Direct acquisitions of an interest in a gas utility or the transfer of assets forming part of the distribution network will require the revocation of the existing Special Right and issuance of a new Special Right to the acquirer. Indirect acquisitions or transfers of assets (by way of share transfers) may be subject to foreign share ownership restrictions regulated under Presidential Regulation No. 10 of 2021 regarding Investment Business Activities, as amended by Presidential Regulation No. 49 of 2021 ("Investment List") (please see question 12.1 below).
8. Natural Gas Trading
8.1 Outline broadly the ownership, organisational and regulatory framework in relation to natural gas trading. Please include details of current major initiatives or policies of the Government or regulator (if any) relating to natural gas trading.
Natural gas trading is governed generally under the Oil and Gas Law and specifically in GR 36. Based on the Job Creation Perppu's amendment of the Oil and Gas Law, it must be conducted by a business entity established in Indonesia by obtaining a downstream Business Licence from the central government (please see question 10.1 below).
Natural gas trading must adhere to the provisions of priority businesses as well as the price stipulation under MEMR Reg. 6/2016.
8.2 What range of natural gas commodities can be traded? For example, can only "bundled" products (i.e., the natural gas commodity and the distribution thereof) be traded?
This will depend on how BPH Migas regulates distribution and trading activities and whether the Government will issue multiple downstream Business Licences for a given area. Bundling several products is possible since one entity may hold a single downstream Business Licence (please see question 10.1 below).
9. Liquefied Natural Gas
9.1 Outline broadly the ownership, organisational and regulatory framework in relation to LNG facilities.
LNG facilities may be operated by upstream players as an ancillary activity to their main activities under the PSC, or by a downstream business entity that engages in processing or trading activities.
9.2 What governmental authorisations are required to construct and operate LNG facilities?
Prior POD approval from the MEMR is required for the operation of LNG facilities at the upstream level. At the downstream level, the construction and operation of LNG facilities requires a processing or wholesale trading licence from the MEMR. However, as the Job Creation Perppu has integrated the Business Licence for all downstream business activities, a single downstream Business Licence should be sufficient (please see question 10.1 below). In both the upstream and downstream sectors, it may be necessary to obtain other relevant licences from the central government and regional government, such as licences related to HSE and land.
9.3 Is there any regulation of the price or terms of service in the LNG sector?
Gas pricing is stipulated by considering the economics of fields, domestic and international gas prices, and added value from the domestic utilisation of natural gas. The stipulation of gas prices for domestic needs must also consider the purchasing power of domestic consumers as well as support for the Government's programme to provide natural gas for transportation, households, and small-scale customers.
9.4 Outline any third-party access regime/rights in respect of LNG facilities.
Please refer to question 6.6 above.
10. Downstream Oil
10.1 Outline broadly the regulatory framework in relation to the downstream oil sector.
Downstream oil activities are regulated generally by the Oil and Gas Law and GR 36 specifically. This encompasses oil processing, storage, transportation, and trading. The Job Creation Perppu removes the multiple business licensing requirement for downstream oil and gas business activities (processing, transportation, storage and/or trading) under the Oil and Gas Law. Rather, it designates a single integrated Business Licence that is applicable for all the foregoing business activities. This Business Licence will be processed through an online system managed by the central government. The Job Creation Perppu also contains a general transition provision stipulating that Business Licences and/or sectoral licences issued prior to the issuance of the Job Creation Perppu will remain in force until the expiration of the licence, while Business Licences that are in the application process shall be adjusted to conform with the provisions of the Job Creation Perppu. The Job Creation Perppu also amends/adds to the sanctions in the Oil and Gas Law for engaging in downstream oil and gas business activities without a Business Licence, violating a Business Licence and/or the Oil and Gas Law, and abusing the transportation and/or trading of gas fuel and/or liquefied petroleum gas.
Only business entities established in Indonesia are eligible to obtain a downstream Business Licence, subject to the applicable foreign shareholding restriction stipulated in the Investment List. The Investment List is Indonesia's new investment list of business lines that are open or closed for foreign investment.
10.2 Outline broadly the ownership, organisation and regulatory framework in relation to oil trading.
Depending on the oil commodities being traded, oil trading activities fall under the auspices of the MEMR or BPH Migas. In addition to the downstream licence from the BKPM c.q. DGOG, the trading of oil fuel can only be conducted after registering the specific type of oil fuel with BPH Migas and obtaining an NIB from BPH Migas. Oil trading is classified into wholesale trading and limited trading, depending on the scale of business and ownership of facilities.
11.1 Which governmental authority or authorities are responsible for the regulation of competition aspects, or anti-competitive practices, in the oil and natural gas sector?
While BPH Migas can impose penalties on business entities engaged in the natural gas sector, the Commission for the Supervision of Business Competition ("KPPU") is responsible for implementing Law No. 5 of 1999 regarding Prohibition on Monopolistic Practices and Unfair Business Competition, as amended by the Job Creation Perppu ("Anti-Monopoly Law"). The KPPU may issue decisions that certain agreements, conduct or positions in the relevant market (including the natural gas market) are anti-competitive and therefore in violation of the Anti-Monopoly Law.
11.2 To what criteria does the regulator have regard in determining whether conduct is anti-competitive?
The provisions and criteria on anti-competitive conduct are regulated under the Anti-Monopoly Law.
The prohibitions can be categorised as follows: prohibited agreements; prohibited conduct; and abuse of a dominant position in a given market sector.
11.3 What power or authority does the regulator have to preclude or take action in relation to anti-competitive practices?
The KPPU is not necessarily authorised to preclude anti-competitive practices. However, should the KPPU deem certain agreements, conduct, or positions in the relevant market (including the oil and gas market) to be in violation of the Anti-Monopoly Law, it may lawfully issue decisions and sanctions. The KPPU also has the authority to provide advice, on request, regarding a planned merger, consolidation or acquisition of companies. This advice does not constitute the KPPU's approval or rejection of the planned restructuring scheme and does not preclude the KPPU from performing an assessment of the merger, consolidation or acquisition after the same is effectuated.
11.4 Does the regulator (or any other Government authority) have the power to approve/disapprove mergers or other changes in control over businesses in the oil and natural gas sector, or proposed acquisitions of development assets, transportation or associated infrastructure or distribution assets? If so, what criteria and procedures are applied? How long does it typically take to obtain a decision approving or disapproving the transaction?
The MEMR has the authority to approve a transfer of shares of a Contractor that will result in a direct change of control of the Contractor, although the MEMR's consideration in granting its approval is not focused on competition issues. The MEMR's approval or rejection of the transfer of shares shall be issued within 28 working days as of SKK Migas' receipt of the correct and complete application. However, in practice, the approval process can