Contributed By King & Spalding LLP
The Constitution of Indonesia provides that all natural resources, which includes petroleum, contained within the Indonesian territory are national assets under the control of the state of Indonesia (the state). Law No 22/2001 regarding Oil and Gas (Law No 22/2001) governs the exploitation of petroleum resources in Indonesia and grants the government of Indonesia (GOI) the right to mine such resources. On behalf of the GOI, the Ministry of Energy and Mineral Resources (MEMR) sets policies, and manages and supervises the industry.
The petroleum sector in Indonesia is segregated into upstream and downstream activities.
Upstream activities include exploration and exploitation, and are regulated by the Special Task Force for Upstream Oil and Natural Gas Business Activities (SKK Migas), which was established under Presidential Regulation No 9/2013. SKK Migas replaced Badan Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi (BPMIGAS) as regulator after Indonesia’s Constitutional Court (Mahkamah Konstitusi) ruled, on 13 November 2012, that the status of BPMIGAS as an upstream petroleum regulator was unconstitutional. The Constitutional Court, however, declared that all existing co-operation contracts (described in 1.4 Principal Petroleum Law(s) and Regulations) entered into by BPMIGAS would remain in full force and effect until their specified expiry dates. BPMIGAS was established pursuant to Government Regulation No 42/2002 and took over Pertamina’s responsibilities as regulator of the oil and gas sector in Indonesia.
Downstream activities include processing, transportation, storage and trading, and are regulated by the Regulatory Body for Downstream Oil and Natural Gas Business Activities (BPH Migas), which was established pursuant to Government Regulation No 67/2002 and Presidential Decree No 86/2002.
Both SKK Migas and BPH Migas fall within the auspices of the MEMR.
Indonesia’s state-owned oil and gas company is PT Pertamina (Persero) (Pertamina), which was established in its current form on 9 October 2003. Previously, Pertamina acted as both a national oil company and as a regulator, with exclusive control over petroleum activities in Indonesia. Pertamina’s role as a regulator was terminated by Law No 22/2001, when the authority over petroleum activities was transferred back to the GOI.
Pertamina is active in the upstream and downstream sectors of the Indonesian petroleum industry. In its upstream business activities, Pertamina acts as a contractor to SKK Migas (as do foreign investors). Pertamina is rated as Baa2 (Stable) by Moody's and BBB by S&P and Fitch respectively.
Pertamina’s downstream activities cover processing, marketing, trading and shipping. Pertamina’s processing plants produce a multitude of commodities, such as fuel, kerosene, LPG, LNG and petrochemicals. Pertamina is the second-largest crude oil producer in Indonesia and currently owns six oil refineries in Indonesia that have a combined production capacity of 1 million barrels of oil per day (bpd). It is also Indonesia’s main supplier of government-subsidised fuel oil for domestic consumption.
In 2018 the GOI appointed Pertamina as the holding company of state-owned enterprises in the oil and gas sector involving Pertamina, PT Pertamina Gas (Pertagas) and PT Perusahan Gas Negara (PGN). It was felt that there was a need to consolidate the state-owned enterprises in order to increase the use of domestic natural gas in Indonesia. Pursuant to Government Regulation No 6/2018 on Increase of the Capital Subscription of the State in the Share Capital of Pertamina, the state increased its capital subscription in Pertamina by subscribing to new shares issued by Pertamina and as the consideration for such new shares, the state transferred its 13.8 billion Series B shares in PGN to Pertamina. Pertamina holds 56.96% of the shares in PGN and the remaining 43.04% is held by the public. PGN then acquired a 51% stake in Pertagas, a subsidiary of Pertamina, further integrating both companies’ infrastructure projects.
Pertamina’s web address: www.pertamina.com/en/home
Law No 22/2001 was enacted on 22 November 2001 and governs Indonesia’s petroleum sector.
Upstream activities are regulated by SKK Migas and governed by Government Regulation No 35/2004 (as last amended by Government Regulation No 55/2009), as well as numerous other regulations and procedures, which set out the process for exploitation of petroleum resources by way of co-operation contracts to be entered into between SKK Migas and petroleum companies (contractor(s)). Pioneered by Indonesia in 1966 and now adopted worldwide, the production sharing contract (PSC) is the most common form of co-operation contract. The traditional cost recovery model PSC used in Indonesia until 2017 allowed the state to maintain sovereignty over its petroleum resources with contractors assuming exploration and development risk, on the condition that their costs could be recovered from a share of production following a commercial discovery and successful development. However, in one of the most significant legal developments in the Indonesian upstream sector since the enactment of Law 22/2001, the MEMR, in early 2017, introduced a new form of PSC, the gross split PSC, which abolished cost recovery and replaced it with a contractor’s entitlement to a percentage split of the gross production determined on a pre-tax basis.
In July 2020, the MEMR, through MEMR Regulation 12/2020, reintroduced the cost recovery mechanism, allowing a new PSC (or an extension PSC) to adopt the cost recovery mechanism. The MEMR Regulation 12/2020 stipulates that the Minister shall decide whether a PSC will adopt either (i) a gross split PSC format, (ii) a cost recovery PSC format, or (iii) another co-operation agreement format.
Downstream activities are regulated under Government Regulation No 36/2004 (as last amended by Government Regulation 30/2009) and are managed by BPH Migas. Pursuant to these government regulations, downstream activities are controlled by business licences issued by the MEMR.
The GOI has also stipulated a National Energy Policy under Government Regulation No 79/2014 to achieve energy independence and national energy security to support national sustainable development. This policy shall be implemented from 2014 up to 2050.
A foreign investor wishing to enter the upstream petroleum sector in Indonesia can do so by establishing a permanent establishment or a limited liability company domiciled in Indonesia that is a foreign investment business entity (PT company). A "permanent establishment" is a business entity that is established outside Indonesia but conducts activities within the territory of Indonesia in accordance with the prevailing laws and regulations.
Private parties can exploit Indonesian petroleum resources by entering into a co-operation contract with the GOI (acting through SKK Migas), thus becoming a contractor. The most common form of co-operation contract in Indonesia is the PSC, which is typically granted for 30 years.
Upstream business activities are conducted in acreage referred to as the "contract area" or "work area" and specified in the co-operation contract.
Co-operation contracts can be awarded by regular tender or by direct offer. Most of the new acreage for upstream activities is awarded through a tendering process. The first licensing round of 2019 saw five contract areas (three exploration and two production) available for bidding, with two contract areas ultimately awarded, translating into USD109.2 million of investment in the upstream sector. In May 2019, the GOI opened the second licensing round of 2019 with four blocks (three exploration and one production) available for bidding, with one contract area being awarded and investment of USD159.3 million being made. In July 2019, the GOI opened the third licensing round of 2019 with four exploration blocks with no contract being awarded.
In a tender for a new contract area, the bidder must:
Direct offer is a process that permits a party to, in co-operation with the GOI, commission and fund a joint study into the prospects of petroleum commercialisation in a contract area, in return for which that party obtains a "right to match" the highest bidder in the subsequent tender process for the contract area.
Cost Recovery PSC
The most common form of a co-operation contract is the PSC. Traditional cost recovery PSCs in Indonesia have evolved through different "generations", often with varying fiscal terms. Under the generation immediately prior to the introduction of the gross split PSC (discussed below), 20% of gross production known as first tranche petroleum (FTP) is shared between the GOI and the contractor according to its allotted percentage under the PSC. After FTP, the contractor recovers all its depreciated capital and operating costs from production (cost recovery). The remaining production (after FTP and cost recovery), often called the equity to be split (ETBS), is then allocated to the state and the contractor in accordance with the percentages set out in the PSC.
Once production has commenced, the contractor may recover its expenses under the following broad categories:
In general, cost recovery and the manner in which PSC-related costs are audited is a much-debated topic within the Indonesian petroleum industry. Contractors often felt that SKK Migas was overly restrictive in approving work programmes and budgets as well as cost recovery, citing bureaucracy as a key delay for investment in the upstream sector. In contrast, the GOI viewed cost recovery as a burden on the state budget, particularly as the cost recovery allocation in the state budget has been increasing year after year.
Gross Split PSC
In 2017, the MEMR introduced the gross split PSC, which in effect replaced the contractor's right to cost recovery and a share of the FTP and ETBS with a potentially higher percentage of gross production being apportioned to the contractor. The base split for the contractor and GOI under the gross split PSC is 43% and 57% for oil, and 48% and 52% for gas. The base split is then adjusted according to variable and progressive components. Variable components are reflective of the location and nature of the discovery, and are determined by the MEMR, based on the proposal from SKK Migas, when the plan of development (POD) is approved. Progressive components then fluctuate over time and are linked to oil/gas price and cumulative production. The gross production allocation may be further adjusted by the Minister at his or her discretion at the time of POD approval, if this is considered to be warranted based on the economics of the block. Given an apparent lack of objective criteria and the uncapped nature of the Minister’s discretion, the uncertain nature of the fiscal terms for applicable development at the time of entering into a gross split PSC has caused concern for contractors.
Co-operation contracts in Indonesia override the general principles of Indonesian income tax law. General tax laws will only be applicable for matters that are not specifically dealt with in co-operation contracts. Indonesia has several layers of taxation on petroleum operations. The key taxes that apply to contractors in Indonesia are:
Pursuant to the "ring-fencing" principle adopted by the GOI, an entity may only hold an interest in one co-operation contract at any time. Accordingly, the costs incurred in respect of one co-operation contract cannot be used to relieve the tax obligations of another.
Following the introduction of the gross split PSC, a key outstanding question was how the tax rules would be applied as the existing upstream tax rules utilised cost recovery as the essential criteria for determining tax deductibility – ie, based on the "uniformity principle", costs that are cost recoverable are also tax deductible for the contractor’s tax filing and calculation of taxable income. In response, Government Regulation No 53/2017 was passed. Operating costs continue to be available for deduction from the contractor’s tax filing and calculation of taxable income. However, such deductions may only be applied for ten years.
It should also be noted that Indonesian PSCs (excluding some older-generation PSCs) do not contain a tax stabilisation clause.
Government Regulation No 35/2004 gives Pertamina a right of first refusal, exercised by the MEMR, if a contractor is transferring its interest in a PSC to a third party. In addition, pursuant to MEMR Regulation No 23/2018 (as amended by MEMR Regulation No 3/2019), Pertamina also has the right to apply for an interest in a contract area, if the co-operation contract governing that contract area is due to expire or has been relinquished, irrespective of whether the existing contractor has applied for an extension. If the existing contractor and Pertamina are awarded a joint operation of the contract area in a new co-operation contract, the existing contractor’s and Pertamina’s interest shall be determined by the MEMR.
In recent tender rounds, Pertamina has been granted a right to obtain an interest in a PSC from the winning bidder, provided a letter of intent is provided by Pertamina within a specified period.
Separately, each co-operation contract provides that, following a commercial discovery and approval of a POD, a contractor is required to offer 10% of its interest in the PSC to a regional government enterprise (BUMD) designated by local government or a state-owned enterprise (BUMN). To further implement this requirement and to address some of the financial challenges faced by BUMDs and BUMNs, MEMR Regulation No 37/2016 requires the contractor to offer to "carry" the financial obligations of the BUMD or BUMN until production, with such costs being offset from the BUMD’s or BUMN’s production entitlement. In older-generation PSCs, this offer of 10% interest was required to be made to Pertamina and it did not require any financial carry.
MEMR Regulation No 15/2013 requires those conducting upstream activities to maximise the use of domestic goods and services. SKK Migas Working Guideline (Pedoman Tata Kerjaor (PTK)) No 007/PTK/VI/2004 (as amended, at the latest, by PTK No 007/PTK/Revisi 4/PTK/2017) (PTK 007) and the co-operation contracts also set out local content requirements. PTK 007 required SKK Migas to approve procurement tenders over a certain amount and only permitted certain qualified contractors to bid for the work.
The introduction of the gross split PSC caused some uncertainty in respect of the domestic requirements for the procurement of goods and services. While MEMR Regulation No 8/2017 (as amended most recently by MEMR Regulation No 12/2020) states that “the procurement of goods and services is conducted by contractors independently”, it was unclear whether PTK 007 would also apply to gross split PSCs. Based on our most recent experience in negotiating gross split PSCs with MEMR and SKK Migas, it is understood that PTK 007 will not apply to gross split PSCs. The gross split PSC does, however, provide financial incentives for contractors to utilise domestic goods or services with a variable component adjustment ranging from 0–4% depending on the level of local content utilised.
A contractor is required to notify the GOI and SKK Migas of any discovery of petroleum in the contract area that the contractor has reasonably determined can be produced commercially.
Once such notification is acknowledged by SKK Migas, the contractor shall as soon as practicable (but within three years) submit its POD. The first POD shall be approved by the MEMR based on SKK Migas’ opinion after consulting with the relevant regional government. Subsequent PODs shall be approved by the chairman of SKK Migas. The estimated time for the issuance of an approval of a POD proposal is 40 days since the completed documents for submission are accepted by SKK Migas at the kick-off meeting process.
Once the relevant POD has been approved, the contractor is required to commence petroleum operations within five years from the end of the exploration period, failing which the PSC shall terminate.
The POD approval procedure is set out in SKK Migas Working Guidelines No PTK-037/SKKMA0000/2017/S0.
The terms of each PSC differ depending on various factors, such as the generation of the PSC and ability of the contractors to negotiate variations to the standard PSC terms.
Typically, each PSC grants rights to contractors over a specified contract area for a term of up to 30 years, with up to ten years for exploration and 20 years for exploitation, and may be extended for a further 20 years. Exploration periods are generally granted for six years, extendable to ten years.
Contractors are required to begin their activities within six months from the effective starting date of the PSC and to carry out the work programme during the first six years of the exploration period.
The contractor is responsible for all financing requirements and bears full risk if exploration is not successful. The PSC includes annual exploration expenditure requirements for both the initial six years and any extension. While the annual commitment is established in the PSC, details must be approved by SKK Migas via annual work programmes and related budgets (for a PSC with a cost recovery mechanism).
Under cost recovery PSCs, SKK Migas’ approval is required for annual work programmes and budgets prepared by the contractors, and authorisations for expenditure for operations conducted under the PSC. For gross split PSCs, because there is no cost recovery, SKK Migas only approves an annual work plan. The work budget is not subject to the approval of SKK Migas.
All goods purchased for operations under the PSC become the property of the GOI.
The contract area is relinquished progressively during the exploration period. The PSC terminates if no commercial discoveries are found before the exploration period expires and the entire contract area is relinquished.
The transfer of a majority interest in a PSC to a non-affiliate is not allowed during the first three years of the exploration period and a change in the operatorship in a PSC during that period is also prohibited. Outside of such limitations, a contractor may transfer part or all of its interest in a co-operation contract with the prior approval of the MEMR and/or SKK Migas, depending on the generation of the PSC. Pursuant to Government Regulation No 35/2004, Pertamina has a right of first refusal in respect of transfers to third parties, exercised by the MEMR.
Notwithstanding the terms of the PSC, MEMR 48/2017 requires a contractor to seek approval from SKK Migas in the event of a direct change of control in the contractor. In contrast, an indirect change of control (eg, in the parent company of the contractor) only requires a contractor to submit a notification to MEMR.
A direct transfer of interest in a PSC or a change of control in a contractor is subject to taxes imposed by Government Regulation No 79/2010 (as amended by Government Regulation No 27/2017) and Minister of Finance Regulation No 57/PMK.011/2011.
There are no regulatory restrictions on production rates of oil and gas in Indonesia. Indonesia became a member of OPEC in 1962, but left OPEC in 2008 when its membership expired having become a net importer of oil and being unable to meet its production quota. Indonesia suspended its OPEC membership again in 2016, less than a year after it re-joined OPEC, as it could not agree to a 5% production cut.
In April 2020, because of the coronavirus pandemic, Indonesia revised its 2020 oil and gas production targets downward by 30,000 barrels per day (bpd) to 735,000 bpd for oil and 5.727 billion cubic feet per day (Bcfd) for gas, having previously budgeted for 5.959 Bcfd.
Law No 22/2001 liberalised the downstream sector (oil and gas processing, storage, transportation and trading), opening it up to direct foreign investment and ended the former monopoly of Pertamina. Subject to certain shareholding restrictions, a foreign entity wishing to enter the downstream sector in Indonesia can do so by establishing a PT company and obtaining the relevant business licence. A downstream processing licence is valid for 30 years, extendable for another 20 years. Downstream transportation, storage and trading licences are valid for 20 years, extendable for another ten years.
There are no specific rights and terms of access to any downstream operation run by a national monopoly.
The authority to issue downstream licences rests with the MEMR. However, the application process may be managed by the Directorate General of Oil and Gas (DGOG) or the Indonesia Investment Co-ordinating Board (BKPM) under a delegation of authority from the MEMR. A person wishing to conduct processing, transportation, storage or trading must apply for a business licence for that activity from DGOG and BKPM, in addition to obtaining the general corporate licences.
To apply for a business licence, a PT company must submit to DGOG or BKPM:
Once approved, a temporary business licence valid for a maximum period of five years will be issued, under which the PT company will prepare the facilities and infrastructure of the business. Once the PT company is ready to operate, a permanent operating licence will be issued.
There are no sector-specific fiscal terms or production-sharing schemes for the downstream sector.
BPH Migas may regulate the tariffs imposed for gas transportation. The operator must submit the proposed tariffs to BPH Migas, and BPH Migas will verify and evaluate the proposed tariff. BPH Migas will determine the tariff after discussion with the operator and the user. In addition, the GOI, with input from BPH Migas, may determine the retail price for certain types of fuel oil by calculating their economic value.
PT companies holding a (i) wholesale trading business licence, (ii) limited trading business licence, or (iii) processing business licence that supplies/distributes oil as an extension of the processing business, or PT companies that hold specific licences for transmitting natural gas, must pay a royalty to BPH Migas.
There is no sector-specific tax regime for downstream operations. General Indonesian tax law applies for downstream operations, although entities may be subject to an exemption from import duty and exemption or postponement from VAT on imports of capital goods needed for production. Withholding tax and final tax arrangements will also differ depending on the activity undertaken.
Tax holidays may also be granted to pioneer investors, subject to the fulfilment of certain conditions. Tax allowances may also be provided to qualifying investments; for instance, regasification of LNG into gas using a floating storage regasification unit (FSRU) may be eligible to receive incentives under Law No 25/2007 and its implementing rules and regulations.
No special rights are given to the national oil or gas company in respect of downstream licences.
There is a limit on the maximum shareholding of foreign investors in companies conducting downstream activities. The percentage of foreign investment allowed in the oil and gas sector changes from time to time and is usually set out in a "negative list of investment" contained in presidential regulations, with the latest being Presidential Regulation No 44/2016. For example, the LNG sea transportation business is restricted to a maximum of 49% foreign shareholding and the LNG storage business is restricted to a maximum of 67% of foreign shareholding.
In general, downstream business licence-holders must prioritise the use of local goods, tools, services, technology, engineering and design capacity. The same rule holds in fulfilling labour requirements. If Indonesian workers do not meet the required standards and qualifications, the PT company must arrange for training and development programmes.
A PT company with a wholesale trading business licence for certain types of fuel oil may be required to provide opportunities to an appointed local distributor.
A general overview of each licence is given below.
One of the conditions of the licence is the submission to the MEMR and BPH Migas of operational reports, an annual plan, monthly realisations and other reports.
The conditions of the licence include:
Pipeline transportation is controlled by BPH Migas, which issues the oil and gas transportation licence based on the Masterplan for a National Gas Transmission and Distribution Network. The licence is granted only for a specific pipeline or commercial region. The conditions of the licence include:
For the transportation of natural gas, a gas transportation agreement and an access arrangement to BPH Migas are also required. The access arrangement, which is required to be approved by BPH Migas, must contain management guidelines, and technical and legal rules. The gas transportation agreement must align with the access arrangement.
Natural Gas Trading
The trading licence is further categorised into wholesale and limited trading, depending on the scale and ownership of the business. However, if the natural gas trading is carried out by an upstream contractor based on its rights under the PSC then the activity does not require a separate trading business licence. In addition to the trading licence, the entity must register the specific type of oil fuel being traded with BPH Migas and obtain a Business Registration Number (Nomor Registrasi Usaha, or NRU) from BPH Migas.
Conditions of the trading licence include:
In addition to the foregoing obligations, the trader must guarantee:
PT companies with a trade licence may include those with a gas distribution network facility and those without. If the trader has a gas distribution network, the entity should also apply for special rights for a distribution network area. This may only be implemented through a distribution network facility of a PT company that has obtained access to a distribution network area and after obtaining a licence to trade gas.
A separate licence is issued for an LPG trading business.
A private investor engaged in downstream activities does not have condemnation or eminent domain rights. Nevertheless, land rights are obtained by negotiating with owners or occupiers, in accordance with prevailing laws. Purchased land then becomes property of the state, while land leased for a facility will be leased in the contractor’s name. Title to land for downstream facilities outside of a co-operation contract may be held in the name of the concerned entity.
Government Regulation No 36/2004 requires each downstream storage and transport company to give third parties the opportunity to use its facilities. However, in practice, implementation has been slow. In response, MEMR Regulation No 4/2018 authorises BPH Migas to put gas transmission sections to tender. The same regulation also sets out the licensing requirements to engage in natural gas transmission by pipeline, or by using facilities other than pipelines in certain transmission areas or distribution networks.
In 2018, BPH Migas announced a plan to auction concessions for the construction of gas pipelines on the basis of third-party access, in accordance with the transportation master plan issued by the MEMR.
Facility sharing is only mandated to the extent that the facility has sufficient capacity and should not impair the facility’s operations. Facility sharing is also subject to economic considerations, including rates of return.
There are no restrictions on product sales into the local market. Note, however, that upstream contractors are prohibited from engaging in downstream activities, and vice versa, except where an upstream entity must build downstream facilities or engage in downstream activities that are integral to its upstream operations.
Subject to obtaining requisite export approvals, a contractor is entitled to export its production entitlement, subject to the domestic market obligation (DMO) that requires 25% of the contractor’s crude oil entitlement to be allocated for the domestic market at a discounted rate. In contrast to the traditional cost recovery PSC, the gross split PSC abolishes the requirement for contractors to supply crude oil to the Indonesian domestic market at a discounted price and permits contractors to receive the Indonesian Crude Price.
Cross-border sales of natural gas may be made only if:
Allocation of natural gas is prioritised by the GOI and requires export approvals from the Ministry of Trade (MOT), which, similar to oil, takes into account the export recommendations from the DGOG.
Downstream business licences are not transferable. The transfer of assets forming part of a distribution network requires the revocation of the existing special rights and the issuance of new special rights to the acquirer. Indirect acquisitions or share transfers may be subject to foreign share ownership restrictions and is also subject to prior approval.
Foreign investments in the petroleum sector enjoy the same protections as are generally afforded to foreign investments in Indonesia. Under Law No 25/2007, those protections include guarantees for equal treatment and assurances on the investors’ ability or right to repatriate their investments or the proceeds thereof. Indonesia has also ratified a number of treaties that might apply to protect foreign investments.
The OSS System
In 2018, for the purpose of accelerating and simplifying the licensing procurement process, the GOI enacted Government Regulation No 24/2018 on Electronically Integrated Business Licensing Services (Government Regulation No 24/2018), which introduces an online business licensing platform called the Online Single Submission (OSS) system. The OSS system is currently operated and managed by BKPM.
After the enactment of Government Regulation No 24/2018, business entities engaging in either upstream or downstream petroleum business must obtain a Business Identification Number (Nomor Induk Berusaha, or NIB) and commercial/operational licence (if required) through the OSS system. The NIB shall also serve as:
Whilst these general business licences need to be obtained through the OSS system, all of the downstream licences, such as the downstream processing licence, are still processed by DGOG or BKPM and applications to obtain those downstream licences need to be submitted directly to DGOG or BKPM.
Regional governments and the Ministry of Environment and Forestry (MOEF) (through the relevant local agency/office) oversee environmental matters for both upstream and downstream operations. The principal environmental regulations in Indonesia are:
Law No 32/2009 and its implementing regulation, Government Regulation No 27/2009, require those engaged in businesses or activities that have significant environmental impact to prepare an AMDAL before starting the business or activity. Businesses or activities that are regarded as having a significant impact on the environment are set out in the Regulation of the Minister of Environment No No P38/MENLHK/SETJEN/KUM.1/7/2019.
Law No 32/2009 also requires each business and/or activity that is required to have an AMDAL to obtain an Environmental Licence, failing which its relevant personnel might be fined. The AMDAL must be approved by the relevant office at the regional government level in charge of environmental matters or the MOEF before an Environmental Licence will be granted.
There are no specific EHS requirements for offshore development in Indonesia.
Pursuant to MEMR Regulation No 15/2018, all contractors must set aside certain amounts in an abandonment and site restoration fund from the start of commercial operations until expiry of the PSC. The fund must be deposited in a bank account jointly held by the contractors and SKK Migas. This requirement applies to all unexpired PSCs.
Prior to the enactment of MEMR Regulation No 15/2018, abandonment and site restoration activities/decommissioning activities were governed by the terms of the PSC and by BP Migas Working Guidelines No 040/PTK/XI/2010.
There is no specific regulation on climate change in Indonesia. Indonesia has, through Law No 16/2016, ratified the Paris Agreement.
In general, oil and gas business activities in Indonesia are regulated and supervised by SKK Migas. However, a special right has been given to the Aceh Province to manage its own oil and gas natural resources. A special task force named Badan Pengelola Migas Aceh (BPMA) was formed to regulate and supervise the upstream oil and gas activities within the Aceh Province.
Unconventional oil and gas resources are governed by MEMR Regulations No 5/2012 and 38/2015. The first regulation requires the offering of the unconventional work area through direct offering or regular tender. The second regulation enables the sale of unconventional oil and gas for contractors by allowing contractors to sell unconventional oil and gas produced before obtaining the first POD, provided that MEMR approval is obtained.
LNG facilities may be operated by entities engaged in both upstream and downstream activities – eg, as upstream facilities ancillary to their main activities under the PSC or as downstream processing/trading facilities.
Indonesia was the first country to enter into a PSC in 1966. Now, PSCs are one of the most common types of contractual arrangements for petroleum exploration and development, and have been implemented throughout the world. For countries and governments, a key element of the PSC (as opposed to traditional concession or licence arrangements) is that the State maintains sovereignty over its petroleum resources and the contractor is only entitled to a share of production.
Since 1966, the Indonesia PSC has undergone a steady evolution (often referred to as new generations of PSC), with the fiscal terms in particular being systematically revised over the years. The traditional PSC model used in Indonesia until 2017 was based on a cost recovery methodology, pursuant to which contractors recovered their exploration and development costs from a prescribed share of the production if a commercial discovery and successful development occurred. However, in one of the most significant legal developments in the Indonesian upstream sector since the enactment of Law 22/2001, the MEMR in early 2017 introduced a new form of PSC, the gross split PSC, which abolished cost recovery and replaced it with a contractor’s entitlement to production on a gross split percentage determined on a pre-tax basis.
Following the introduction of the gross split PSC, all new PSCs are required to follow the gross split PSC format. However, the MEMR recently enacted the MEMR Regulation 12/2020 which allows new PSCs (including those issued as an extension to an existing PSC) to be awarded, at the election of the MEMR, as a conventional cost recovery PSC, a gross split PSC or other co-operation form set forth by the MEMR. Under MEMR Regulation No 8/2017 (as amended, most recently, by MEMR Regulation No 12/2020) contractors may request to amend their existing PSCs to apply a gross split mechanism.
At the time MEMR Regulation 12/2020 was enacted in July 2020, more than 30 contract areas in Indonesia now operate under the gross split PSC regime, with some contractors opting to convert their existing cost-recovery PSCs into gross split PSCs.
As of March 2019, the Indonesian House of Representatives has initiated draft legislation of the long-awaited oil and natural gas bill to amend Law No 22/2001. The new oil and gas law is widely expected to reform the oil and gas regulatory framework. The bill has been submitted to the President and is currently being reviewed by the MEMR.
Expected changes include the establishment of a new oil and gas business entity called BUMN-K, which will be granted the authority to carry on business activities in the upstream and downstream sectors. The bill will also provide greater flexibility around co-operation with investors by introducing, in addition to the standard conventional PSC, a gross split PSC and "other forms of co-operation frameworks" that may benefit the state.