Energy: Oil & Gas 2023 Comparisons

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. Law No 22/2001 regarding Oil and Gas, as amended by Law No 6 of 2023 on the Stipulation Into Law of Government Regulation in Lieu of Law No 2 of 2022, concerning Job Creation (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. The Directorate General for Oil and Gas (DGOG) on behalf of the Ministry of Energy and Mineral Resources (MEMR) sets policies for the industry.

The petroleum sector in Indonesia is segregated into upstream and downstream activities.

Upstream Regulators

Upstream activities include exploration and exploitation, and are managed and supervised 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 reports directly to the President and is supervised by a committee consisting of:

• the Minister of Energy and Mineral Resources;
• the Vice Minister of Energy and Mineral Resources;
• the Vice Minister of Finance (MOF); and
• the Head of the Capital Investment Co-ordinating Board (BKPM).

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 Hydrocarbon 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 Regulators

Downstream activities include processing, transportation, storage and trading, and are managed and supervised 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), 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 government.

As of 12 June 2020, the Ministry of State Enterprises announced Pertamina as a holding company in the Indonesian energy sector. Pertamina established six business units:

• upstream, operated under PT Pertamina Hulu Energi (PHE);
• gas, operated by PT Perusahaan Gas Negara Tbk (PGN);
• refinery and petrochemicals, operated by PT Kilang Pertamina Internasional;
• power and NRE, operated by PT Pertamina Power Indonesia;
• commercial and trading, operated by PT Patra Niaga; and
• shipping, operated by PT Pertamina International Shipping. 

The reorganisation follows a consolidation of state-owned enterprises in the oil and gas sector involving Pertamina, PT Pertamina Gas (Pertagas) and PT Perusahan Gas Negara (PGN). In 2018, 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; 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.

In the upstream sector, PHE and its subsidiaries act as a contractor to SKK Migas (as do foreign investors). As of 31 December 2021, PHE was an operator of 27 working areas and non-operator of 13 working areas.

PGN is responsible for managing a number of activities including natural gas transmission, provision and sales of liquefied natural gas (LNG) to both domestic and international markets, compressed natural gas (CNG), as well as lead gas infrastructure projects, such as construction of LNG regasification facility, gas pipelines, and gas refuelling stations (SPBGs).

In the refining and petrochemical sector, PT Kilang Pertamina Internasional is responsible for oil refining into petroleum and petrochemical products. Pertamina’s oil refinery activities are supported by six refineries – Dumai Refinery Unit (RU) II, Plaju RU III, Cilacap RU IV, Balikpapan RU V, Balongan RU VI, and Kasim RU VII – with total installed capacity of 1,031 mbopd, or approximately 90% of the total existing refinery capacity in Indonesia.

Pertamina is rated as Baa2 (Stable) by Moody’s and BBB (Stable) by S&P and Fitch, respectively.

The main regulation that governs Indonesia’s petroleum sector is Law No 22/2001, enacted on 22 November 2001.

Upstream Regulation

Upstream activities are regulated by DGOG on behalf of the MEMR and SKK Migas and are 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.

The rights to oil and gas exploration and exploitation are held by the government. To explore and exploit oil and gas, co-operation contracts are 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 PSC model enables the state to maintain sovereignty over its petroleum resources with contractors assuming exploration and development risk in return for compensation in accordance with the PSC.

Prior to 2017, the PSCs incorporated a cost recovery model, whereby the contractor would recover its costs 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, in early 2017 the MEMR 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 (i) a gross split PSC format, (ii) a cost recovery PSC format, or (iii) another co-operation agreement format.

Downstream Regulation

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 government 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 to 2050.

Reform

There are ongoing efforts in Indonesia to make the Oil and Gas Law more efficient (described in 6.4 Unique or Interesting Aspects of the Hydrocarbon Industry). The People’s Representative Council (DPR) seeks to merge the two regulatory agencies (SKK Migas and BPH Migas) so that the industry is regulated by one administrative agency (BUKMigas). BUKMigas would also be responsible for the exploration and exploitation of oil and gas, with or without partnership with oil and gas contractors. The government and the MEMR, however, continue to advocate for the separation of upstream and downstream activities.

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 (ie, 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 government (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 with a possible extension of up to 20 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 tender or by direct offer. Most of the new acreage for upstream activities is awarded through a tendering process in accordance with MEMR Regulation No 35 of 2021 regarding Procedures for the Stipulation and Tender of Oil and Gas Mining Concession Areas. In the first licensing round of 2023, two upstream blocks were made available for direct offer: Akia and Beluga; and one upstream block was made available for direct offer without joint study: Bengara I. All three are tendered out as cost recovery scheme working areas. 

In a tender for a new contract area, the bidder must:

• register as a tender participant by purchasing the bid information pack;
• purchase the official government information for the particular work area; and
• submit the completed bid documents by the tender closing date to the MEMR for financial, technical and performance evaluation.

Direct offer (less common) is a mechanism allowing a party to propose the inclusion of a working area in a tendering process after, or without conducting, a joint study. For a direct offer with a joint study, in return for such joint study, that party obtains a “right to match” the highest bidder in the subsequent tender process for the contract area. Direct offer without joint study can only be conducted for a working area which was tendered out in the previous licensing round but received no winning bidder.

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 latest cost recovery generation PSCs:

• a maximum of 20% of gross production, known as first tranche petroleum (FTP), is shared between the government 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), potentially up to a capped amount; and
• 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. The split ratio depends on each PSC, but the split between the contractor and the government is usually 35% and 65% for oil, and 40% and 60% for gas.

Once production has commenced, the contractor may recover its expenses under the following broad categories:

• operating costs from a particular field for the current year;
• depreciation of capital costs based on the accounting rules in the PSC; and
• carried forward operating costs and depreciation from previous years that have not been recovered.

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 government 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 the government 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, if considered to be warranted based on the economics of the block, be further adjusted by the Minister at his or her discretion at the time of POD approval. Given an apparent lack of objective criteria and the unfettered 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.

On 23 May 2023, the MEMR issued a press release announcing that the GOI plans to revise the existing regulations to provide for a “new simplified gross split” arrangement. Aside from improving the investment climate in the oil and gas industry, the revisions are primarily intended to achieve the following objectives:

• increase the contractor’s production share (before tax) to be within the range of 80%–90% of the gross production, depending on the risk profile of the working area;
• reduce the need for the contractor to rely on the Minister’s discretionary decision (to award additional split) to increase the economics of the working area;
• reduce the components and parameters for the split; and
• design fiscal policies that are suitable for non-conventional oil and gas.

Such revisions will be effected by amending MEMR Regulation No 8 of 2017 on Gross Split Production Sharing Contract (as amended at the latest by MEMR Regulation No 12 of 2020) and the new regulation is expected to introduce the following changes:

• reducing the variable components from ten components to become three components;
• reducing the progressive components from three components to two components;
• balancing the base split;
• balancing the total split;
• amending the formula for the progressive component of the oil and gas price;
• applying a sliding scale on the parameters of the progressive component of the oil and gas price based on a certain threshold;
• removing the local content obligation from the split components;
• separating the terms and conditions applicable for the non-conventional oil and gas operation from those applied to conventional oil and gas operation;
• adding fixed variable components specifically for non-conventional oil and gas operation;
• improving the evaluation process to determine the “parameters” for split adjustment according to the progressive components by conducting statistical analysis based on information derived from the price and production realisation data of the past five years; and
• removing attachment on the variable and progressive components from the Minister Regulation to the Minister Decree to facilitate a simpler adjustment based on future price and production realisation data.

In addition to the aforementioned changes, the new regulation is expected to incorporate the following transitional provisions:

• all PSCs that were executed prior to the enactment of the new simplified gross split will continue to be valid;
• a contractor with cost recovery PSC may request for its PSC to be converted into the new simplified gross split PSC;
• a contractor with gross split PSC may request for its PSC to be amended to become the new simplified gross split PSC;
• such conversion or amendments will not apply retroactively and will not extend the term of the PSC;
• for contractors with gross split PSC that had received the additional discretionary split from the Minister but intend to request for the PSC to be amended to become the new simplified gross split PSC, the Minister will re-evaluate (and if necessary, adjust) the additional split according to the economics of the working area; and
• with respect to the existing working areas, the split between contractor and GOI stipulated in the POD approval will be adjusted using the variable and progressive components of the new simplified gross split which will be stipulated in a Minister Decree on Implementation Guidelines and Components of Gross Split PSC.

In relation to the last bullet point above, it is unclear whether the adjustment is applicable to all existing gross split PSCs or will only be applied for the gross split PSCs that will be converted into the new simplified gross split PSCs.

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:

• corporate income tax – this rate is dependent on the signing date of the PSC (with effect from 2022, the applicable rate is 22%);
• branch profits tax – 20%;
• dividend tax – 15%;
• withholding tax – this rate might differ depending on the recipient, and be subject to treaty reduction in the case of non-resident entities; and
• value added tax (VAT) – crude oil and natural gas are not subject to VAT and contractors are therefore not taxable for VAT purposes, they will, however, be charged with VAT on the local purchase of taxable goods and services, which may be reimbursed under the PSCs.

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 offset any liability to pay tax under another co-operation contract.

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. If, after the deduction of the operating cost, the contractor suffers a loss, then such a loss can be compensated with the income of the next ten consecutive years.

In August 2021, the GOI issued Government Regulation No 93/2021 which amended the provisions related to income tax for the transfer of participating interest in Government Regulation No 53/2017. Government Regulation No 93/2021 stipulates that the income derived from the transfer of participating interest, directly or indirectly, shall be subject to final income tax. Therefore, any investors that wish to transfer or acquire participating interest (directly or indirectly) must consider the tax implication of Government Regulation No 93/2021 on the transaction.   

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 23/2021, 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.

According to MEMR Regulation No 35 of 2021, Pertamina was granted a right to obtain 15% 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). Specifically for working areas located within Aceh Province, Government Regulation No 23 of 2015, requires a contactor to make an offer at the minimum of 10% to Aceh’s BUMD. To further implement this requirement, and to address some of the financial challenges faced by BUMDs, MEMR Regulation No 37/2016 requires the contractor to offer to “carry” the financial obligations of the BUMD until production, with such costs being offset from the BUMD’s production entitlement. If this offer of 10% interest is to be made to BUMN, it does 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/SKKIA0000/2023/S9 (Fifth Revision)) (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 experience in negotiating gross split PSCs with the 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 2–4%, depending on the level of local content utilised.

A contractor is required to notify the government 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.

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/SKKMA0000/2021/S1 (Third Revision).

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 government of Indonesia.

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. MEMR 48/2017 does not specify the timing for the notification, however, based on our observation, most recent PSCs require the notification to be made in advance (ie, prior to the completion of the transaction).

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), Minister of Finance Regulation No 257/PMK.011/2011 and Government Regulation No 93/2021.

Pursuant to Government Regulation No 35/2004, all goods and equipment utilised for upstream oil and gas operations purchased by the contractor become the property of the GOI. Therefore, since the upstream assets belong to the GOI, they cannot be transferred to a third party.

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 rejoined OPEC, as it could not agree to a 5% production cut.

Indonesia set its 2023 oil and gas production targets at 660,000 barrels per day (bpd) for oil and 6.160 million cubic feet per day (MMscfd) for gas.

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 and storage licences are valid for 20 years, extendable for another ten years. Downstream trading licence is valid for 20 years, extendable for another 20 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 or BKPM, in addition to obtaining the general corporate licences.

To apply for a business licence, a PT company must submit to DGOG or BKPM:

• the name of the PT company;
• the line of business proposed;
• an undertaking to comply with operational procedures; and
• a detailed plan and technical requirements relating to the business.

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 government, with input from BPH Migas, may determine the retail price for certain types of fuel oil by calculating their economic value.

PT companies holding (i) a wholesale trading business licence, (ii) a limited trading business licence, (iii) a processing business licence that supplies/distributes oil as an extension of the processing business, or (iv) a specific licence for transmitting natural gas, must pay a royalty (iuran) 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 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 Government Regulation No 78 of 2019 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 certain downstream activities. The percentage of foreign investment allowed in the oil and gas sector changes from time to time and is set out in a “positive list of investment” contained in presidential regulations, with the latest being Presidential Regulation No 10/2021 (as amended by Presidential Regulation No 49 of 2021). For example, the LNG sea transportation business is restricted to a maximum of 49% 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.

Gas Processing

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.

Gas Storage

The conditions of the licence include:

• submission of operational reports to the MEMR each quarter, or as often as may be requested by BPH Migas;
• provision of opportunity for another party to share in its storage facilities;
• sharing of storage facilities in remote areas; and
• holding a licence to store LNG.

Gas Transportation

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:

• submission of monthly operational reports to the MEMR and BPH Migas;
• prioritisation of the use of transportation facilities owned by co-operatives, small enterprises and national private enterprises (for land transportation);
• provision of opportunity for sharing the utilisation of its pipelines and other facilities; and
• compliance with the Masterplan for the National Gas Transmission and Distribution Network.

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:

• submission of monthly operational reports to the MEMR or at any time, as required by BPH Migas, including reports in respect of the appointment of distributors;
• maintenance of facilities and means of storage that will secure supply from domestic and foreign sources;
• distribution of fuels through a distributor, to small-scale users under the licence-holder’s authorised trade mark; and
• prioritisation of co-operatives, small enterprises and national private enterprises when appointing a distributor.

In addition to the foregoing obligations, the trader must guarantee:

• the constant availability of fuels and processing output in its trade distribution network;
• constant availability of gas through pipelines in its trade distribution network;
• selling prices of fuels and processing output at a fair rate;
• availability of adequate trade facilities;
• standard and quality of fuels and processing output, as determined by the MEMR;
• accuracy of the measurement system used; and
• use of qualifying technology.

PT companies with a trading 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 company 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 company, while land leased for a facility will be leased in the company’s name.

The transportation of hydrocarbons would fall under the supervision of Ministry of Energy and Mineral Resources (MEMR), Ministry of Transportation (MOT) and/or Ministry of Environment and Forestry (MOEF) depending on the type of hydrocarbon products and the method of transportation.

In general, hydrocarbon products are under the supervision of the MEMR, except for lubricant and petrochemicals products which are under the supervision of the Ministry of Industry. When the hydrocarbon products that fall under the MEMR’s supervision are transported, either through land transportation, sea transportation or pipelines, the transportation process would be regulated by, and fall under the supervision of, the MEMR and the MOT. For lubricant and petrochemicals products, the transportation would be regulated by, and fall under the supervision of, the MOT, and MEMR has no authority to regulate or supervise the transportation of these products. In case the transported hydrocarbons fall under the category of hazardous and toxic substance (bahan berbahaya dan beracun) or hazardous and toxic waste (limbah bahan berbahaya dan beracun), the transportation would also be required to comply with requirements issued by the MOEF.

The key regulations governing the transportation of hydrocarbons are:

• Law No 22 of 2009 on Traffic and Road Transportation as amended by Law No 6 of 2023 on the Stipulation into Law of Government Regulation in Lieu of Law No 2 of 2022 concerning Job Creation (Law 6/2023) and Government Regulation No 74 of 2014 on Road Transportation as amended by Government Regulation No 30 of 2021;
• Law No 17 of 2008 on Shipping as amended by Law 6/2023 and Government Regulation No 20 of 2010 on Sea Transportation as amended by Government Regulation No 22 of 2011;
• Law No 22/2001 and Government Regulation No 36 of 2016 on Oil and Gas Downstream Activities as amended by Government Regulation No 30 of 2009; and
• Law No 32 of 2009 on the Environment Protection and Management as amended by Law 6/2023 and Government Regulation No 22 of 2021 on Implementation of the Environment Protection and Management.

Government Regulation No 36/2004 (as amended by Government Regulation No 30 of 2009) 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. Recent generations of PSCs no longer require the contractor to sell their entitlement at a discounted price for the purpose of DMO. 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:

• the domestic need for natural gas has been fulfilled;
• there is insufficient domestic infrastructure; or
• domestic purchasing power is insufficient to satisfy the relevant gas field’s economics.

Allocation of natural gas is prioritised by the government 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 Online Single Submission System

In 2018, for the purpose of accelerating and simplifying the licensing procurement process, the government 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.

On 2 November 2020, the government issued Law No 11 of 2020 on Job Creation (or the Omnibus Law). The Omnibus Law aims to attract investment, create new jobs, and stimulate the economy by, among other things, simplifying the licensing process and harmonising various laws and regulations, and making policy decisions faster for the central government to respond to global or other changes or challenges. The Omnibus Law amended more than 75 laws; up to April 2021, the central government has issued at least 50 implementing regulations, making the Omnibus Law one of the most sweeping regulatory reforms in Indonesian history.

One of the implementing regulations issued in relation to the Omnibus Law is Government Regulation No 5 of 2021 (Government Regulation 5/2021) which revoked Government Regulation No 24/2018. According to Government Regulation 5/2021, business entities engaging in either upstream or downstream petroleum business must obtain a Business Identification Number (Nomor Induk Berusaha, or NIB) and a commercial/operational licence (if required) through the OSS system. The NIB shall also serve as:

• the importer’s identification number (Angka Pengenal Importir, or API);
• the customs registration number;
• evidence of automatic registration for the Health and Manpower Social Security Programmes; and
• the first mandatory labour report.

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.

On 25 November 2021, the Constitutional Court, through Decision Number 91/PUU-XIII of 2020, declared the Omnibus Law to be “conditionally unconstitutional” and consequently certain aspects of the Omnibus Law need to be rectified. The rectification is required to be completed within a two-year period and during such time, the Omnibus Law continues to be valid and in full force.  In response, on 30 December 2022, the GOI enacted Government Regulation In Lieu of Law No 2 of 2022 on Job Creation (GR 2/2022) revoking and replacing the then existing Omnibus Law. However, all of the implementing regulations enacted under the preceding Omnibus Law remain valid, provided that they did not contravene GR 2/2022.

On 31 March 2023, the House of Representatives ratified and elevated the status of GR2/2022 to become Law 6/2023. 

There is no restriction on Indonesian companies wishing to invest in oil and gas businesses in other jurisdictions. 

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 regarding Environment Protection and Management as amended by the Omnibus Law;
• Government Regulation No 22/2021 regarding Implementation of Environmental Protection and Management; and
• Regulation of Minister of Environment and Forestry No 4 of 2021 regarding List of Business and/or Activities that are Required to Have an Environment Impact Assessment (Analisis Mengenai Dampak Lingkungan Hidup, or AMDAL), Environment Management Effort (Upaya Pengelolaan Lingkungan Hidup, or UKL), and Environment Monitoring Effort (Upaya Pemantauan Lingkungan Hidup, or UPL) or Statement of Ability for Environmental Management and Monitoring (Surat Pernyataan Kesanggupan Pengelolaan dan Pemantauan Lingkungan Hidup, or SPPL).

Law No 32/2009 and its implementing regulation, Government Regulation No 22/2021, require those engaged in businesses or activities that have impact to the environment to prepare an AMDAL or UKL-UPL or SPPL before starting the business or activity. AMDAL is required for businesses/activities that have significant impact to the environment. UKL-UPL is required for businesses/activities that do not have significant impact to the environment. SPPL is required for businesses/activities that are not required to have AMDAL or UKL-UPL. The classification of businesses or activities that would require either AMDAL or UKL-UPL or SPPL is set out in the Regulation of the Minister of Environment No 4/2021.

There are no specific EHS requirements for offshore development in Indonesia.

Pursuant to MEMR Regulation No 15/2018 and SKK Migas Working Guidelines No PTK-040/SKKMA0000/2018/S0, 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 managed 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 manage 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, which requires the offering of the unconventional work area through direct offering or regular tender.

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.

The GOI has designated several oil and gas projects for the CCU/CCUS programme (including the EGR Tangguh project, Gundih PEP and Sukowati PEP) and has issued MEMR Regulation No 2 of 2023 on CCS and CCUS. 

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 generation PSCs), 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 operated 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. Because of the COVID-19 pandemic, the new oil and gas bill is no longer included in the priority list of the House of Representatives as of 2021 and, as such, little progress has been made recently on the draft bill.

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.