A modern upstream industry was established by the Petroleum Act B.E. 2514 (1971) (the “Petroleum Act”) where ownerships of petroleum resources belonged to the state. Exploration and production activities require authorisation of the Minister of the Ministry of Energy (the “Minister”).
Landowners are unable to legally explore for or produce petroleum resources or authorise such activities unless obtaining exploration and production rights (the “Petroleum Rights”) from the state. The state ownership of petroleum resources extends the state’s power to grant the Petroleum Rights in the offshore areas to the Thai continental shelf.
The key regulator to grant Petroleum Rights is the Minister, and it is empowered to renew and revoke the awarded Petroleum Rights with advice from the Petroleum Committee exercising these powers. This Committee is established by the Petroleum Act. However, granting of Petroleum Rights on overlapping areas in the Gulf of Thailand between Thailand and Malaysia is a power of the joint authority established by both governments.
At an operational level, the key upstream regulator is the Department of Mineral Fuel (DMF). The Director-General of DMF serves as a member and a secretary of the Petroleum Committee with the power to approve the determination of a production area, permit an extension of the period for commencing the production, and approve the working plan and estimated cost of decommissioning activities.
For midstream/downstream, the Minister is still a key regulator vested with powers to authorise petroleum trading activities under the Fuel Trade Act B.E. 2543 (2000) (the “Fuel Trade Act”) and the Director of the Department of Energy Business (DOEB) under the Fuel Control Act B.E. 2542 (1999) (the “Fuel Control Act”).
The Energy Regulatory Commission (ERC) is not vested with a regulatory power to grant the Petroleum Rights under the Energy Industry Act B.E. 2550 (2007) (the “Energy Industry Act”).
The Thai government established a state-owned petroleum enterprise named the Petroleum Authority of Thailand (PTT) through the Petroleum Authority of Thailand Act B.E. 2521 (1978) (the “PTT Act”). PTT does not own petroleum resources but is empowered to carry out petroleum operation and other related businesses. PTT did not have monopolistic powers in any of the petroleum markets: upstream, midstream or downstream.
PTT was privatised in 2001 and named PTT Public Company Limited (“PTT PLC”) through the Corporatisation of State-owned Enterprise Act B.E. 2542 (1999), and the PTT Act is repealed. As the Ministry of Finance holds more than 51% of its shares, PTT PLC is deemed a state-owned enterprise under the Budgetary Procedures Act, B.E. 2561 (2018) (the “Budget Procedures Act”).
Key legislation governing the granting of Petroleum Rights is the Petroleum Act. Terms and conditions on petroleum rights granted in the form of a concession and production sharing contract is subject to the Ministry Regulation on Form of Petroleum Concession B.E. 2555 (2012) (the “Concession Form”) and the Ministry Regulation on Form of Production Sharing Contract B.E. 2561 (2018) (the “PSC Form”). Determining the type of authorisation is governed by the Notification of the Petroleum Committee on Criteria and Methods for Selection of the Exploration or Production Are to be awarded in the Form of Concession, Production Sharing Contract, or the Service Contract (2017) and as amended (the “Notification of the Petroleum Committee”).
At operational stages, an exploration and production operator (“E&P Operator”) must comply with the Ministerial Regulations on Criteria and Methods on Petroleum Exploration, Production, and Conservation B.E. 2555 (2012). Decommissioning activities are governed by the Ministerial Regulations on Removal of Installation for Petroleum Operation Working Plan, Estimated Budget, and Security B.E. 2559 (2016).
The petroleum rights granted by the Minister can take three forms: a petroleum concession, a production sharing contract (PSC), and a service contract (SC). The concessionaire and the contractor bear risks and costs associated with operational activities. A concessionaire will become an owner of the produced petroleum and can commercialise these extracted resources. A PSC contractor will have a right to acquire the profit oil under the produced petroleum which was allocated for cost recovery and royalty payments. A service contractor will obtain no ownership of produced petroleum, but will obtain service fees.
The Minister of Energy will determine the exploration and production area opened for competitive bidding. It will announce onshore or offshore exploration blocks, relevant maps and prescribe qualifications of bidders, details on bidding document submissions as relevant, and evaluation criteria. The winner will be required to deposit a performance bond.
In determining the form of petroleum rights, the Minister must comply with the criteria and methods announced by the Petroleum Committee. The area with proven oil reserves from 300 million barrel or natural gas reserves from three trillion cubic feet shall be awarded an SC. For the area not qualified for SC, if the commercial discovery rate of the geological area (“Commercial Discovery Rates”) is higher than that of the country, a PSC is awarded. If the Commercial Discovery Rates are lower or equal to that of the country, a concession is awarded. The rates are reviewed every five years.
A concessionaire is bound to pay royalty, special remuneration, and petroleum income tax. Royalty payment is based on petroleum which is sold or distributed in the form of cash or in kind. Sliding scale rates, from 5–15%, are applied to the current petroleum fiscal regime. Petroleum concession typically requires a concessionaire to pay special remuneration benefits on a progressive rate from 0–75% on windfall profit.
A PSC contractor is required to pay special remuneration benefits and royalty at the rate of 10% of the total production. Actual operation costs shall be recovered from the total production but shall not exceed the total production. The remaining petroleum shall be treated as profit oil. A PSC contractor is not bound to pay petroleum income tax.
A service contractor may be assigned to sell or dispose of the produced petroleum. Operational costs shall be borne by the contractor. In return, the contractor shall earn service fees payable in cash or in kind only when a commercial discovery is made.
In operating petroleum business, a concessionaire shall pay income tax under the law on petroleum income tax. The Petroleum Income Tax Act B.E. 2514 (1971) provides tax rates shall be less than 50% of net income but shall not exceed 60% of net income. In addition, the Thai government has adopted a royalty on petroleum which is sold or distributed, in order to gain the state’s share from petroleum production. A PSC contractor is not subject to pay income tax under the law on petroleum income tax. However, it must pay a royalty on petroleum which is sold or distributed. Royalty payment calculation methods are stated in a royalty clause contained in a PSC.
PTT Exploration and Production Public Company Limited (PTTEP), founded in 1985, as the upstream arm of PTT PLC, which holds more than 60% of its shares, makes PTTEP a state-owned enterprise under the Budget Procedures Act.
PTTEP operates several offshore petroleum projects including the Erawan and the Bongkot blocks. It has been awarded a production sharing contract for offshores blocks (G1/65 and G3/65) in 2023. It operates upstream projects in foreign countries including Malyasia, Mozambique, United Arab Emirates and Algeria.
A concessionaire and a PSC contractor undertake to hire Thais for petroleum operation as much as possible. For marine transport of petroleum operations, a concessionaire is bound to use the Thai vessels unless the service fee offered is higher than usual rates. Additionally, a concessionaire shall prioritise Thai operators for construction of an offshore production platform.
A concessionaire, a PSC contractor and an SC contractor must commence petroleum production according to the plan within four years from the approval date from DMF. On failure to do so, it shall be deemed that the petroleum production period is terminated.
To safeguard against political risks, a petroleum concession and a PSC require the Minister to refrain from “unilaterally” changing rules pertaining to benefits, rights and duties such as royalty, income tax payments, and calculation of the awarded concession and the PSC. In case of changes affecting benefits, rights and duties of the protected rights, the Minister and the concessionaire may agree to amend the rules accordingly. If the Minister proposed a negotiation on the change, the concessionaire undertakes to respond to the proposed negotiation.
For dispute resolution, implementing Section 53 of the Petroleum Act, the Concession Form and the PSC Form stipulates that a dispute relating to a Ministerial order to amend or revoke a concession according to Section 52 of the Petroleum Act or a dispute relating to compliance with the terms of a concession shall be resolved by a means of arbitration.
Under the Petroleum Act, a concessionaire and a PSC contract receives the guarantee that the state will not force transfer the properties and rights in relation to the petroleum business operation to the ownership of the state, except for the transfer under the provisions of concession. Exports of petroleum outside the Kingdom will not be restricted.
During a petroleum exploration period, the concessionaire and the PSC contractor may produce petroleum. Before producing petroleum from any place in an exploration block, they shall demonstrate that a commercial well has been discovered and a production area has been determined correctly. When the concessionaire has obtained approval from the Director-General, it may then produce petroleum from such production area. The Petroleum Act does not empower the state to place a production restriction on the concessionaire or the PSC contract.
The Petroleum Act serves as a legal basis authorising an E&P operator to carry out midstream/downstream operations. A concessionaire and a PSC contractor have the right to store and transport petroleum, and to sell and distribute the produced petroleum.
Private operators not awarded a concession or a PSC under the Petroleum Act can participate in midstream/downstream markets through licensing and registration regimes depending on the trading volumes and the nature of activities.
Persons conducting a Category 3 business must obtain a licence from DOEB. These downstream markets are, for example, a gasoline station located on a public road or a gasoline station providing services to aircraft.
There is no national monopoly in downstream. PTT PLC, a state-owned enterprise and dominant player, participates midstream/downstream markets through subsidiaries PTT Global Chemical Public Company Limited, Thai Oil Public Company Limited, IRPC Public Company Limited and Global Power Synergy PTT Oil and Retail Business Public Company Limited.
A person becoming a fuel trader under Section 7 of the Fuel Trade Act must be incorporated under Thai law. The applicant must demonstrate detailed location of a fuel station and storage and fuel tanks. A licence and registration will be issued by the Minister or DOEB if the licence fees are paid.
Safety is at heart of the licensing regime established by the Fuel Control Act; for example, for a Category 3 licence under the Fuel Control Act, operators must begin with getting its construction and design plans approved by DOEB together with approvals for fuel storage and equipment testing.
A concessionaire shall set the selling price of the produced crude oil for use in Thailand not exceeding the average realised price on the crude oil exported outside the Kingdom by all concessionaires in the preceding calendar month. For produced natural gas, the concessionaire must set the price in accordance with that prescribed by the Petroleum Committee and the Minister, which must not exceed the exporting price.
Prices include taxes (excise tax, municipality tax, and VAT) and contribution payments made to the Oil Fund. Traders can gain profit from internalising marketing costs.
A PSC contractor is bound by a PSC to sell the produced crude oil at the usual market price when the crude oil is sold for local consumption. However, in selling the produced natural gas, a PSC contractor is bound to collaborate with DMF and cannot sell its natural gas share in contradicting the selling method agreed with DMF.
Retailing natural gas prices are determined by the competitive market. The price includes the natural gas price, determined by the Ministry of Energy, acquired through a firm or a non-firm gas sales agreement. Costs associated with gas supply and wheeling services are incorporated into the retail price.
There is no specific tax regime for midstream/downstream operations, except for the general income and consumption taxes.
PTT PLC enjoys some benefits of a state enterprise having the Ministry of Finance as its major shareholder with a Royal Decree Stipulating the Power, Rights, and Benefits of PTT B.E. 2544 (2001) as amended. This includes the right to receive the national budgetary subsidies under certain conditions such as subsidies for the project providing the public services.
The licensee under the Fuel Trade Act and/or the Fuel Control Act is required to be a company incorporated under Thai laws.
Midstream/downstream operators are typically required to obtain licences from both the Fuel Control Act and the Fuel Trade Act. Key requirements include submissions of the monthly volume accounts and storage location and three-months business plan regarding the import, purchase, refining, production and distribution of fuels, and annual fees.
Not applicable to midstream/downstream.
A concessionaire and a PSC contractor shall have the right to store and transport petroleum they produced from the awarded concession and the PSC. Storage and transportation of petroleum shall be in accordance with the provisions stipulated in the concession and the PSC. Persons other than a concessionaire and a PSC contractor who desire to carry out oil and gas production are subject to regulatory requirements under the Fuel Trade Act B.E. 2543, which requires any person being a fuel transporter of the type and volume prescribed by the Minister to submit information in accordance with the forms prescribed by the Director General of the Department of Commercial Registration.
Natural gas network system operators are obligated by the Energy Industry Act to provide equitable access to their natural gas network system for other energy licensees. They are also required to establish TPA (Third Party Access) Codes, taking into account the pre-existing rights of energy business operators on a “grandfathered” basis as a crucial factor.
Any person storing, refining and distributing petroleum products is required to obtain licences under the Fuel Trade Act and/or the Fuel Control Act. The type of licences and restrictions depend on the kinds of business activities conducted.
The Minister is empowered under Section 8 of the Fuel Trade Act to condition any trading operations as deemed appropriate to be observed by a fuel trader necessary for the benefits of national security, prevention and remedy of fuel shortage, such as specifying the port of custom eligible to export fuels. DOEB, under Section 24 of the same, can order a trade embargo to prevent shortages; this happened in 2009 during a halt in the fuel production in the Gulf of Thailand.
The licences under the Fuel Control Act are transferable. Certain licences under the Fuel Trade Act are not transferable.
The Petroleum Act does not place any statutory limit on a foreign investor for a concessionaire, a PSC contractor, or an SC contractor. It only requires the operator to be a company and have capital, machinery, tools, equipment and experts sufficiently to explore, produce, sell and distribute petroleum. In practice, a company incorporated aboard can apply to compete in the bidding round.
Thailand does not adopt any sanctions to investment aboard.
Implementing the precautionary principle, laws governing energy businesses and natural resources exploitation require operators to conduct an environment impact assessment (EIA). According to the Enhancement and Conservation of the National Environmental Quality Act B.E. 2535 (1992) (the “Environmental Conservation Act”), the Minister of Natural Resources and the Environment can declare activities or projects to require an EIA report. An EIA report must be submitted to the Office of Natural Resources and Environment Policy and Planning (ONEP) for approval from an expert committee. The Minister cannot grant petroleum concession, PSC, or an SC unless an EIA report is approved by the ONEP.
Non-compliance with the EIA requirement is a criminal offence. The Environmental Conservation Act explicitly recognises civil liability for damage caused by a pollutant. The owner or possessor of the sources of the leakage or dispersion of pollutants causing death, harm, injury, or property damage to persons or the state shall be liable to provide compensation, regardless of the wilful act or a negligent act of the owner or possessor.
For petroleum businesses, the operator is bound to take appropriate measures in accordance with good petroleum industry practice to prevent any place from being dirty with oil, mud or any other substances. In case of failure or delay to comply, DMF or persons assigned by DMF may remedy such dirt on behalf of or jointly with the concessionaire at the concessionaire’s sole expense.
The Petroleum Act does not provide a definition of the term “good petroleum industry practice”. However, DMF views an obligation of good petroleum industry practice as means to place environmental obligations upon the operator. In the Council of State Ruling No 420/2557, DMF explicitly opined that it is “vested with statutory powers” under the Petroleum Act to ensure that the operator strictly complies with good petroleum industry practice and preventive and remedial measures in an approved EIA report.
The Notification of the Ministry of Energy on Criteria and Procedures on Petroleum Exploration, Production, and Conservation of Petroleum B.E. 2555 (2008) establishes an ex-ante regulatory framework requiring an operator carrying out exploration and production activities to submit details on operational activities including environmental management measures to DMF, which may request additional detail.
It also requires operators and sub-contractors to properly seal the exploration wells, control the liquid flow to prevent potential leakage, and prevent any contamination to underground water reservoirs. A petroleum producer is responsible for installing any appropriate flow measurement equipment in accordance with the American Gas Association (AGA) Standard and the American Petroleum Institute Standard (API).
In case of an accident which can cause an impact on petroleum operation, the operator must notify DMF within 24 hours and submit details of such event within 72 hours from its occurrence.
Petroleum production within 12 nautical miles from the baseline must refrain from directly dismissing rock fragments and liquids resulting from the production to the sea. An operator of an offshore petroleum project is responsible for injecting liquids resulting from the production for storage.
A petroleum producer, whether onshore or offshore, owes a duty to design and construct a production platform, petroleum installations, and other relevant infrastructures according to good petroleum practice. For the offshore project, the operator must submit a 15-day advance notification with details on an approved construction drawing and other relevant technical details to DMF prior to relocation of the production platform.
In addition to the EHS requirements under the Petroleum Act, the petroleum operator may be subject to the draft Ocean Dumping Act proposed following the London Protocol 1996. Persons dismissing waste or other materials from any human-made installation in the ocean shall obtain approval from the Minister of Transport. The law does not exclude petroleum operators under the Petroleum Act.
“Decommissioning” does not appear in the Petroleum Act. Decommissioning activities are not treated as petroleum operation but E&P operators remain responsible under the technical principles or good petroleum industry practice. The operator owes a duty under Section 80/1 to submit a working plan and estimated demolition cost to seek approval from DMF. Additionally, it must deposit security for the demolition with DMF.
Acceptable decommissioning security includes, with no limitations, cash, a government bond and a letter of guarantee issued by bank. The operator is required to deposit the decommissioning security when, for example, a PSC reaches the last five years.
The Climate Change Act is endorsed by the Cabinet and is currently undergoing the legislative process in Parliament. It imposes statutory duties upon certain business operators including the “energy operator” under the law on energy industry, which is the Energy Industry Act, to submit greenhouse gas (GHG) emission information to the government for the national GHG database. The E&P operator is not an energy operator under the Energy Industry Act.
The onshore E&P operator is subject to environmental obligations under the Public Health Act B.E. 2535 (1992); local governments have the power to issue local ordinances prescribing any businesses including production, storage, refining and transport of petroleum or petroleum products as hazardous to health subject to local rules and conditions for compliance.
Despite being awarded a concession or a PSC under the Petroleum Act, the operator must still comply with local rules and regulations.
The Petroleum Act only governs exploration, production, storage, transportation, sale or distribution of petroleum, which is defined as crude oil, natural gas, liquefied natural gas, by-products and other naturally occurring hydrocarbon compounds in a free state, whether solid, semi-solid, liquid or gaseous. Therefore, it does not directly govern exploration and production of unconventional resources. However, unconventional resources, such as oil shale, are defined as a type of mineral under the Minerals Act B.E. 2560 (2017) (the “Minerals Act”). Consequently, exploration for and production of oil shale is subject to regulatory requirements under the Minerals Act. Any person who intends to apply for an oil shale exploration licence in any locality shall submit an application to the local official in such locality. No person shall undertake the production of oil shale at any place, whether any person has any right in the place of such mining or not, except upon obtaining a concession certificate.
Liquefied natural gas (LNG) is defined as a type of fuel under the Fuel Control Act. Under this law, an LNG storage facility means a premises used for storing and filling LNG. The LNG premises can be used for use of the LNG by the owner, the sale of LNG and LNG storage. In addition, the law also regulates a fuel service station that stores LNG. Under the Ministerial Regulations on Criteria, Methods, and Conditions on Notification, Approval, and Fees Relating to Fuel Business Operation B.E. 2556 (2013), a person desiring to operate an LNG storage facility must obtain an LNG operation licence from the DOEB. It should be noted that location and construction of a premises to be used for LNG storage is subject to the Ministerial Regulations on the LNG Storage Premise B.E. 2560 (2017).
The DMF has attempted to facilitate and regulate carbon storage activities to be carried out by existing petroleum concessionaires. In the absence of special legislation for carbon storage activities, the DMF can regulate carbon dioxide emitted as by-product of petroleum production through the Ministerial Regulations on Petroleum Exploration, Production, and Conservation Criteria and Methods B.E. 2555 (2012). This by-law permits a petroleum concessionaire to use the captured carbon dioxide resulting from its production for enhancing oil recovery. However, it must be noted that it does not permit the existing concessionaire to inject captured carbon dioxide which is not a result of the petroleum production.
Ongoing Petroleum Act Evaluation Project: Carbon Storage Regulation
Although the Petroleum Act was not enacted to directly regulate carbon storage activities, it recognises a right of a petroleum operator under the law to utilise the carbon captured from the petroleum production to enhance the production process.
However, carbon storage exploration and storage of carbon captured from the place or site outside of petroleum exploration are not subject to Section 23 of the Petroleum Act and its regulatory regime.
Arbitration and Decommissioning Disputes
Chevron made its first offshore discovery in the Gulf of Thailand (”Erawan”) in 1973 and started its production in 1981. In 2007, the Petroleum Act was amended by adding decommissioning duties upon the concessionaire. Chevron argued that under the terms of its initial contracts from 1971, it was not liable for such duties. The Ministry of Energy explained that awarded petroleum concession is a contractual obligation between Chevron and the Ministry of Energy and could not triumph the Petroleum Act. This reveals practical challenges of stabilisation enforceability.
A material change to the Petroleum Act took place in 2017, when Section 23 was amended by adding the PSC and the Service Contract regimes. In 2017 (amended in 2021), the Petroleum Committee announced rules for determining suitability of the areas to be awarded a concession, a PSC or a service contract. In essence, these rules are based on proved reserves, probable reserves, and rate of commercial discovery. A service contract will be awarded to permit exploration and production of petroleum in an area with a high amount of proved or probable reserves. An area will lower reserves and commercial discovery rates will be awarded a PSC and a concession respectively.
Current State of the Thai Petroleum Industry
Supplies of upstream operations are currently declining in Thailand. The geological risk in the country has been increasing due to decreased resources and geological difficulties. While, in the past, large exploration and production sites have been occupied, there have been fewer discoveries on many of them recently.
Attempts to provide more flexible investment models, other than concessions for the private sector, have been met with moderate interest. There have been studies and attempts to promote investment in the marginal fields, but standalone production may not be commercially feasible and therefore is not an investment priority for many. These attempts are evidenced in Section 99 bis of the Petroleum Act where it is possible to achieve an up to 90% reduction in royalties. The question arises, however, as to whether these reductions will provide unproportionately high advantages to the private party in the marginal fields and how to assess whether these marginal field operators have already used their best efforts to operate their respective marginal fields. The current Petroleum Act is capable to serve as a basis for incentivising new investment; however, ambiguities and legal interpretation are required for practical implementation.
Stimulus Packages Offered to Maintain Oil and Gas Investment
Investment in the petroleum industry is governed by several bodies of legislation, mainly the Petroleum Act. The general law governing the investment incentive is the Investment Promotion Act B.E. 2520 (1977) as amended (the “Investment Promotion Act”).
The Investment Promotion Act provides different levels of privileges depending on the type of business activities. In the past, there were privileges granted to concessions. However, with the shift towards a more sustainable trend, the privileges are granted mostly to downstream markets including the following:
The level of privileges granted varies depending on the type of business activities. The most common privileges include:
The duration of these privileges will also depend on how amenable the government is to supporting them. The duration may range from three to 13 years depending on the types of business activities involved. Additionally, carbon capture and storage are among the businesses receiving the privileges under the Investment Promotion Act. It is noted, however that the carbon capture and storage business is not currently licensable or considered as a regulated petroleum business under the Petroleum Act. Its applicability in practice therefore remains uncertain.
An investor may be awarded investment privileges under the Investment Promotion Act; however, at the operational level, it has remained unclear whether operational activities, especially injecting carbon dioxide captured outside of a petroleum exploration and production blocks into a depleted reservoir, will be awarded such privileges. A question arises to determine whether this is an “unregulated matter” or a regulated matter and this uncertainty has caused negative impacts on investment decisions, as well as bankability of a carbon storage project in Thailand.
The Intention of the Petroleum Act and its Effectiveness Assessment
The Petroleum Act is applied for the purpose of granting rights and regulating the exploration, production, storage, transportation and distribution of petroleum in Thailand. Territorial scope of the Petroleum Act includes the continental shelf that is within the control of Thailand as a coastal state under the international principles of relevant international treaties and conventions. Petroleum businesses are considered a means for energy security, thus contributing to public interest. As part of an attempt to generate national income, provide energy security for the people, and mitigate the environmental impacts on the petroleum industry operations, the Thai government authorises petroleum exploration and production through the Petroleum Act in forms of concession, the production sharing contract (PSC), and the service contract (SC).
A three-option model has been developed to enhance the capability of the upstream regulation regime to respond to, as well as to incentivise, investment in upstream petroleum projects in different geological areas. An area with less geological risk will be subject to the SC regime, whereas an area with difficulties in exploration for, or production of, petroleum is subject to the PSC and the concession regimes respectively. In essence, a concessionaire and a PSC contractor will be granted the right to exploit resources and provide benefits to the government in return. These benefits may come in the form of concession fees, royalties, taxes or the other returns under the law. The relevant environmental standards, including decommissioning requirements, must also be complied with.
In light of the draft amendment to the Petroleum Act, the drafters must assess its intention and its effectiveness. To assess the effectiveness of the law, there a balance must be struck for proportionality between the burden on businesses and people, as well as the costs for the government to regulate the petroleum industry. The costs incurred by the government must not be disproportionately high and the government’s income must be at a rates that is still attractive to corporations. DMF must also regulate the petroleum industry fairly without prejudice. However, if the income from the petroleum industry is too low and if the DMF fails to effectively regulate the petroleum industry, it will affect the public at large economically, socially, and environmentally. In addition, the private sector participating in the petroleum industry is provided with clear regulations and legal certainty from the government ensuring their rights to conduct business operations. Therefore, the enforcement of the Petroleum Act is more beneficial than burdensome to the public.
Draft Amendment to the Petroleum Act in Progress
The draft amendment to the Petroleum Act is currently in its early stages; only academic results published by a research team from Chulalongkorn University have been made publicly available. In summary, there are nine primarily concerns highlighted by the research team.
The DMF has attempted to facilitate and regulate carbon storage activities to be carried out by existing petroleum concessionaires. In the absence of special legislation for carbon storage activities, the DMF can regulate carbon dioxide emitted as by-product of petroleum production through the Ministerial Regulations on Petroleum Exploration, Production, and Conservation Criteria and Methods B.E. 2555 (2012). This by-law permits a petroleum concessionaire to use the captured carbon dioxide resulting from its production for enhancing oil recovery. However, it must be noted that it does not permit the existing concessionaire to inject captured carbon dioxide which is not a result of petroleum production.
The carbon capture and storage business where the act of carbon capture and storage falls outside the scope of the “petroleum business” widens a legal gap for the possibility of the concessionaires to store captured carbons within a reservoir. This limitation currently acts as a legal barrier to the government’s commitment to carbon neutrality, which inevitably needs carbon storage.
To address this legal issue and to modernise the Petroleum Act, the Thai government has commissioned the drafting of an amendment to the Petroleum Act which will include elements of the storage of carbon captured from a carbon-producing area outside of petroleum blocks. This would mean that the existing facilities will not need to be decommissioned, but a modification may be required. Given its technical capability, the DMF is recommended as the key regulator to act as a one-stop-service state agency for all the licence requirements to ease the private party’s burden to operate a carbon capture and storage businesses.
The research team is tasked with revisiting the exploration and production of petroleum regime regarding the employment of the concession, the PSC and the SC regimes. It is generally accepted that these systems may be required to be implemented, but they should be adjusted to ensure the project’s feasibility. The details are yet to be provided to the public.
The next key point of the amendment is the plan to include the licensing scheme details as well as amending the duration of the concession, the PSC and the SC to be more commercially feasible. The intentions are to ensure an uninterrupted energy supply to the country, as there is typically a gap or halt in production during the transition, and to address the depleting supplies of the reservoir that has been in operation for an extended period. It is possible that a one-time extension order under Section 26 of the Petroleum Act will be removed from the law.
The research team is assessing the fairness of the dispute resolution mechanisms in respect of disputes relating to the revocation of the concessionaire and other compliance by the private parties. The research team is revisiting the concepts related to the Thai arbitrator’s requirements and its implications for foreign investors. A challenge stems from the requirement to adopt the UNCITRAL model through an arbitration institute located in Bangkok, Thailand. This institute may prefer to use its own arbitration rules rather than those of UNCITRAL.
There has been a call for the drafters to revise the price regulations for fuel and natural gas pursuant to Section 57 and the Section 58 of the Petroleum Act. It remains unclear, however, how and if this concept will be revised.
The next issue lies with the good petroleum industry practice pursuant to Section 80 of the Petroleum Act. The drafters intend to provide clearer parameters for good petroleum industry practice to provide technical and procedural certainty and limit officials’ use of their discretion.
Next, for the decommissioning of security deposits, a challenge has arisen when an upstream operator is required to make a deposit payment at the end or near-to-the-end of its production. Incoming revenues of the project will be declining at this stage, making it practical for an operator to make decommissioning security payments. It has been academically recommended that a petroleum decommissioning fund can be adopted to replace the current security payment system. The decommissioning fund will have an impact on the Petroleum Taxation Act since monthly payments made to the fund should be deductible expenses.
The final issues relate to the royalty fees and the profit-sharing scheme which private parties are required to pay to the government in the form of various fees, which has been criticized and will also be reviewed. However, according to the research team, it is still necessary to collect royalties on the production of petroleum. The upstream should be developed to allow royalty discount for operational activities that have be in a difficulty situation.
Steps Towards Carbon Neutrality
Bound by its international obligations, Thailand is working on regulating carbon storage exploration and storage of carbon captured from a site outside of petroleum exploration or production blocks in its drafting of the amendment to the Petroleum Act as discussed above. There are other frameworks in place to facilitate Thailand’s work towards carbon neutrality, which includes the Thai carbon credit trading markets. As an overview, Thailand adopts voluntary participation systems, and it is regulated by the Thailand Greenhouse Gas Management Organization (TGO).
It regulates two levels of carbon credits: the T-VERS and the T-CERS.
As the drafting of the amendment to the Petroleum Act is still in the early stages, it is unclear how the DMF, as the regulator of the Petroleum Act, is going to work with the TGO to regulate the carbon credits arising from carbon capture businesses. It is possible that the DMF will be the key regulatory authorising exploration for suitable reservoir and carbon dioxide storage activities, whereas the TGO regulates carbon credit creation procedures.
In addition, as mentioned in relation to investment promotion incentives provided under the Investment Promotion Act, the DMF and the office of BOI should work closely with each other to make sure that awarded BOI benefits will not trigger or cause any liability under the Petroleum Act.