The Coming Decommissioning Wave in Southeast Asia: What to Expect and the Relevance of Experiences in the North Sea and U.S. Gulf of Mexico

1. What is decommissioning?

Essentially, decommissioning, in the context of oil and gas assets, is the dismantling, removal and disposal of the structures forming part of those assets and their associated infrastructure, along with plugging and abandoning the underlying wells and restoring the sites. The process begins when an asset ceases to produce hydrocarbons (or production is deemed uneconomic) and a decision is taken by the project participants to decommission such assets in accordance with applicable regulations. Following the cessation of production, the asset must be physically disconnected from any reservoir and action taken to ensure that the reservoir itself is isolated from the environment or, as referred to in the industry, plugged and abandoned. All equipment on the asset must then be cleaned in order to reduce hazards associated with decommissioning such as removal of hydrocarbons, hazardous waste, asbestos, etc. Equipment that will not be removed from the asset site must be cleaned and secured to ensure that it does not pose a threat to the environment post-completion of the decommissioning work.

The next stage in the process is perhaps the most challenging from a technical perspective, particularly in the context of offshore decommissioning—removal of the asset. This stage typically involves the removal of jackets and topsides as well as pipelines and other subsea infrastructure. This is executed by the deployment of one (but frequently a combination) of three key techniques:

• Reverse of installation – essentially the module installation process in reverse but with additional preparatory works being required to separate and dismantle the modules in separate pieces.
• Single lift – removal of complete modules by way of specialist vessels.
• Demolition in situ – specialist teams placed on the asset to dismantle it using industrial demolition equipment (e.g., hydraulic shears).

The work undertaken during the removal phase requires the use of specialist marine vessels with suitable lifting capacity (e.g., heavy lifting cranes), facilities to support diving activities and Remotely Operated Underwater Vehicles (ROVs)².

Finally, once removed, all recovered equipment and infrastructure must be disposed of in a manner that ensures protection of the environment and regulatory compliance. Additionally, certain jurisdictions (such as the U.K., for example), require parties to monitor the sites in order to ensure that no issues arise after all decommissioning activities have been completed³.

Advanced planning is critical for ensuring the successful implementation and delivery of a decommissioning project. In stark contrast to other oil and gas projects, decommissioning generally provides no return on investment, and rewards for operators are largely limited to satisfaction of fulfilling their legal and social responsibilities, in addition to preservation of the environment. A successful decommissioning project is generally regarded as one that has been completed in a safe and cost-effective manner, with minimal environmental impact.

2. Southeast Asia – Where are we now?

Despite the vast scale of decommissioning work expected to be undertaken over the course of the next decade, activity in Southeast Asia has, for the most part, been relatively limited. Brunei Shell Petroleum undertook limited decommissioning work towards the end of the 1980s, while Malaysian national oil company Petronas decommissioned its first asset in 2003, followed by several more assets using the “rigs-to-reef” (RTR) solution (see further details below) in 2017.

Thailand, which is generally considered the most developed nation in the region in terms of decommissioning regulation (see below), has perhaps the biggest challenge given the number of assets approaching end of life. Thailand has also been the setting for the first high-profile dispute regarding, potentially, $2 billion of decommissioning liabilities for the Erawan gas field. The country’s Energy Ministry reported that it had set a target of March 2020 to resolve the dispute between PTTEP, Thailand’s state-owned operator, and Chevron. The dispute also has implications for France’s Total SA and Japan’s Mitsui & Co. and their respective decommissioning liabilities in the Bongkot field, estimated at approximately $1 billion⁴.

In Indonesia, approximately 75 percent of the some 450 offshore platforms are more than 20 years⁵ old and nearing the end of production. Recently, Pertamina, Indonesia’s state-owned integrated oil and gas company, has entered into deals to acquire a number of mature assets (most notably the Rokan Block which Chevron had been operating since 1971⁶), further exposing them to inevitable decommissioning obligations.

3. International regulatory framework

The first international attempt to codify rules concerning offshore decommissioning in international waters came through the 1958 United Nations Geneva Convention on the Continental Shelf (“Geneva Convention”), which provided that signatories were required to remove all offshore installations at the end of field life. The Geneva Convention was effectively superseded by the 1982 United Nations Convention on the Law of the Sea (UNCLOS), which adopted a revised approach to decommissioning, with partial and, to a lesser extent, no removal being permitted provided that “generally accepted international standards established in this regard by the competent international organization⁷” are taken into consideration.

It is widely accepted that the non-binding International Maritime Organization Guidelines and Standards of the Removal of Offshore Installations and Structures on the Continental Shelf and in the Exclusive Economic Zone (“IMO Guidelines”) are the “generally accepted international standards” referred to in UNCLOS. The default position under the IMO Guidelines is entire removal, except where non-removal is evaluated to be consistent with the IMO Guidelines in terms of navigational safety, deterioration rate, technical feasibility and risk of injury. Indeed, the IMO Guidelines contain the following specific provisions relating to the removal/non-removal of offshore installations, setting out specific criteria in terms of water depth and weight of the installations in question:

• All abandoned or disused installations or structures standing in less than 75m of water (from January 1, 1998: 100m) and weighing less than 4,000 tons in air, excluding the deck and superstructure, should be entirely removed.
• Notwithstanding this, where entire removal is not technically feasible or would involve extreme cost, or an unacceptable risk to personnel or the marine environment, the host government may determine that it need not be entirely removed.
• In cases of partial removal, an unobstructed water column sufficient to ensure safety of navigation, but in any case not less than 55m, should be provided for any structure that does not project above the surface of the sea.

The UNCLOS has been signed by each of the ASEAN nations (with the exception of Laos which is landlocked) and ratified by all but Cambodia.

The international community has also sought to address the specific issues of marine pollution and dumping of waste, which are both major concerns in the context of decommissioning. The 1972 Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (“London Convention”) (and the accompanying 1996 London Protocol) provides that contracting states agree to:

“take all practicable steps to prevent the pollution of the sea by the dumping of waste and other matter that is liable to create hazards to human health, to harm living resources and marine life, to damage amenities or to interfere with other legitimate uses of the sea.”

The London Convention (updated by the 1996 London Protocol) contains a general prohibition on dumping, with the exception of items on a “reverse list,” which includes “vessels and platforms” and “bulky items primarily comprising iron, steel and concrete.”

During their twenty-second consultative meeting in 2000, the London Convention contracting states adopted a series of guidelines entitled Specific Guidelines for Assessment of Platforms or Other Man-Made Structures at Sea (“London Convention Guidelines”). The London Convention Guidelines set out a series of factors to be considered / addressed when considering the disposal of offshore installations, including:

• Options for the disposal of offshore installations when they reach end of life, ranging from re-use, to recycling or scrapping, to final disposal.
• Development of a pollution prevention plan that includes specific actions relating to the identification of potential sources of pollution.
• Analysis of the potential adverse effects to the marine environment from offshore installations proposed for disposal at sea.
• The principal components of platforms or other man-made structures (steel or concrete) are not an overriding concern from the standpoint of marine pollution. However, these installations may contain a number of potential sources of pollution that should be addressed when considering management options.
• Contaminants that are likely to cause harm to the marine environment should be removed from the platforms or structures prior to disposal at sea.
• Determination of the suitability for sea disposal of offshore installations should be considered in the context of the potential impact on existing and adjacent marine habitats and communities.
• Monitoring is undertaken in order to verify that permit conditions are complied with and that any assumptions made during the permit review and site selection process were correct and sufficient to protect the environment and human health.

While a number of regional conventions have been developed to work in tandem with UNCLOS, the IMO Guidelines and the London Convention (such as the Convention for the Protection of the Marine Environment of the North East Atlantic 1992 (“OSPAR Convention”) and subsequent OSPAR Decision 98/3, which provide a European framework for intergovernmental cooperation on dumping), no such action has been taken in Southeast Asia. However, in 2012 the ASEAN Council on Petroleum (ASCOPE) (the association of national oil companies in ASEAN) published the ASCOPE Decommissioning Guidelines (ADG) in an attempt to provide a technical reference document for decommissioning in the ASEAN region and expand on the general principles set out in UNCLOS and the IMO Guidelines. The ADGs have been mutually approved by the national oil companies of the ASEAN nations and are intended to compliment national decommissioning procedures, rather than replace them. The ADGs reiterate the positions of UNCLOS and the IMO Guidelines in respect of offshore platforms. However, the ADGs have gone a step further in addressing pipelines, which are, in fact, not specifically addressed, by either UNCLOS or the IMO Guidelines. The ADGs assume that export pipelines will be left in situ, provided that there is no history of pipeline spanning, or movement of the seabed.

While the development of the ADGs is certainly a positive step, ASCOPE appears to have undertaken little further work in encouraging either their implementation, or the development of more sophisticated national decommissioning legislation in the ASEAN member nations.

4. What are the challenges and pitfalls in Southeast Asia?

Southeast Asian nations are faced with a common set of challenges in the field of decommissioning. Certain of these, such as environmental and financial issues, also apply generally in respect of more mature decommissioning basins. However, Southeast Asia faces its own hurdles that must be addressed for decommissioning projects to be executed effectively in the region.

a. Lack of developed and consistent regulatory framework

According to the Boston Consulting Group, a nation requires a strong regulatory foundation for decommissioning in order to achieve three key objectives, namely:

1. Enabling the most prudent and efficient use of public funds.
2. Creating incentives for operators to maximize and continually improve their performance, in terms of both cost-efficiency and environmental compliance.
3. Allowing supply chain participants to play an active role in developing the solutions and technologies needed in each basin⁸.

Across Southeast Asia, the decommissioning industry is still at a relatively embryonic stage and legislation remains underdeveloped for a complex sector that requires strict regulation. Any introduction of new, more rigorous, legislation poses questions for holders of existing concession agreements, or production share agreements (PSCs). This is particularly so in respect of the possibility of new laws applying retroactively and placing increased levels of liability for decommissioning squarely on current operators.

In addition, where concession agreements, risk service agreements, or PSCs, pre-date new legislation, a further question arises as to whether new decommissioning obligations for operators will override any stabilization type provisions in the relevant agreement. Stabilization clauses provide protection for international operators, or contractors, when entering into long-term petroleum agreements (or, potentially, any long-term investment contract) with a state. Although taking a number of different forms (e.g., a “freezing clause”—which prevents the state from making laws which alter contractual obligations throughout the life of the relevant agreement), the basic premise of such clauses is to insulate the international investing party from any adverse changes to a nation’s legal and fiscal arrangements, including changes to environmental and decommissioning obligations. In the context of decommissioning, the question is whether new legislation creating decommissioning and abandonment obligations for operators will override any existing stabilization provisions in concession agreements or PSCs. This will, of course, largely turn on the drafting of the relevant clause and on the enforcement mechanism incorporated into the relevant agreement.

The issue of stabilization style clauses is also relevant from the perspective of bilateral and multilateral investment treaties, typically those between developed and developing countries. Bilateral treaties typically require the contracting states to offer substantive protections to give comfort to investors from the investing state that their investments will not be prejudiced. Bilateral treaties can impose a range of requirements, such as the requirement to provide fair and equitable treatment (FET), protection and security, national treatment (i.e., the investing company will not be treated differently to local companies) and protections in respect of expropriation or nationalization. Taking the FET clause, in particular, as an example, while there is no prescribed definition of the FET principle, it can broadly be explained as fair treatment by host states with regard to the property of foreign nationals investing in the host state. In the event that a change in law regarding decommissioning liabilities was effected and applied retroactively in respect of legacy concessions/PSCs, then whether such laws resulted in a breach of the FET principle would no doubt be an active subject of consideration by the investing party.

We now turn to a review of the specific national decommissioning legislation of the key hydrocarbon producing jurisdictions in ASEAN (namely Indonesia, Malaysia, Myanmar, Thailand and Vietnam).

Indonesia

Regulators in Indonesia have become increasingly focused on decommissioning since implementation of the initial Government Regulation No. 17 of 1974 Regarding Supervision of Implementation of Offshore Oil and Gas Exploration (“1974 Regulations”). The 1974 Regulations required the dismantling of oil and gas installations that are no longer used, in a good workman-like manner, and with notification being made to the Indonesian government prior to abandonment of any well. Historically, Indonesian PSCs were silent on decommissioning obligations, post-1994 however, PSCs began to incorporate broad site abandonment and restoration obligations on the operators, albeit that operators were somewhat protected by having the ability to recover these expenses via the cost recovery mechanism.

Indonesia subsequently implemented the Oil and Gas Law No. 22 of 2001 (“Oil and Gas Law”), which required every PSC to contain provisions dealing with post-operation obligations. The concept of decommissioning obligations was further developed by Government Regulation Number 35 of 2004 (“GR 35”), which included a requirement for operators to allocate funds for satisfaction of post-operation obligations.

The PSC was subject to further amendment in 2008 with the introduction of decommissioning obligations for operators, requiring the removal of all equipment and infrastructure in a manner deemed acceptable to the government and then regulator, Badan Pelaksana Kegiatan Usaha Hulu Minyak Dan Gas Bumi (BPMIGAS)⁹.

In 2010, BPMIGAS introduced guidelines which set out a more detailed process for abandonment and site restoration (ASR), supplementing the decommissioning provisions contained in the relevant PSC. Subsequent Indonesian PSCs have included requirements for operators to set aside decommissioning funds in a joint bank account (i.e., in the name of the operator and SKK Migas (in its capacity as regulator)). Operators would then be able to recover the funds set aside for decommissioning activities by way of the cost recovery procedure set out in the PSC. However, in 2017, the Indonesian government, determined to abandon the principle of cost recovery, moved to a “gross split” mechanism whereby contractors would be allocated a potentially higher percentage share of gross production under new PSCs. Consequently, it was anticipated that the government intends to push all responsibility for decommissioning liabilities onto contractors.

In 2018, the Indonesian Ministry of Energy and Mineral Resources (“MEMR”) issued new regulations specifically addressing ASR obligations. MEMR Regulation No. 15 of 2018 (“Regulation 15/2018”) requires that contractors perform “post-operation activities” on, or prior to, expiry of the PSC, with such activities including dismantling equipment, installations and/or supporting facilities, including well plugging, site restoration and disposal of equipment and installations and/or facilities.

The contractor is required to prepare a post-operation activities plan and submit the same to the chairman of SKK Migas for approval. The plan must include the following as a minimum:

• List of the equipment, installations and/or supporting facilities to be dismantled, as well as provide details of the well(s) proposed to be permanently plugged, and
• The estimated costs associated with the post-operation activities.

Upon approval of the Chairman of SKK Migas, the contractor must deliver an implementation proposal of the post-operation activities to the Director General of Oil and Natural Gas through the Chairman of SKK Migas along with the approved post-operation activities plan for further approval. A contractor which has secured an approval from the Director General of Oil and Natural Gas must immediately start dismantling equipment, installations and/or facilities, including well plugging and site restoration after such dismantling. The contractor must then submit an implementation activity report to the Director General of Oil and Natural Gas no later than 30 calendar days after completion of the foregoing activities.

In addition, Article 11 of Regulation 15/2018 provides that contractors are required to allocate funds for post-operation activities (“ASR Funds”), reflecting those estimated costs set out in the plan submitted to SKK Migas for approval. The ASR Funds must be deposited in a joint account held by SKK Migas and the contractor in an Indonesian state-owned bank. We note that, where a PSC uses the cost-recovery mechanism (i.e., pre-2017), the ASR Funds are treated as cost recoverable. In PSCs using the gross split mechanism, ASR Funds are borne by the contractor and may be deducted by the contractor for the purpose of calculating its income tax liability.

Regulation 15/2018 also states that PSCs that do not contain provisions regarding post-operation activities will be subject to Regulation 15/2018. Consequently, contractors holding PSCs entered into prior to Regulation 15/2018 coming into force are now under an obligation to conduct post-operation activities, as well as making provisions for ASR Funds. This appears to indicate that the Indonesian government now has the ability to unilaterally amend PSCs that were entered into prior to Regulation 15/2018 and impose obligations on contractors in respect of ASR which may not have previously existed. However, as noted above, this may raise some issues in respect of the use of stabilization clauses and the principle, please see our comments above.

Malaysia

In Malaysia, the domestic regulatory framework relating to decommissioning consists of a myriad laws, regulations and guidelines¹⁰, issued by different government agencies, creating a fragmented legal landscape. As a result, operators seeking to undertake decommissioning are required to liaise with various regulators in order to obtain requisite approvals and comply with the processes set out in the relevant laws and regulations. This has the potential to give rise to conflicting interests between government authorities.

Malaysian PSCs require that operators make provision for an “abandonment cess,” or fund, to be paid to Petronas. The operator is responsible for calculating these payments annually and submitting to Petronas for approval. However, the operator has the ability to recover these costs through the cost recovery mechanism, set out in the PSC, which indicates that Petronas will bear the brunt of decommissioning liabilities.

Petronas, the state-owned operator, has been proactive in developing and issuing decommissioning guidelines known as the Petronas Procedures and Guidelines for Upstream Activities (PPGUA), which must be complied with by any party to a PSC in Malaysia. Released in 2000 (and most recently amended in 2013), the PPGUA provides that all proposed decommissioning activities are subject to review and approval by both Petronas and the Malaysian government. The PPGUA also requires that operators submit a decommissioning plan to Petronas during the development phase.

Myanmar

The oil and gas industry in Myanmar is regulated by a series of laws dating back to 1918, largely based on the British legal codes of pre-independence India. The Myanmar Petroleum Concessions Rules, 1962 include some provisions relating to decommissioning. For example, persons engaged in oil and gas activities are required, insofar as possible, to leave the land or water surface in the same condition as before commencement of the oil and gas activities.

However, Myanmar’s government has not issued any specific legislation or guidelines addressing the issue of decommissioning but the 2013 PSC does include a general obligation to remove equipment and installations in a manner acceptable to the Myanma Oil and Gas Enterprise (“MOGE”) (in its capacity as the state-owned entity with responsibility for exploration and production in Myanmar), as well as the performance of site restoration activities in accordance with government rules and industry practice to prevent damage to the public and environment. Pre-2013 PSCs contained little or no provisions addressing the issue of decommissioning and the industry will be closely monitoring how the government proposes to deal with those liabilities in 2022 when the first assets in Myanmar are expected to be decommissioned.

The government of Myanmar has introduced certain measures aimed at addressing the potential environmental impact associated with decommissioning works. The Environmental Impact Assessment Procedure ("EIA Procedure") was published on 29 December 2015 under the Environmental Conservation Law 2012. Under the EIA Procedure, an Environmental Management Plan ("EMP") must be submitted as part of an EIA or IEE Report, setting out the mitigation strategy against any potentially adverse environmental or social impacts. The EMP must include a project description by project phase (pre−construction, construction, operation, decommissioning, closure and post−closure). EIAs, IEEs and EMPs require the approval of the Ministry of Natural Resources and Environmental Conservation. Once approved, the Ministry will issue an Environmental Compliance Certificate (an "ECC"). An ECC includes a condition, amongst other things, to comply with the measures set forth in the EMP.

In 2018, the Myanmar government tabled the new draft Law on Petroleum Exploration, Appraisal and Production (“Draft Petroleum Law”) which contains specific legal provisions addressing decommissioning. The Draft Petroleum Law, which is still under consideration, would, if enacted, repeal the Petroleum Resources (Development, Regulation) Act 1957 and raises the issue of possible retroactive application by the government which would certainly create friction with operators.

The Draft Petroleum Law contains requirements for reporting to, and approval of, MOGE before decommissioning can commence, as well as standards for restoration of decommissioned oil fields, and allocation of liability for decommissioning. A decision regarding the Draft Petroleum Law is expected early in 2020.

Thailand

Thailand has perhaps the most well developed legislative framework for decommissioning in Southeast Asia. The key legislation governing oil and gas in Thailand are the Petroleum Act 1971 (as amended) (“Petroleum Act”) and the Petroleum Income Tax Act 1971 (as amended) (“PITA”).  In 2007, the Petroleum Act was amended to introduce two new sections that gave authority to the Director General of the Department of Mineral Fuels to implement regulations addressing decommissioning activities. Another key aspect of the amended Petroleum Act is the introduction of the general principle that the concessionaire (or PSC contractor depending on the form of contracting model being utilized, see comments below) is required to place a security deposit in order to ensure that it will assume responsibility for the decommissioning works. The value of the security deposit is approved by the Director General and may not be less than the estimated decommissioning costs set out in the approved decommissioning plan (see below). Failure to make payment of the security deposit will render the concessionaire or PSC contractor liable, following written warning, for a two percent surcharge per month that the amount remains unpaid. Following the second written warning, the Minister of Energy has the power to revoke the concession or PSC. Note that the concessionaire or PSC contractor will not obligated to pay the security deposit until one hundred and twenty days have elapsed from:

1. the date upon which the decommissioning plan was approved by the Director General; or
2. the fifth anniversary of the date of commercial production, whichever is later.

The regulations referred to above were introduced in early 2016 by way of the Ministerial Regulation Prescribing Plan and Estimated Cost and Security for Decommissioning of Installations Used in the Petroleum Industry (“Decommissioning Regulations”). The Decommissioning Regulations state that the concessionaire is required to commence the decommissioning process following the occurrence of any of the following:

• When the concessionaire does not use the relevant installation continuously for a period greater than one year.
• When the petroleum reserves of the concession fall below 40 percent of the sum of the accumulated petroleum production and petroleum reserves.
• When the remaining period of production, as specified in the relevant concession agreement, is five years or
• When the concessionaire wishes to commence decommissioning activities.

The Decommissioning Regulations require that the concessionaire/contractor submit, to the Director General, a decommissioning plan (initial and final decommissioning plans), estimation of decommissioning costs, an environmental assessment report and a best practical environmental solution report, all within prescribed timelines.

The concessionaire/contractor’s proposals will then by audited by authorized third parties (based on qualifications prescribed by the Director General) and the Director General has authority to accept or request clarifications and/or amendments in the event that the proposals are non-compliant.

However, despite the issuance of the Decommissioning Regulations, there still exists a degree of uncertainty around decommissioning liabilities and costs associated with assets transferred to the Thai government. Concession and PSC agreements in Thailand typically contain provisions which state that the concessionaire/contractor is required to transfer usable assets back to the government, at no cost, while retaining liability for the decommissioning liabilities associated with said assets, unless otherwise provided for in the asset transfer agreement. It remains to be seen whether concessionaries/contractors will be willing to agree to enter into asset transfer agreements that hold the concessionaire/contractor liable for decommissioning which may only occur in the future following relinquishment of the concession/termination of the PSC.

In 2017, the government approved amendments to the Petroleum Act and PITA which established two new contractual regimes for exploration of oil and gas resources, namely the PSC and service contract. Prior to 2017, exploration and production rights were granted solely by way of concession agreements.

Vietnam

The primary legislation governing decommissioning in the oil and gas industry in Vietnam is the 1993 Law on Petroleum (as amended) (“Law on Petroleum”). The Law on Petroleum was subject to amendment, first in 2000, secondly in 2008 and again in 2015 by way of Decree No. 95/2015/ND-CP (“Decree 95”). Decree 95 included, amongst other amendments, new provisions intended to align Vietnamese decommissioning legislation with UNCLOS, as well as the requirement for operators to establish a “field clearance fund,” designed to be utilized for the satisfaction of decommissioning liabilities.

With Vietnamese production rates showing a steady decline in recent years, certain key mature assets are soon likely to reach the point where production will either cease, or become economically unviable. Operated by the Vietnamese/Russian joint venture, Vietsovpetro, Bach Ho (White Tiger) is Vietnam’s largest single producing field and has been in production since 1986. However, production from the field, which peaked at 267,370 bpd in 2001, has since been in steady decline, leading to claim by Thanh Nghia, general director of Vietsovpetro, that Bach Ho has entered its final stage of production¹¹.

In recognizing that decommissioning poses an imminent challenge for the country’s oil industry, the Vietnamese government issued Decree 95 (as highlighted above) but has since released further guidance by way of Decision No. 49/2017/QD-TTg on Decommissioning of Petroleum Installations (“Decision 49”).

Decision 49 places an obligation on operators of petroleum assets to formulate a “decommissioning plan” in respect of the relevant assets, within nine months of the commencement of commercial exploitation, or within one year of the project first being put into operation, and submit the same to the Ministry of Industry and Trade ("MOIT") for approval. Operators are required to decommission petroleum installations in a manner that “ensures safety of people and environment and complies with requirements for underground protection, environmental restoration, traffic safety and other resources of the sea and mainland where the installations are located.”

In addition to setting out the general principles regarding decommissioning work, Decision 49 also expands on the “field clearance fund” principle introduced by Decree 95. Operators are required to establish the “decommissioning fund” (as it is referred to in Decision 49) within one year from the date of first extraction of hydrocarbons, using the formulae set out in Articles 28 and 36, noting that separate formulae are used for oil and gas projects. Decision 49 also contemplates partial and full retention of petroleum assets in the event that:

1. in the event that removal is not technically feasible;
2. in the event that removal creates potential risk for the public and/or environment;
3. where there are demonstrated benefits of retention (e.g. RTR); and
4. in certain other instances relating to the removal of wellhead infrastructure, pipelines and well casing.

Vietnam’s model production sharing contract, introduced in 2013 (“Model PSC”), also makes specific reference to abandonment and decommissioning obligations. In particular, the contractor is required, no later than nine months from the date of first production, to submit an abandonment plan to the “Management Committee” for approval, after which it must be submitted to Vietnam Oil and Gas Group (“PVN”) for review, followed by MOIT for final approval no later than 11 months from such date. In addition, the contractor is required, no later than 12 months from the date of first production, to establish a fund designed to ensure that sufficient financial resources are available to undertake abandonment operations. Abandonment and decommissioning are discussed in greater detail below.

Under the terms of the Model PSC, title to assets acquired, owned and used by a contractor for “Petroleum Operations in the Contract Area” shall be automatically transferred to PVN when the cost of such assets has been fully recovered by the contractor through the cost recovery mechanism, or on termination of the PSC, whichever is the earlier. If the contractor determines that any assets are no longer required, then PVN has a first right of refusal. In the event that PVN elects not to take on the assets, the contractor may dispose of them on PVN’s behalf, with the net proceeds being passed to PVN on behalf of the Vietnamese government.

The abandonment provisions of the Model PSC provide that abandonment of any “artificial islands, installations, structures, facilities or wells constructed or drilled” by the contractor must be undertaken in accordance with “relevant regulations of Vietnam” (e.g., Decision 49) and in conformity with “General Accepted International Petroleum Industry Practices”. In addition, as discussed above, the Model PSC also contains obligations for contractor in respect of preparation of the abandonment plan and establishment of the abandonment fund.

b. Lack of experienced contractors in the region

As highlighted above, decommissioning is a relatively new concept in Southeast Asia and, consequently, there are a limited number of regional contractors with experience in the sector. The likelihood is that regional players will take a number of years to gain the necessary expertise to tackle the market effectively. In the meantime, the skills and expertise may need to be imported from other regions thereby increasing the cost of decommissioning in Southeast Asia.

Nevertheless, this presents an opportunity for contractors based in other regions (such as the U.K. and U.S.) to export skills and experience to the Southeast Asian market. By way of an example, U.K.-based engineering consultancy, Longitude Engineering, has developed a decommissioning barge concept for PTTEP for the removal of small offshore oil and gas installations. The design utilizes reverse float-over and onboard lifting methods to remove both the topside and substructure by way of the same vessel¹². Equally, there appears to be a growing trend of operators rebranding themselves as mature field specialists (particularly in the North Sea), and it is possible that we will see this replicated in Southeast Asia.

c. Lack of finance

Decommissioning is a costly exercise, particularly where deep-water assets are involved. In the U.K. for example, the Oil & Gas Authority (OGA) recently reported that the estimated decommissioning costs in the UK Continental Shelf (UKCS) would be approximately £51 billion¹³. HM Revenue and Customs in the U.K. estimates that £24 billion of those decommissioning costs will be borne by the U.K. taxpayer as some operators take advantage of tax reliefs (discussed in more detail below), while others simply do not have access to the funds necessary for undertaking decommissioning work¹⁴. In Southeast Asia, as we have seen above, responsibility for decommissioning liabilities is somewhat unclear. However, with mature assets increasingly being acquired by national oil companies across the region, it is becoming more likely that Southeast Asian governments (and then ultimately taxpayers) will be left bearing a significant proportion of likely decommissioning liabilities, estimated in the region of $30 billion–$100 billion.

Insurers, identifying opportunities created in the sector, have started to develop bespoke products specifically designed for decommissioning projects. One of the difficulties associated with developing these insurance products is the nature of the work being performed when an asset is decommissioned. The decommissioning process can, effectively, be described as construction in reverse—this points to insurance products which are substantially similar to a construction all-risks (CAR) policy.

However, a key element of any CAR policy is insurance and replacement of the project assets which are, ultimately, intended to be profit generating. In decommissioning, the intention is to return the site to its original state, albeit that there may be some residual value in the dismantled installations. Consequently, the key risks to be covered by any decommissioning insurance product will be third party loss or damage, as well as environmental liabilities. However, products are now on the market such as Marsh JLT Specialty’s decommissioning policy which is designed to provide “clear coverage for both operator and their contractors operating under largely a “Knock for Knock” contractual basis”¹⁵. The advice from insurers is that “knock-for-knock” contracting (i.e., the principle that each party agrees to hold the other harmless against any claims or liabilities arising in respect of damage to their own personnel and property) is more straightforward to insure, and that this approach should continue when entering into decommissioning service contracts. Decommissioning contains specific risks that insurers and operators need to take into consideration such as heavy lift risk, damage to property not intended for decommissioning (whether owned by the insured or third parties), as well as removal of wrecks or debris.

d. Environmental concerns

A key challenge in the decommissioning sector is ensuring that removal activities are undertaken using methods which minimize the impact on the environment. Decommissioning has potentially large-scale environmental impacts ranging from the loss of biodiversity and destruction of seabed habitats, to the release of hazardous materials which may also pose a threat to human life. Historically, the approach has been to remove obsolete oil and gas infrastructure in its entirety in an attempt to return the seabed to its “pre-oilfield” state. However, a 2018 survey of environmental experts suggested that “partial removal” options may deliver better environmental outcomes¹⁶.

One partial removal strategy, which has been successfully implemented in the Gulf of Mexico, is the RTR model. Essentially, RTR involves the modification of an obsolete platform to enable it to support marine life as an artificial reef. The United States Bureau of Safety and Environmental Enforcement reported that, as of April 15, 2018, 532 platforms previously installed on the U.S. Outer Continental Shelf (OCS) had been reefed in the Gulf of Mexico¹⁷. The RTR strategy has been deployed on a smaller scale by Brunei Shell Petroleum and Petronas on the damaged Baram-8 rig, offshore Sarawak.

5. How can stakeholders safely navigate the decommissioning risks?

There are a number of strategies that can be deployed in order to mitigate the financial risk associated with decommissioning. Wood Mackenzie identified four key principles for delivering Southeast Asian decommissioning projects within budget¹⁸:

• Knowledge transfer – As highlighted above, oil producing nations in Southeast Asia have significant work to undertake both regionally and nationally in order to develop a functional regulatory framework. The regional effort should be led by ASCOPE, firstly to ensure regional adoption of the ADGs and secondly to attempt to draw on the experience of stakeholders in developed decommissioning regions such as the U.K. North Sea or the Gulf of Mexico in creating a regional regulatory framework for undertaking such projects.
• Optimal contract strategy – The implementation of effective project management and contracting strategies are essential elements in managing costs on a decommissioning project. Wood Mackenzie commented that the three most common contracting strategies, lump sum, unit cost and day rate, are suited to different levels of risk. During a decommissioning project, the well plug and abandonment phase is typically considered the riskiest as live hydrocarbons are present, often with poor availability of data regarding well conditions. Therefore, unit cost contracts, where the contractor undertakes well plug and abandonment, or facility removal, at a fixed cost per unit that includes a margin for profit, may be better suited to projects in Southeast Asia¹⁹.
• Adoption of innovative technologies – The oil and gas industry has always been a fertile ground for innovation and this is set to continue as we move into the era of decommissioning. The RTR solution (see above) is more cost-effective than total removal and has the added benefit of creating a habitat for marine life. Southeast Asian nations may also wish to follow the lead of the U.K., which established the National Decommissioning Centre (NDC) in Northeast Scotland in late 2018. The NDC is a technology research and development hub which has been tasked with aiding the U.K. oil and gas industry in delivering the OGA’s 35 percent decommissioning cost reduction target²⁰.
• Economies of scale – Batch decommissioning also presents an opportunity to reduce the costs associated with decommissioning. This approach involves a group of fields being abandoned together, typically selected by way of geographical proximity or common operator. However, the approach has the potential to be extended across multiple blocks, with different operators, thereby increasing the scale of the project and, in theory, reducing unit-decommissioning costs.

6. What can we learn from the U.K. and U.S.?

a. United Kingdom

Overview

The U.K. is (perhaps with the exception of the U.S.) the most developed jurisdiction in the field of decommissioning, from both regulatory and practical experience perspectives. Decommissioning expenditure is currently estimated at £1.5 billion per annum and approximately 9 percent of the offshore platforms installed on the UKCS have been decommissioned to date²¹. The Petroleum Act 1998 (as amended by the Energy Act 2008) (“U.K. Act”) sets out the primary decommissioning requirements in the U.K., as well as implementing the provisions of both UNCLOS and OSPAR.

In terms of decommissioning liabilities, the U.K. Act provides that the Secretary of State may, by written notice (“Section 29 Notice”), require almost any party connected with an offshore installation to submit a decommissioning program for approval. Once a party is in receipt of a Section 29 Notice (noting that multiple notices may be sent to current and legacy participants), it will become liable for all decommissioning costs related to the relevant installation. It is worthwhile to note that divestment of an asset does not necessarily mean release from liability, given that the U.K. government has the ability to “call back” a legacy participant in order to satisfy outstanding decommissioning obligations. However, the government has indicated that it would only exercise this power as a last resort. The Section 29 Notice was perhaps best described by Jim Ayton, Technical Director, Energy, Lloyds Bank Commercial Banking, who called it the “Hotel California” principle—you can check out any time you like, but you can never leave²².

The U.K. oil and gas industry, in an attempt to address the potential for overlapping liability created by the Section 29 Notice, developed decommissioning security agreements (DSAs). Under the terms of a DSA, each participant in an oil or gas development is required to deposit cash (or other form of security) in a trust. The trust established by the DSA then functions as a fund to meet decommissioning costs when required. In the event that the operator fails to meet its decommissioning obligations, the other beneficiaries can utilize the defaulting party’s portion of the trust. The OGA has developed a standard form DSA, but these agreements tend to be heavily negotiated. However, with the true value of decommissioning liabilities often being uncertain, there is a high probability that the funds set aside in DSAs may be insufficient to cover the total cost.

The U.K. has also implemented a controversial tax relief model whereby operators have the ability to claim rebates against decommissioning expenditure. In December 2019, Royal Dutch Shell announced that it had received a £60 million tax rebate from the U.K. government directly linked to decommissioning the Brent Field. The legal basis for the rebate is set out in an agreement known as a Decommissioning Relief Deed (DRD), typically entered into between individual participants (whether operators or licensees) in U.K. oilfields and the U.K. government. DRDs provide that, in certain circumstances specified in the DRD, if the amount of tax relief in respect of any decommissioning expenditure incurred by the relevant company is less than an amount determined in accordance with the DRD, then the difference becomes payable to the company. The DRD serves to provide certainty for participants in oil and gas projects as to the tax relief they will receive when undertaking decommissioning of assets.

Standardization of contracts

Other recent developments in the UKCS include the release of standard decommissioning contracts by both LOGIC (a subsidiary of Oil & Gas UK, focused on standardization of contracts in partnership with industry) and the Baltic and International Maritime Council (BIMCO) which hope to encourage standardization and cost-reduction in a market where an estimated £15.2 billion is anticipated to be spent on decommissioning assets located on the UKCS over the course of the next decade²³. These standard form contracts address the dismantling, removal and transport to shore of all forms of offshore infrastructure. However, although potentially instructive, we see difficulties in a similar standardized approach being adopted in Southeast Asia, not least due to the fact that each jurisdiction adopts its own nuanced approach to decommissioning.

New players

In recent years the UKCS has seen an increase in the volume of mergers and acquisitions (M&A) transactions in upstream oil and gas. However, the identity of the buyers in these transactions has shifted from traditional oil majors and independents to private equity. In 2016, Siccar Point Energy, a North Sea focused E&P company backed by funds managed by Blue Water Energy and Blackstone Energy Partners, acquired the North Sea assets of Austria’s OMV in a $1 billion deal—the largest M&A transaction in the UKCS following the 2014 oil price collapse. In the following two years, more than $12 billion of private equity cash poured into the North Sea as major private equity houses, such as Carlyle Group and CVC Capital Partners, began to snap up mature assets²⁴. As we have highlighted above, the current trend in Southeast Asia points towards mature assets being acquired by national oil companies across the region. It remains to be seen, however, whether the private equity players who have invested heavily in the UKCS will identify similar value in upstream Southeast Asian assets.

Another interesting development in the UKCS is the conversion of Fairfield Energy, a private equity backed U.K. operator, to fully fledged “late-life asset and decommissioning operator.” Fairfield Energy was established in 2005 with the aim of acquiring North Sea assets being put on the market by majors and continue their development. After some success in acquiring a number of assets, the 2014 oil price crash halted any further development and Fairfield’s management was forced to rethink. In 2015, the company reinvented itself as a decommissioning specialist and commenced work on its own assets in the Greater Dunlin Area. Fairfield has now established a joint venture with Heerema Marine Contractors and AF Offshore Decom to provide a fully integrated, end-to-end solution to late-life operations and decommissioning. It remains to be seen whether Southeast Asia will attract similar new players.

b. United States

As previously mentioned, decommissioning is a key component in the life cycle of assets in the oil and gas industry, and the U.S. has been at the forefront of the creation and implementation of a regulatory framework that incentivizes private companies to carry out activities in the sector in an efficient and environmentally sustainable manner. U.S. federal law governs oil and gas activities offshore and in federal lands, while applicable state laws govern oil and gas activities conducted in private or state onshore lands and within state territorial waters. In the decommissioning context, this means that the location of the relevant facilities determines the applicable decommissioning jurisprudence.

Offshore Decommissioning

Today, more than 3,700 active platforms and related structures exist in the U.S. Outer Continental Shelf, with more than 30 percent of such structures having been placed in service more than 25 years ago and in sight of the end of their useful life. ²⁵ However, during the past decade, industry participants have only averaged approximately 130 platform decommissioning projects per year, and while the downturn in the oil and gas industry over the past five years along with a large number of oil and gas company bankruptcies and more costly decommissioning requirements has retarded the growth in decommissioning projects, over the longer term, the number of new decommissioning projects is expected to increase significantly.

With respect to federal offshore activities, the Outer Continental Shelf Lands Act of 1953 (OCSLA) is the key legislation governing the offshore oil and gas industry in the U.S. OCSLA tasks the U.S. Department of Interior (DOI) with the management of all natural resources located within federal lands and the OCS. In turn, the DOI has delegated its authority to certain agencies depending on the location of the resources. After the Deepwater Horizon tragedy in the Gulf of Mexico in 2010, which lead to a groundswell of public support to reform the offshore oil and gas industry, including the need to decommission idle wells and idle platforms that could contribute to future environmental disasters, DOI generally restructured this process. Today, for offshore oil and gas activities, (i) the Bureau of Ocean Energy Management (BOEM) is tasked with promotion of energy independence, environmental protection and economic development of energy and mineral resources in the OCS, and (ii) the Bureau of Safety and Environmental Enforcement (BSEE) with the regulation and oversight of worker safety, decommissioning and environmental compliance.²⁶ OCSLA’s implementing regulations establish the obligations to which operators and leaseholders must commit to obtain and maintain an OCS lease (the document whereby the U.S. federal government grants mineral rights for private parties to explore, develop and produce oil and gas), including decommissioning obligations. Owners and operators of an OCS lease bear joint and several liability for all exploration, development, production, plugging, abandonment and decommissioning operations. At the front end, BOEM establishes the financial securities, or bonds, that all operators and/or leaseholders must provide in order to secure their offshore oil and gas activities, including decommissioning, based on the development stage of, and the activities to be conducted on, the OCS lease (i.e., level of activity being undertaken through the OCS lease) or the surface area within the OCS (i.e., level of activity across numerous OCS leases within an area)²⁷. Thereafter, upon determining the required work to decommission facilities in accordance with applicable laws, BOEM reassesses the lessees’ financial and operational ability to carry out such lease obligations, and, if necessary, may request lessees to provide a supplemental bond to adequately secure their decommissioning obligations. This analysis takes into consideration several factors, including each lessee’s financial capacity, projected financial strength, business stability, credit ratings, debt to equity ratio, net worth, reliability, estimated plugging, abandonment and decommissioning costs, and the record of performance and compliance with BOEM and BSEE.²⁸ This framework allows the government to organically regulate offshore oil and gas activities and ensure that lessees will be able to meet their obligations without imposing inefficient or cumbersome requirements that do not take into consideration their past, current and future financial and operational profiles.

Once oil and gas facilities are no longer useful for operations, operators must submit decommissioning applications to BSEE, which manages the actual decommissioning process, including the plugging and abandonment of wells, removal of all platforms, facilities and pipelines, and clearing of the seafloor of all obstructions created by the oil and gas operations.²⁹ BSEE works closely with operators/lessees to design and implement the best decommissioning solution, including reusing obsolete structures to create artificial reefs in U.S. waters using the RTR model described above.³⁰

It is important to note that OCSLA gives BSEE broad authority to impose decommissioning obligations on any party that is or was a lessee or operator of any well, platform or other facility. In recent years, as several companies have found themselves without the financial capability to conduct expensive decommissioning operations and either declare bankruptcy or simply abandon their facilities without completing a proper decommission, BSEE has held solvent predecessor companies responsible for decommissioning costs, regardless of the remoteness of their link to a given structure. This has had the effect of substantially increasing the potential exposure for predecessor oil and gas producers which may have sold assets decades ago to now-bankrupt companies and find themselves to be the “last-man standing” as the U.S. government seeks companies with large balance sheets in the chain of title to meet decommissioning liabilities. Accordingly, it is now more important than ever for oil and gas companies to take the necessary steps to protect their interests and minimize their future exposure, including requiring successor companies to provide parent guarantees or other collateral to secure such obligations.³¹

Onshore Decommissioning

There are two main factors that create different challenges for operators/lessees as it relates to the decommissioning of onshore assets in the U.S.: first, the lessor may be any of the federal government, an Indian tribe or private individuals, and working with each can mean, potentially, that an operator/lessee assumes different responsibilities within the same leasehold area, and secondly, the federal government and each state within the U.S. has its own set of regulations governing oil and gas activities within its jurisdiction, which can thus require an operator/lessee to be required to adhere to varying decommissioning requirements.

For onshore oil and gas activities on U.S. federal government lands, the DOI has tasked the Bureau of Land Management (BLM) with the monitoring, administration and management of oil and gas activities, including decommissioning. For onshore oil and gas activities on Indian lands, the BLM, in consultation with the Bureau of Indian Affairs, is charged with the monitoring, administration and management of oil and gas activities, including decommissioning. Federal regulations require operators to include a reclamation or decommissioning plan with every application for permit to drill, and to promptly plug and abandon oil and gas wells, remove facilities and reclaim sites after they stop producing in paying quantities.³² Companies must provide bonds at the outset to cover reclamation, but if they fail to properly decommission the site, or if costs are higher than anticipated, the BLM may be liable.³³

As mentioned previously, with respect to private or state-owned onshore lands, each oil or gas producing state within the U.S. will have its own set of regulations governing oil and gas activities within its jurisdiction. Accordingly, decommissioning requirements can vary from state-to-state; for example, in some states, such as Texas and Louisiana, where there is a long history of oil and gas production, in general, the state decommissioning requirements can often be less burdensome than the decommissioning requirements under U.S. federal law or in other states with little history of oil and gas production.

In Texas and Louisiana, the Texas Railroad Commission and the Louisiana Department of Natural Resources, respectively, are in charge of regulating all oil and gas activities within their respective states, including decommissioning, and the Texas Commission on Environmental Quality and the Louisiana Department of Environmental Quality are tasked with supervising, managing and enforcing regulations to mitigate the impact that these activities may have.

State regulations are truly tailored to address local characteristics, challenges and goals. For instance, the geographical, environmental and geological characteristics of potential well sites vary drastically between the west Texas desert and the Louisiana swamplands. Even though most decommissioning regulations are based on similar principles, they have distinctive differences from state to state. In Louisiana, all inactive wells must be plugged and abandoned within five years after the well becomes inactive, while in Texas, operators must commence decommissioning operations within one year after ceasing operations.³⁴³⁵The location of a facility also determines applicable decommissioning permitting requirements that may require security or bonding. In addition to existing decommissioning liability under applicable state laws, both states have decommissioning funds that require owners/operators to pay certain fees on their oil and gas production into a government fund. Those fees are used by the state agencies to decommission wells and facilities where owners/operators are unable to meet their obligations to ensure proper mitigation and restoration of the site. Similar to BSEE at the federal level, if the decommissioning costs exceed the statutory threshold, the state agencies will look at all former operators/owners to recover the entire restoration cost in inverse chronological order.³⁶

7. What next?

The Southeast Asian oil and gas market will undoubtedly see a marked increase in decommissioning activity over the next decade as mature fields reach the end of their life cycle and production depletes. Decommissioning presents a significant opportunity for local oilfield service providers to refine their skills for servicing the market, while at the same time, providing experienced international contractors with a new arena in which to deploy their specialist knowledge and technology.

However, Southeast Asian governments face huge challenges in developing comprehensive legislative frameworks that fairly allocate liability for decommissioning, while at the same time ensuring the investment landscape remains attractive enough to entice upstream companies to invest in Southeast Asian fields that are yet to be developed. Southeast Asia’s decommissioning industry should draw on practices developed in mature markets, such as the U.K. and the U.S., and adapt these in order to address regional challenges. This will be critical in maintaining cost-efficiency in a sector where the bottom line is, as of yet, unknown.

With thanks to DFDL for their assistance with this article.

Akin Gump acknowledges the assistance of the following DFDL personnel in preparing this article:

¹ Energy Voice, “Southeast Asia braces for huge wave of decommissioning,” December 9, 2019.

² Globe Law and Business Limited, “Oil and Gas Decommissioning: Law, Policy and Comparative Practice,” 2nd Ed., 2016.

³ Ibid.

⁴ Reuters, “Thai energy ministry sets March target to resolve Chevron dispute,” October 8, 2019.

⁵ Offshore Technology, “Decommissioning Indonesia’s oil rigs: a vast but challenging market,” February 18, 2015.

⁶ Nikkei Asian Review, “Pertamina wins bid to take major Indonesia oil block from Chevron,” August 1, 2018.

⁷ Article 60(3) of the 1982 United Nations Convention on the Law of the Sea.

⁸ Boston Consulting Group Inc., “Preparing for the next wave of offshore decommissioning”, April 11, 2018.

⁹ Note - (BPMIGAS was disbanded in 2012, with its responsibilities being transferred to the new Upstream Oil and Gas Regulatory Special Task Force (“SKK Migas”)).

¹⁰ Note – such as the Fisheries Act 1985, Environmental Quality Act 1974, Continental Shelf Act 1966, Exclusive Economic Zone Act 1984, Petroleum (Safety Measures) Act 1984, Occupational Safety and Health Act 1994 and Department of Environment environmental guidelines for decommissioning of oil and gas facilities.

¹¹ VietNamNet Bridge, “Experts warn about depletion of Vietnam’s largest oil field,” January 25, 2018.

¹² Offshore Energy Today, “UK firm develops decom solution for Thai operator,” April 16, 2018.

¹³ Oil & Gas Authority, “UKCS Decommissioning: 2019 Cost Estimate Report,” July 2019.

¹⁴ House of Commons Committee of Public Accounts, “Public cost of decommissioning oil and gas infrastructure”, March 27, 2019.

¹⁵ Marsh JLT Speciality, “Challenges in Decommissioning for Operators”.

¹⁶ The Maritime Executive, “Decommissioning: platform removal needs rethink”, January 28, 2018.

¹⁷ Bureau of Safety and Environmental Enforcement, https://www.bsee.gov/what-we-do/environmental-focuses/rigs-to-reefs.

¹⁸ Wood Mackenzie, “Offshore decommissioning in Asia Pacific could cost US$100 billion,” February 1, 2018.

¹⁹ Ibid.

²⁰ Forbes, “Chasing the prize for North Sea oil and gas decommissioning,” January 25, 2019.

²¹ UK Oil and Gas Industry Association Limited, “Decommissioning Insights 2019.”

²² Petroleum Economist and Lloyds Bank, “Decommissioning in the North Sea – fundamentals and financing.”

²³ Ibid.

²⁴ Financial Times, “Private equity leads the changing of the North Sea guard,” February 13, 2019.

²⁵ BSEE, “Decommissioning,” February 25, 2020, https://www.bsee.gov/what-we-do/research/tap-categories/decommissioning.

²⁶ Oil and Gas Decommissioning: Law, Policy and Comparative Practice - United States.

²⁷30 CFR §§ 556.900 & 556.901.

²⁸ Ibid.

²⁹ 30 CFR § 250.1703.

³⁰ BSEE, “Rigs to Reefs.” https://www.bsee.gov/what-we-do/environmental-focuses/rigs-to-reefs.

³¹ Akin Gump Strauss Hauer & Feld LLP, “As Bankruptcy Bells Ring in the Outer Continental Shelf, BSEE May Toll for You,” September 30, 2019, https://www.akingump.com/en/experience/industries/energy/speaking-energy/as-bankruptcy-bells-ring-in-the-outer-continental-shelf-bsee-may.html.

³² 43 CFR § 3162.3-4.

³³ Bureau of Land Management, “ Reclamation Efforts in BLM,” https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/reclamation/new-mexico.

³⁴ La. Admin. Code tit. 43, Part XIX §137.

³⁵ 16 Tex. Admin. Code 3.14(a)(3) & (b)(2).

³⁶ La. R.S. 30:93.