Indonesia: Indonesia's New Gross Split Production Sharing Contracts For The Oil & Gas Industry

Last Updated: 8 February 2017
Article by Benjamin McQuhae, Alex Cull and Darren Murphy

On January 16, 2017, Indonesia took a large step toward eradicating the cost recovery regime for upstream cooperation contracts.

Regulation of the Minister of Energy and Mineral Resources Number 8 of 2017 on Gross Split Production Sharing Contracts ("Regulation 8/2017") sets out a new economic structure for production sharing contracts ("PSC") based on dividing gross production between the state and PSC Contractors, without a mechanism for the PSC Contractor to recover operating costs.

The Minister of Energy and Mineral Resources ("MEMR") is responsible for determining the final form and provisions of PSCs incorporating this new gross split mechanism ("Gross Split PSC"). We have not yet seen a model form Gross Split PSC, but from the provisions of Regulation 8/2017 can draw the following conclusions.

Cost Recovery to be Replaced by a Progressive Sliding Gross Split Mechanism

Unlike existing PSCs, Gross Split PSCs will contain no mechanism for PSC Contractors to recover sunk costs before production is shared with the State. The required capital for operations is to be fully funded, and the risk of operations is to be fully borne, by the PSC Contractor.

Having said that, operating costs incurred by the PSC Contractor can be taken into account as a deduction against the Contractor's income tax liability. The often-disputed classification of costs as permitted recoverable costs may therefore still be relevant, but it is now in the context of calculating income tax liability rather than allocation of shared production volumes.

The traditional cost recovery mechanism will be replaced by a gross split model that will apply a variable percentage production share on a field-by-field basis, with the split adjusted by reference to the characteristics of the specific field and the revenue generated from the field's production, as follows:

  • The percentage gross split for a field is determined by starting from a base allocation that is then adjusted by "variable" components and "progressive" components in accordance with the Annex to Regulation 8/2017.
  • The base split for oil is 57 percent—43 percent for the state and the contractor respectively. The base split for gas is 52 percent—48 percent for the State and Contractor respectively.
  • The base split will then be adjusted by "variable" components that address specific matters affecting the cost of developing and commercializing the field. These are: (i) the location of the field (onshore or offshore, and if offshore, the water depth); (ii) the type (conventional or unconventional) and depth of the reservoir; (iii) the availability of supporting infrastructure; (iv) whether the field contains heavy oil or the petroleum specification requires additional costs to be incurred due to high levels of carbon dioxide or hydrogen sulphide; (v) the availability of required equipment and goods in the domestic economy; and (vi) whether the field is in the primary, secondary, or tertiary phase of production.
  • A 5 percent uplift to the Contractor's split will also be given for a plan of development that is developed for the first time in a PSC work area—which we interpret to mean the first plan of development under a PSC, at which point the PSC moves from the exploration phase to the production phase. No such 5 percent uplift is available for subsequent plans of development in the PSC work area, or for additional work under an existing plan of development. A 5 percent reduction in the Contractor's share of petroleum may also be applied in certain circumstances.
  • The "progressive" components focus on the revenue generated from the field and adjust the gross split from time to time by reference to the Indonesian Crude Price ("ICP") and the cumulative total production of oil and gas from the field.
  • The Contractor's production share is lifted by increasing increments of 2.5 percent the further ICP falls below US$70 per barrel (capped at a 7.5 percent increase where ICP is below US$40), and is similarly reduced in increments of 2.5 percent the further ICP is above US$85 per barrel (capped at a -7.5 percent adjustment where ICP exceeds US$115). Some further detail is required on how this will be calculated in practice; on a straight reading of the Annex to Regulation 8/2017, as little as a US$0.01 increase in the ICP, for example, could trigger a 2.5 percent reduction in the Contractor's percentage production share, leaving the Contractor significantly worse off.
  • The PSC Contractor will also receive an adjustment in its favor when a field is first producing, and as cumulative production from the field increases, that favorable adjustment reduces until it ceases once cumulative production reaches 150 MMboe.
  • The percentage gross split to be applied to a field will be determined at the time the plan of development for that field is approved.
  • If a field does not achieve a specified economic result, then an additional share of up to 5 percent may be allocated to the PSC Contractor. If a field exceeds a specified economic result, the State may take an additional share of up to 5 percent from the PSC Contractor.
  • After commercial production commences, adjustments of the production share may be made if the actual conditions experienced deviate from the variable and progressive components used in setting the production share during field development. Further, adjustments to the crude oil price element of the progressive components will be made monthly based on the results of evaluations carried out by the Special Task Force for Upstream Oil and Gas Business Activities ("SKK Migas"). Such evaluations will be based on the monthly calculation of the ICP.

First Tranche Petroleum and Investment Credits

As a natural consequence of these adjustments, we expect that the Gross Split PSC will also do away with: (i) the First Tranche Petroleum structure, which was designed to ensure the State receives a share of production without having to wait until all approved costs were first recovered from production; and (ii) investment credit allowances, as the variable components are designed to incentivize PSC Contractors to invest in frontier, deepwater, or other high-cost/high-risk areas by giving them a greater share of production to compensate for the additional investment risks and costs.

No Other Fundamental Changes

Regulation 8/2017 does not foreshadow any other fundamental changes to the existing PSC regime. As with the existing PSC structure:

  • Oil and gas remains the property of the State until the delivery point of the production. Data obtained from implementing Gross Split PSCs remains the property of the State, and the existing strict confidentiality and disclosure regulations will continue to apply.
  • SKK Migas retains overall control (but limited to policy formulation toward work plans and budgets) and management (through ensuring compliance with the approved work plan) of operations, and PSC Contractors will still need to prepare work programs and budgets for SKK Migas approval.
  • The 25 percent domestic market supply obligations continue to apply, with payment for crude oil based on the Indonesian Crude Price. Regulation 8/2017 is silent as to the price to apply for natural gas, and we assume this will follow the current practice.
  • Gross Split PSCs are likely to contain standard PSC provisions such as those relating to mandatory relinquishment of working area, minimum work and expenditure commitments, restrictions on assignment, 10 percent Indonesian participation rights (in this regard, no changes appear to be proposed to the provisions set out in MEMR Regulation 37 of 2016), prioritizing domestic labor and goods and services content, conditions for contract extension, and creation of a reserve fund for abandonment and rehabilitation activities.
  • All goods and equipment directly used by PSC Contractors in upstream oil and gas activities become the property of the State, to be developed by the Government and administered by SKK Migas. This implies that, even in the absence of a cost-recovery mechanism, the State is ultimately carrying the costs of those goods and equipment, either by virtue of the deductions to the PSC Contractor's tax liability or the reimbursement is built in to the PSC Contractor's share of production.
  • Certain bonuses will need to be paid to the State. Regulation 8/2017 does not clarify what bonuses will be payable under the Gross Split PSC. We expect a signature bonus may still apply; however, we query whether payment of production bonuses will be required as the progressive components already build in a reduction to the PSC Contractor's gross split as cumulative production levels reach certain milestones. It is possible that production bonuses may be imposed at cumulative production targets in excess of 150 MMboe.


It appears that the new gross production split structure is mandatory for all new PSCs granted on or after January 16, 2017, including for PSCs that have expired and are being replaced.

For those existing PSCs that are expiring and being extended, the original PSC cost recovery and profit split regime may continue to apply, or the new gross split structure can be proposed for the extension period. Those PSCs that were signed before the Regulations came into force can also propose converting the existing PSC to a Gross Split PSC at any time. Any proposed conversion of an extension PSC or an existing PSC into a Gross Split PSC would appear to be subject to gaining approval; however, the Regulations are not entirely clear on the proposal and approval process.

Where an existing PSC converts to a Gross Split PSC, all operating costs incurred but not yet recovered under the previous PSC terms can be added to the gross split in favor of the PSC Contractor's share.

It is not entirely clear how this carrying-forward of unrecovered costs will operate in conjunction with MEMR Regulation 30/2016 and MEMR Regulation 15/2015. MEMR Regulation 15/2015 sets out, among other things, provisions for determining whether the existing PSC Contractor, Pertamina, a different contractor, or a combination of them would be appointed as the contractor for a work area where an existing PSC is expiring and being renewed. MEMR Regulation 30/2016 amended MEMR Regulation 15/2015 so that in the event Pertamina or a third party is appointed as the new contractor to take over the work area under the extended PSC, the new contractor can enter into an agreement with the current PSC Contractor for the funding of operations during the remaining term of the existing PSC until the handover of operations. This was a sensible clarification in order to ensure funds are properly spent in maintaining the safe and effective operation of the work area by an incumbent PSC Contractor who is fully aware that it would not be party to the extended PSC and otherwise would have no means by which to recover costs spent in the final months of operations, and costs incurred pursuant to that funding agreement could be recovered under the new PSC. However, if the extended PSC will take the form of a Gross Split PSC, then the carrying-forward of unrecovered costs is not an option, and we suggest it would be prudent for these costs to be proposed as an adjustment to the gross split percentages when applying for the extended PSC or when the work area is retendered for award.

Partial Repeal of Unconventional Regulations

As a final note, MEMR Regulation 38/2015 on Expediting Non-Conventional Oil and Gas Operations has been partially repealed. MEMR Regulation 38/2015 made provision for three types of PSCs for nonconventional oil and gas operations: (i) a traditional form of PSC; (ii) a form of sliding scale gross production split of a similar form to that introduced under Regulation 8/2017; and (iii) a sliding scale PSC that incorporated a cost recovery mechanism prior to the split of production and where the Contractor's share of production reduced over time as prescribed cumulative production levels were achieved. Under Regulation 38/2015, the Directorate General of Oil and Gas would determine which form of contract would apply.

Regulation 8/2017 repeals those provisions within Regulation 38/2015 that regulated sliding scale gross production split PSCs. However, the remainder of Regulation 38/2015 has not been expressly repealed. The effect of this is not entirely clear. It could be interpreted as meaning that Gross Split PSCs are not available for nonconventional operations, although this would be contrary to the principle embodied in Regulation 8/2017 of moving away from cost recovery mechanisms. Alternatively, it could be interpreted as allowing the Directorate General of Oil and Gas to still determine that any one of the three forms of PSC may apply to a new working area contract for nonconventional resources, and that if a gross production split model is selected, then the provisions of Regulation 8/2017, rather than Regulation 38/2015, will apply to that Gross Split PSC. This would remove certain provisions from Regulation 38/2015 that would still be relevant for Gross Split PSCs for unconventional resources, however, such as those setting out how to determine the petroleum reserves to be used in setting the plan of development and the sale of initial pre-plan of development production to domestic markets (e.g. to facilitate a multi-well pilot production test).

Developments in this area should be monitored.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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