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On 15 June 2017, President Joko Widodo issued Government Regulation No. 27 of 2017 on the Cost Recovery and Income Tax Treatment in Upstream Oil and Gas Business (“GR 27/2017”). GR 27/2017 amends Government Regulation No. 79 of 2010 (“GR 79/2010”), which is the main regulation governing the cost recovery regime in the Indonesian upstream oil and gas industry. GR 27/2017 was issued with the stated purpose of attempting to encourage investment and provide additional legal certainty for the upstream oil and gas industry in Indonesia. However, less than a month after the issuance of GR 27/2017, on 14 July 2017, the Minister of Energy and Mineral Resources (“MEMR”) issued MEMR Regulation No. 42 of 2017 on the Supervision of Business Activities in the Sector of Energy and Mineral Resources (“MEMR 42/2017”) which increases the supervision (and bureaucracy) of companies engaging in the energy and mineral resources sector, including in the Indonesian upstream oil and gas industry. We understand that the Indonesian Government is now considering amending or clarifying certain provisions in MEMR 42/2017 (potentially through a new circular letter or other legal instrument). This is because the government has encountered numerous objections and requests for clarifications from stakeholders in the energy and mineral resources sector (including in the oil and gas industry) in relation to MEMR 42/2017, particularly in relation to the new MEMR approval requirements and restrictions for transfers of participating interests and changes to the directors and commissioners of oil and gas contractors.
In relation to GR 27/2017, while there remains significant uncertainty as to how the provisions will be implemented in practice, on the whole, the regulatory reforms are positive and reflect a long-awaited recognition by the Indonesian government of the need to stimulate and promote investment in the upstream Indonesian oil and gas industry. In particular, GR 27/2017 sets out a number of new tax and non-tax incentives (including, potentially, confirmation of the non-imposition of branch profit tax for the transfer of participating interests) and makes some positive revisions to the ability to make claims for cost recovery.
The provisions set out in GR 27/2017 will automatically apply to all new production sharing contracts (“PSCs”). However, existing PSCs (signed prior to 15 June 2017) will remain in force in accordance with their terms and contractors will be able to elect whether or not they wish to remain subject to the provisions of their existing contract or, by no later than 19 December 2017, apply to adjust the terms of their contract in accordance with the provisions of GR 27/2017. There are a number of different potential economic and legal consequences in adopting the provisions of GR 27/2017 which will need to be carefully considered on a case-by-case basis. Given the uncertainty in relation to the implementation of the provisions of GR 27/2017 in practice, it remains to be seen whether or not existing contractors will exercise their option to adopt the provisions of GR 27/2017.
New incentives for oil and gas contractors
GR 27/2017 introduces a number of new tax and non-tax incentives for upstream oil and gas contractors. The non-tax incentives introduced by GR 27/2017 include investment credits, domestic market obligation (“DMO”) compensation, accelerated depreciation rates, DMO holidays and policies to potentially allow the utilization of certain State assets by contractors during the course of their oil and gas operations. We note that several of these incentives have previously been included in the terms of relevant PSCs. As a result, it remains to be seen whether these new non-tax regulatory incentives will represent a material improvement on the currently available non-tax incentives.
One of the most notable tax incentives introduced by GR 27/2017 is the purported non-taxable treatment of income arising from uplifts and the transfer of PSC participating interests (after being reduced by final income tax). While there remains some regulatory uncertainty on this point, the provisions of GR 27/2017 could provide a basis for ensuring that branch profit tax will not be applied to the transfer of PSC participating interests. This could help spurn greater M&A activity in the Indonesian upstream oil and gas industry. Other new tax incentives introduced by GR 27/2017 include:
- income tax, import duty, value added tax and luxury sales tax exemptions for the importation or usage of goods to be used for oil and gas operations;
- deductions of land and building tax of 100% (during the exploration stage) and up to 100% (during the exploitation stage);
- value added tax deductions and withholding tax exemptions for income from shared asset usage charges; and
- income tax and value added tax exemptions for the indirect costs incurred from the contractor’s head office.
Changes to operations and activities for cost recovery
Previously, the scope of oil and gas operations for which cost recovery could be applied was limited to oil and gas exploration, exploitation, transportation, closure and abandonment of well and site restoration. However, pursuant to GR 27/2017, the scope of activities for cost recovery has now been increased to also include field processing, storage and sale of a company’s own production activities.
GR 27/2017 has also increased the specific activities eligible for cost recovery by including the costs for the development of the community and the environment during the exploration and exploitation stages (cost recovery was previously limited to only during the exploration stage) as well as to confirm cost recoverability for gas processing costs. GR 27/2017 also helpfully clarifies that in the event that tangible assets can no longer be used due to natural factors or force majeure events then the remaining book value of such assets can be immediately included as operational costs for the purposes of cost recovery. Notably, the list of non-recoverable costs has also been amended by GR 27/2017, including by eliminating costs which have not been procured through a tender process. Each of these reforms should, if implemented properly, improve the economic returns for the relevant oil and gas operators/participants.
However, GR 27/2010 has also potentially decreased some of the activities eligible for cost recovery by specifying that cost recovery is limited to operational costs which are “directly” incurred in the oil and gas operations of a contractor’s working area. Under the previous regulatory regime, cost recovery was available for such costs which were either “directly” or “indirectly related” to the oil and gas operations in a contractor’s working area.
Determination of tax calculations
GR 27/2017 amends the existing regulatory framework by expressly stating that, for the purpose of taxation calculations, the Directorate General of Taxation must determine the annual cost of the relevant exploration and exploitation activities after obtaining a recommendation from SKK Migas. In event that the amount of the costs recommended by SKK Migas is different from the amount determined by the Government’s auditor, then the Government’s auditor and SKK Migas must settle such difference.
Potential reform to the production share regime
In the wake of the recent introduction of the gross-split system for new PSCs, GR 27/2017 also makes revisions to the government share regime under the cost recovery system. GR 27/2017 states that MEMR will not be required to consider any guideline in determining the minimum amount of the government share of production from any PSC in relation to a working area. In addition, GR 27/2017 allows MEMR to stipulate a sliding scale production split regime. This sliding scale is intended to reflect an adjusted distribution of production and risk due to any changes which may affect the oil and gas operations, including changes to oil and gas prices, production rates and operational costs. However, GR 27/2017 is unclear as to how such a sliding scale production split regime would be implemented in practice and how such a regime would operate in conjunction with the production splits already expressly stated in the relevant PSC.
Increased supervision of oil and gas companies
As noted above, MEMR 42/2017 seeks to increase the supervision of (among others) upstream oil and gas companies in Indonesia by expanding and clarifying the activities which require prior approval from MEMR. Importantly, MEMR 42/2017 applies to all existing and new PSCs.
Consistent with the terms of most PSCs (as well as the existing regulatory regime), MEMR 42/2017 expressly requires contractors to obtain MEMR approval (the application for which will be considered by MEMR in consultation with SKK Migas) for the transfer of any participating interest in a PSC. However, MEMR 42/2017 also includes more detailed provisions in relation to the requirements and procedures for obtaining such approval.
More notably, MEMR 42/2017 also further regulates the MEMR approval requirements for the change of control of PSC contractors. Numerous PSCs (particularly PSCs granted before 2008) do not expressly require MEMR approval (or notification) requirements for the change of control of PSC contractors. However, MEMR 42/2017 now states that any “direct” change of control of a PSC contractor must obtain the prior approval of MEMR (the application for which will be considered by MEMR in consultation with SKK Migas). Under MEMR 42/2017, a “direct” change of control means the direct transfer of shares in a PSC contractor pursuant to which control of the PSC contractor is transferred to a third party.
MEMR 42/2017 further states that such a transfer of shares by a party (which causes a “direct” change of control of a PSC contractor) can only be carried out to its affiliates. This provision is clearly highly problematic as it potentially prohibits any direct transfer of shares in a PSC contractor to a third party. This provision is also internally illogical (as any transfer of shares by a party to its affiliate will, by its nature, not cause any change of control of the PSC contractor). In practice, we understand that MEMR has not yet implemented MEMR 42/2017 in a way which actually prohibits any transfer of shares in a PSC contractor to a third party – however, this remains possible based on a technical reading of MEMR 42/2017. We suspect that this particular provision is an error or oversight and that the actual intention from a policy perspective is to:
(a)require MEMR approval for the direct transfer of shares in a PSC contractor which results in a change of control (which is consistent with the position in newer generation PSCs); and
(b)permit the transfer of shares in PSC contractors to affiliates, without requiring MEMR consent.
As a result, we expect that MEMR will soon issue a formal amendment to MEMR 42/2017 (or issue a new circular letter in relation to the interpretation and implementation of MEMR 42/2017) to clarify this issue.
MEMR 42/2017 also states that any “indirect” change of control of a PSC contractor must be notified to MEMR (through the Head of SKK Migas); however, MEMR 42/2017 is silent on the time frames applicable for such notification requirement. Under MEMR 42/2017, an “indirect” change of control is where the control of a PSC contractor is transferred to a third party other than through the direct transfer of shares in the PSC contractor.
In addition, MEMR 42/2017 also now states that any change to the board of directors or board of commissioners of a PSC contractor requires prior approval from MEMR (the application for which will be considered by MEMR in consultation with SKK Migas). We note that this new approval requirement is similar to the requirements that have been applicable to mining companies for several years. However, in the Indonesian upstream oil and gas industry, foreign investors have typically invested directly through foreign (not Indonesian) companies. The requirement to obtain prior approval from MEMR for any change to the board of directors of a foreign PSC contractor is a significant hindrance to the flexibility and autonomy of PSC contactors.