Indonesian Insights

Written by Fitriana Mahiddin

Following long discussions with oil and gas investors, the Government of Indonesia recently issued Government Regulation No. 79 of 2010 (“GR 79”) on operating costs that can be recovered and the income tax treatment of the upstream oil and natural gas business sector. This regulation came into effect as of December 20, 2010 in order to implement Article 31D of the Indonesian Income Tax Law.  While initially questioned by the oil and gas industry, this regulation is now expected to encourage investment in the upstream oil and gas sector in Indonesia.  However, some provisions of GR 79 may create uncertainties for the existing Production Sharing Contracts (“PSCs”).

Although cost recovery is already regulated in existing PSCs, GR 79 is considered necessary by the Government in order to maximize the efficiency of cost recovery calculations due to, among others, the increase of the state’s expenditure for cost recovery and the Finance and Development Supervisory Body’s findings on cost recovery. The Government therefore proposed to revise the existing system regarding cost recovery, particularly to clarify the types of costs that can be included or excluded in cost recovery.

GR 79 is applicable to PSCs and service contracts in the upstream oil and natural gas business sector.  GR 79 aims to further govern what costs can and cannot be recovered, which previously were regulated under the Minister of Energy and Mineral Resources’ (“MEMR”) Regulation No. 22 of 2008 regarding the types of costs of oil and natural gas upstream businesses which are not recoverable to the Cooperation Contract Contractors (“MEMR Reg 22”).  GR 79 also regulates the calculation of income tax on income associated with PSCs, service contracts and other income outside of PSCs.

The regulation’s main provisions

Under GR 79, PSC Contractors can recover operating costs in accordance with the Work Program and Budget approved by the Head of the Implementing Body for Upstream Oil and Gas Activities (commonly known as “BPMIGAS”)  after the related working area has reached commercial production.  Operating costs are further defined as exploration costs, exploitation costs and other costs.  GR 79 stipulates that operating costs can be recovered in the calculation of production sharing and income tax as long as they meet the following requirements:

(i)         incurred to obtain, collect and maintain income pursuant to applicable laws and regulations and are directly related to petroleum operations within the working area of the Contractor in Indonesia;

(ii)        use a reasonable price that is not influenced by related parties as intended in the Income Tax Law;

(iii)       implement petroleum operations in accordance with good business and good engineering practices;

(iv)       petroleum operation activities are in accordance with the Work Program and Budget that have been approved by BPMIGAS.

While MEMR Reg 22 provides 17 types of costs that are not recoverable, GR 79 now sets forth and clarifies 24 types of costs that cannot be recovered (including 7 new types of costs), as follows:

(i)         costs that are charged or incurred for personal interest and/or the family of employees, management, participating interest holders and shareholders;

(ii)        formation and accumulation of the reserve funds, except for the mine closure and abandonment costs which are deposited in a joint account between BPMIGAS and the Contractor at a public bank of the Government of Indonesia located in Indonesia;

(iii)       granted assets;

(iv)       administrative sanctions in the form of interest, fines, and criminal sanctions in the form of fines in relation to the implementation of laws and regulations in taxation, and claims or fines arising from a Contractor’s mistake, either intentionally or through negligence;

(v)        depreciation cost of the goods and equipment used which are not owned by the state;

(vi)       incentives, pension fund payments, and insurance premiums for personal interest and/or the families of expatriate employees, management and shareholders;

(vii)      costs for expatriate employees who are not in compliance with the Expatriate Manpower Utilization Plan or do not have an Expatriate Work Permit;

(viii)     costs for legal consultation not directly related with petroleum operations under a PSC;

(ix)       costs for tax consultation;

(x)        costs for the marketing of a Contractor’s share of oil and natural gas, except for the marketing cost of natural gas approved by the Head of BPMIGAS;

(xi)       costs for representation, including costs for meals under whatever name or form, except if accompanied with a list of nominated benefit recipients and their tax identification number;

(xii)      costs for environmental and community development during the exploitation period;

(xiii)     costs for the technical training of expatriates;

(xiv)     costs associated with mergers, acquisitions, or the transfer of a participating interest;

(xv)      costs for interest on loans;

(xvi)     employee tax borne by the Contractor or paid as a tax allowance and deductable, or collected income tax from third party income borne by the Contractor or grossed-up;

(xvii)    procurement of goods and services and other activities not in accordance with reasonable and good engineering principles, or exceeding the value of authorized expenditure by 10% of such authorized expenditure;

(xviii)   surplus inventory due to inaccurate planning and purchasing;

(xix)     book value and operation costs of used assets no longer operable due to Contractor’s negligence;

(xx)      any transaction which:

a.         causes loss to the Government;

b.         does not use a tender process in accordance with regulations, except under certain circumstances;

c.         is contradictory to applicable rules and regulations.

(xxi)     bonuses paid to the Government;

(xxii)    costs incurred prior to contract signing;

(xxiii)   incentives on interest recovery; and

(xxiv)   commercial audit costs.

Increased powers of the MEMR

GR 79 also provides additional authority and responsibility to the MEMR.  For example, the MEMR determines the minimum extent of the Government’s share of a certain working area in respect to lifting in an approval of the field’s plan of development.  Such determination is based on guidelines stipulated by the MEMR.  Further, to guarantee state income, the MEMR stipulates the extent and the sharing of First Tranche Petroleum (FTP).  The MEMR may also stipulate the form and extent of investment incentives in order to stimulate development of a working area.  As to the authority of BPMIGAS, GR 79 requires BPMIGAS to issue standards and norms, types, categories, and costs utilized in petroleum operation activities while GR 79 is in effect.

Income Tax calculations

GR 79 further regulates the acknowledgement and calculation of the income of PSC Contractors, the calculation of production sharing and the calculation of income tax.  With regard to income outside PSCs, GR 79 provides new requirements that a Contractor’s income from the transfer of a PSC’s participating interest shall be subject to a final income tax of 5% of the gross proceeds of the transfer during the exploration phase and a 7% final income tax rate of gross proceeds of the transfer during the exploitation phase.  However, no income tax will be imposed on the transfer of the participating interest to a national company.  In addition, for the purpose of risk-sharing during the exploration period, the transfer of a participating interest is excluded from income calculations if:

(i)         not all participating interests are transferred;

(ii)        the participating interest has been in possession for more than three years;

(iii)       exploration has been carried out in a working area (i.e. investment costs have been incurred); and

(iv)       the transfer of the participating interest is not for profit seeking.

Contract Sanctity

Importantly, GR 79 provides contract sanctity for existing PSCs that have been signed before GR 79 was enacted.  However, matters that have not been regulated in such PSCs must be adjusted to comply with GR 79 within three months (i.e., March 20, 2011) including with respect to the following provisions:

(i)         the amount of state revenue;

(ii)        the terms and conditions of operating costs that can be recovered and the norms of charging those operating costs;

(iii)       non recoverable operating costs;

(iv)       appointment of an independent third party to conduct financial and technical verifications;

(v)        the issuance of income tax statements;

(vi)       exemption of import duties and tax on goods utilized during exploration and exploitation;

(vii)      a Contractor’s income tax in the form of the volume of crude oil and/or natural  gas from the Contractor’s share; and

(viii)     income from outside PSCs in the form of uplift and/or the transfer of a participating interest.

The latter provision on the exception of the contract sanctity provision may create uncertainties for the existing PSCs and could possibly trigger future disputes with the Government and/or BPMIGAS.  However, while GR 79 establishes additional limitations on cost recovery, it also provides greater clarity that may positively affect the interests of investors in the upstream oil and gas sector in Indonesia.

This article was first published in Asian-Counsel magazine, Volume 9, Issue 2, 2011.