Gross split in oil production sharing contracts
The Energy and Mineral Resources Ministry recently enacted the gross split production sharing contract (PSC) through ministry regulation no. 8/2017. As its distinct feature, the gross split PSC does not use the costrecovery mechanism, currently applied to all PSCs. The gross split scheme allocates oil and gas production to contracting parties based on gross production. This contrasts significantly with the traditional Indonesian PSC concept, where oil and gas production was shared between the government and companies (contractors) after deducting the production costs (cost recovery).
The regulation stipulates that the initial base splits for government and companies in the gross split PSC are 57 percent/43 percent and 52 percent/48 percent, for oil and natural gas respectively. The base splits are adjustable by incorporating other metrics, which are called variable and progressive components.
Variable components include the block status, the field’s location, the reservoir depth and type, the availability of supporting infrastructure, the content of carbon dioxide and hydrogen sulfide, the oil’s weight, local content and stages of production. Variable components can adjust contractors’ base splits negatively and positively. Each component’s adjustment varies, but it may range from 16 percent to minus 5 percent.
Furthermore, there are two progressive components, namely oil price and cumulative production. A lower Indonesian Crude Price (ICP) than US$40 per barrel will improve contractors’ base split by 7.5 percent, but if ICP skyrockets to $115 per barrel (or above), the contractors’ base split will be cut by 7.5 percent. Regarding the cumulative production, greater production means more reduction of contractors’ production split.
As already mentioned, the absence of a cost-recovery mechanism is one of the gross split PSC’s distinct features. In a traditional Indonesian PSC, cost recovery is essentially the capital and operating expenditures of upstream operation, which are paid and assumed in advance by oil and gas companies. Without capital and operating expenditures, it is impossible to run an upstream project.
A gross split PSC creates an impression that it erases cost recovery. The term “cost recovery” can be erased, but the costs (capital and operating expenditures) do not disappear because they are real business costs. They just no longer can come up as cost recovery.
As a matter of fact, Article 14 of the regulation states that contractors’ upstream costs can be deducted in calculating their income taxes. In this situation, it might be correct to say that a gross split PSC eliminates cost recovery terms and procedures, but capital and operating expenditures will continue to show up on oil companies’ income tax returns. As an important note, despite the gross split PSC not having a cost-recovery component; all upstream operational equipment purchased or procured by companies automatically belongs to the state.
Another distinct feature of a gross split PSC is how it allocates upstream project cash flows to contracting parties. Generally speaking, it is all about who gets what. For the state, a gross split PSC awards economic benefits such as share of production, bonuses and income taxes. In addition, the regulation also mentions that the state is entitled to receive indirect taxes (value added tax is an example of indirect taxes).
On the other side, what do contractors get out of gross split PSCs? Of course, they will receive a share of the production according to the percentage of their gross splits. However, they must still pay income taxes. Their upstream costs can be claimed in their tax calculation process. Contractors’ “net take” is simply their share of production less income taxes, bonuses, and indirect taxes. Thus, expressed percentages in the gross split PSC are not after-taxes.
Gross split PSCs also strictly divide governmental institution’s roles in relation to state revenue. As mentioned before, state revenues from gross split PSCs are a share of production, bonuses, income taxes and indirect taxes. The state’s share of production and bonuses (or non-taxes revenue) tend to fall within the role of energy ministry and upstream petroleum authority, while taxes are the responsibility of the Finance Ministry. The state’s non-tax revenues are taken without considering upstream costs, while taxes are calculated after costs.
Hence, there is the possibility that their perspectives on state revenue will be relatively fragmented. For a comparison, in the traditional PSCs, capital and operational expenditures (cost recovery) are deducted from oil and gas production to determine the amount of production to be shared between the government and companies. Companies then pay income taxes on their share of production.
In the new scheme, theoretically, the perspective of governmental institutions should intersect at cost recovery because it affects the size of production to be shared, which later serves as the base of production sharing (the government share of production is a non-tax revenue) and income taxes.
Prior to the gross split PSC, the government had introduced PSC variations such as sliding scale PSC and gross split sliding scale in 2015 (for non-conventional oil and gas), as well as the open bid split in 2016. The next oil and gas block auction will decide whether gross split PSC is better or worse than its predecessors in attracting new upstream investment.