A new formula for dividing revenues from Indonesia’s oil and gas fields offers a chance for greater returns in the energy sector – an opportunity that could generate more upstream investment.
Introduced in mid-January, the reforms shift energy production contracts from a cost-recovery system to a gross split system using fixed shares of revenues.
Under the old scheme, the state reimbursed contract holders for exploration and production costs but received up to 85% of output earnings, an arrangement that protected contractors’ investments but limited their returns. The new system makes contractors responsible for exploration, development and operational costs but gives them a larger share of the returns.
Under this arrangement, the state will take 57% of output from oil fields, with the remaining 43% going to the contractor; for gas fields, the margins are narrower, at 52% and 48%, respectively.
The shift in contract structure came as part of a wider move to realign minerals and extraction policy.
On January 12 the government announced it was lifting restrictions on a range of unprocessed minerals, including nickel, bauxite and concentrates of other minerals under certain terms. Exports of unprocessed ore had been banned since 2014, a measure aimed at increasing investment in local refining capacity.
Like the change in energy contracts, this easing in minerals policy is aimed at stimulating interest in extractive industries and boosting state revenue from commodities.
Investment in new projects has fallen in recent years amid low energy prices and private sector concerns over long lead times to gain approval for development plans, and determine production costs and rebates.
Besides giving contractors a far greater incentive to maximise output and boost operational efficiency, the new revenue-sharing system for oil and gas blocks also allows a range of variables to come into play to increase returns to the leaseholder.
Among these are the block’s location, depth of deposits, input of local components and future development plans.
A key variable included in the arrangement, however, is price. Should Indonesian crude drop below $40 a barrel, the base split for contracts rises by 7.5 percentage points; similarly, it falls by 7.5 percentage points if the price rises above $115 a barrel.
In early April the price of Indonesian crude rose to $37.20 per barrel, up from $34.10 in March, according to the Ministry of Energy and Mineral Resources.
The appeal of this measure to upstream firms is a hedge against any price fluctuations in the marketplace. While a contractor’s base split would be reduced if prices climb sharply, this would be offset by windfall earnings from higher barrel prices.
The first round of contracts under the new scheme is already under way.
In late January state-owned energy firm Pertamina renewed its rights to the Offshore North West Java block, estimated to hold reserves of 309.8m barrels of oil and 1.1bn cu feet of gas. Under the new contract terms, the government’s take is 37.5% for natural gas and 42.5% for oil.
Other licences will continue to operate under a cost-recovery system, but if no agreement has been reached to extend them by the time of their expiry, they will be renewed under the gross split arrangement. For licences that by law must be extended, operators may apply to the Ministry of Energy and Mineral Resources to either maintain the existing production-sharing contracts or shift to the gross split system.
Moves to implement this clause of the new scheme are in the works, with the government granting Pertamina a further eight blocks whose contracts are set to expire either this year or next.
Reactions to the change in the broader energy sector will likely come in May, when the government is scheduled to open tenders for entirely new blocks.
While appetite for new leases will likely hinge in part on the appeal of the blocks offered and the scale of up-front costs, the May round of tenders should also serve as a litmus test of the new gross split system, and of underlying interest in Indonesia’s upstream segment.
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