Momentum for Reforming Oil and Gas Production-Sharing Contracts

The government must optimize new blocks to boost oil and gas lifting. The incentive packages and production-sharing schemes are not attractive enough.

THE discovery of massive gas reserves in the Ganal Block, offshore the Kutai Basin in East Kalimantan, should be a breath of fresh air for the national energy supply. Reforming the production-sharing contract system remains the key to ensuring that this massive gas potential does not merely remain a figure on the reserve books without making a tangible contribution to state revenue.

The block, with reserves of 5 trillion cubic feet of gas and 300 million barrels of condensate, is touted as the largest discovery in recent years amid a trend of declining oil and natural gas production. In the 2026 State Budget, the oil and gas lifting target is set at 1.594 million barrels of oil equivalent per day (BOEPD). Last year’s actual production stalled at 1.56 million BOEPD, falling short of the 1.61 million BOEPD target. This situation is exacerbated by the decline in gas lifting to 951,800 BOEPD, well below the target of 1.005 million BOEPD.

The government must not get carried away by the euphoria of discovering new gas reserves. Especially since the fundamental problem in the upstream oil and gas sector lies in the ineffectiveness of the production-sharing contract scheme, which has long been a source of investor complaints. According to data from the Indonesian Petroleum Association, as of October 2025, realized upstream oil and gas investment has only reached US$11.2 billion, below the US$16.1 billion target. Exploration investment stands at just US$500 million, which also falls short of the US$1.5 billion target. These gaps help explain why national oil and gas production continues to be sluggish. 

A comprehensive evaluation of the oil and gas production-sharing scheme is long overdue. For more than five decades, since 1966, Indonesia has relied on the cost-recovery scheme. Through this mechanism, contractors can claim reimbursement for exploration and development expenses once a field begins production. The system has proved successful in attracting major oil and gas companies to Indonesia.

However, past success does not mean the system is flawless. The cost-recovery scheme is often criticized for opening the doors to inflated costs, lengthy verification processes, and protracted audit disputes. Various studies indicate that this scheme is suitable for high-risk fields because it makes projects more economically viable. However, the state must bear significant oversight costs. The main issue lies not in the concept itself, but in governance and oversight, which are often weak.

When the gross split was introduced in 2017, this new scheme was expected to drive efficiency, simplify administration, and provide certainty regarding state revenue. In reality, in oil and gas fields with high geological risks, many contractors still consider cost recovery to be more investor-friendly.

Amid intense international competition to attract investors in the oil and gas sector, the government must continue to explore alternative scenarios to make Indonesia more competitive. One scheme worth examining is the tax-and-royalty model. Under this scheme, investors manage production, while the state collects royalties based on volume and taxes on profits without bearing operational costs or initial risks. However, this relatively simpler and less contentious cost-sharing scheme requires strong tax administration and law enforcement institutions. 

In essence, every production-sharing contract option requires a transparent, consistent, and strictly monitored design. Without that, no scheme can guarantee the sustainability of investment and the optimization of state revenue. A comprehensive evaluation is increasingly urgent because the stakes are high: Indonesia’s dependence on oil and natural gas is growing day by day.

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