As the oil and gas sector has contributed progressively less to the state budget, policymakers are seeking ways to boost revenue from the industry. Walking the tightrope between an attractive investment climate and greater state revenue shares has proven challenging, particularly since the slump in oil prices began in 2014. New government regulations implemented since 2001 have affected the way the sector operates.
REDRAWING THE RULES: The regulatory environment has been in a state of flux for much of the new millennium, starting in 2001 with the introduction of a new Oil and Gas Law. Shortly thereafter, state-run upstream and downstream regulatory bodies and companies were established in the form of BPMIGAS and BPH MIGAS in 2002 and Pertamina in 2003. Government Regulation No. 35 of 2004 and Government Regulation No. 36 of 2004 for upstream and downstream business activities, respectively, were issued in 2004. In 2008 the government began to express a desire to keep a larger share of the revenue derived from extractive industries, resulting in a list of 17 negative cost-recovery items. This was followed with Government Regulation No. 79 of 2010, which redrew the rules pertaining to cost recovery and income tax on upstream operations.
Conscious of the declining revenue in the sector, the government rolled out a new plan in January 2017 intended to simplify contract structures, slash red tape, encourage new investment, increase government revenue splits, and lower the cost of exploration and production. The primary means through which these goals are to be achieved is Government Regulation No. 8, which redesigns the contract splits from the previous standard production-sharing contract (PSC) to a new gross-split PSC system. The new gross-split PSC regulation divides gross production revenues between the government and contractor.
These changes were made in part to address one of the complaints levelled at the previous net-split contracts by contractors who sometimes found it challenging to recoup the funds owed through the cost-recovery process. Because these funds were funnelled into the budget, the relevant government bodies often struggled to convince Parliament to allocate the cost-recovery funds to the companies. In this sense, gross-cost recovery can be viewed as a means to address perceived problems with the system by slashing bureaucracy and eliminating a level of regulation.
NEW APPROACH: “It is positive that the government is looking at new ways to do things because some big potential projects have been delayed in the past as investors felt that the returns did not always justify the investment,” Sacha Winzenried, lead advisor for energy, utilities and mining at PwC Indonesia, told OBG.
While the new gross-split system removes some layers of bureaucracy and the complicated cost-recovery aspect of contracts completely, it does little to compensate contractors for developing the higher-cost, low-margin technical fields which are prevalent in the country today. For oil projects, gross revenues will be shared 57:43, in the government’s favour. For gas projects, the ratio will be 52:48. Another provision introduced by the government is the possibility of a sliding scale for the split based upon higher anticipated development costs of more technically challenging fields. However, there has been a lack of clarity in terms of how the stipulation could be applied.
As it stands, the gross-split PSC has similar characteristics to a concession-based royalty system which has been successful elsewhere in the world, notably in Thailand, Morocco, the Netherlands and Canada. The reality in Indonesia, however, is that the economics of a royalty regime may not be well suited to the oil and gas industry, which features a large number of low-margin, high-cost fields and very capital-intensive projects.
Under the gross-split system, it is projected that 32% of oil and gas fields in Indonesia would be economically unviable or “deterred”, compared to 22% under the standard PSC system, according to an analysis on the issue published by Wood Mackenzie in March 2017. The removal of cost-recovery contract clauses places the responsibility for cost control solely with contractors and could encourage a more efficient upstream sector, but this strategy relies on contractors being willing and able to reduce costs. Utilising the net present value (NPV) method of estimating a project’s potential profitability by analysing the difference between the present value of cash inflows and cash outflows, the study indicated that onshore, shelf and deepwater oil projects would all show negative NPVs under the gross-split scheme compared with the PSC. While deepwater projects needed to achieve at least 10% cost reductions for a positive NPV, projects taking place in shelf waters began to show positive NPV once cost savings of at least 20% were realised and onshore projects remained negative even with 30% cost reduction. Costs for natural gas projects would need to be slashed by as much as 75% to achieve similar returns to the previous terms.
The new terms are applicable to future licence awards and contract extensions. This provision will have significant ramifications considering the expiration of major contracts including South-East Sumatra, Sanga Sanga and North-West Java Sea. According to budgetary models in the Wood Mackenzie study, PSCs converted to the gross-split model would reduce total contractor value by $480m while boosting the government share by $470m. For other expiring PSCs already operating under challenging economic conditions, such as North Sumatra Offshore, Attaka, East Kalimantan, Tuban and Ogan Komering, the gross-split PSC could deter investment and reduce the operating lives of these fields.
SELECTIVE INVESTMENT: Given the projected costs and returns, many in the sector are doubtful contractors will find gross-split contracts economically viable enough to justify new investment in the majority of blocks available. Oil companies have been reticent to bid for new contracts due to a perception that it will take longer to recover costs. “Despite low oil prices, companies are still investing, albeit more prudently and selectively,” Ari Soemarno, a consultant in the oil and gas industry and former head of Pertamina, told OBG. “The era of easy oil is gone, and the remaining fields are more suitable to the major players. Indonesia must compete to attract investment from the majors.”
These sentiments were echoed by several independent studies analysing the gross-split system, with a consensus forming that in some low-risk areas where the infrastructure is already in place, projects could remain viable provided that operators were able to reduce costs. However, new investments in exploration and production will remain unlikely until further changes are made to incentivise activity in higher-risk areas.
“The government needs to be proactive in formulating a new law as soon as possible,” Soemarno told OBG. “Oil and gas was a major revenue generator. We need to understand that it still has the largest multiplier effect compared to other natural-resource industries.”
