Amendments to Indonesia's new gross split PSC regime: a change for the better, but some uncertainties remain.

Out-Law Analysis | 05 Sep 2017 | 11:38 am | 5 min. read

ANALYSIS: Following consultation from the industry, Indonesia's minister of energy and mineral resources has issued amendments to the country's much-debated gross split production sharing contract (PSC) regime. Initial industry reaction to the changes, which are now aimed expressly at encouraging desperately needed investment into Indonesia's upstream oil and gas industry, is positive.

January's gross split regime

Indonesia introduced the gross split PSC in January to a decidedly lukewarm response from the oil and gas industry. Industry analysis of January's proposed production splits and accompanying adjustment mechanisms was that the regime was in many instances less favourable to investors than Indonesia's cost recovery PSC regime and was more likely to deter than attract investment for many upstream projects, particularly marginal fields, mature fields in need of enhanced oil recovery, projects located in frontier areas, and gas projects. 

The new amendments

On 29 August, the minister published amendments to the gross split PSC regime aimed at boosting use of the new PSC across different types of projects. Encouragingly, the Indonesian government has now taken into account feedback from key oil and gas industry stakeholders.   Prior to issuing these amendments, the government engaged in extensive consultation with key industry stakeholders, including a number of independent petroleum economists, the Indonesian Petroleum Association (IPA) and those international oil companies (IOCs) participating in the current Indonesian upstream bid round. 

The key changes are:

  • most significantly, the removal of the 5% cap on the minister's discretion to award an additional PSC contractor split where a project does not meet a "certain economic level";
  • an increase from 3% to 6% in the PSC contractor variable split for fields in the secondary production phase (water/gas injection) and an increase from 5% to 10% in the PSC contractor variable split for fields in the tertiary production phase (enhanced oil recovery);
  • introducing a progressive split for gas projects which will see an additional PSC contractor split for projects with a gas supply price of less than $7 per million british thermal units (mmbtu);
  • changing the progressive split for oil price to a formula based approach. For example, July's Indonesia crude price of $45.48 would have given a PSC contractor under the revised regime an additional split of 9.88%, which compares very favourably to the maximum of 7.5% available under January's regime;
  • an increase from 5% to up to a maximum of 10% in the PSC contractor progressive split for cumulative production, plus changes to the relevant thresholds;
  • an increase from 0% to 3% in the PSC contractor variable split for subsequent plans of development for oil and gas fields such as for POD II and beyond;  
  • an increase from 2% to 4% in the PSC contractor variable split for new frontier onshore projects; and
  • an increase from 1% up to a maximum of 5% in the PSC contractor variable split for field hydrogen sulphide content, plus changes to the relevant thresholds.

More detail on the changes to the field specific and 'progressive' splits is set out in the tables at the end of this article.

Impact of the changes

The IPA, which was unusually vocal in its criticism of the regime introduced in January, has welcomed these revisions. On 4 September IPA executive director Marjolijn Wajong described them as "positive changes in the efforts to improve the competitiveness of the Indonesian oil and gas industry".

Unlike January's regime, which was introduced principally to "increase efficiency and effectiveness", these new amendments are aimed squarely at making the new model more attractive to investors, including, we think, those PSC contractors currently operating under cost recovery PSCs who, to date, have had little interest in transitioning over to the new regime.  

A fundamental change is the removal of the cap on the minister's discretion to adjust the PSC contractor's production share on POD approval, where SKK Migas' commercial evaluation of a field, or fields, either exceeds or does not meet a "certain economic level". Under January's gross split PSC regime this increase or decrease was capped at a maximum adjustment of +/-5%. This +/-5% cap has now been removed. While this obviously gives the minister significant flexibility to adjust the overall splits, it creates some uncertainty and may make modelling the proposed changes challenging.

It therefore remains to be seen how this discretion will operate in practice. For example, will it be limited to strategic projects? We will also have to wait to see whether it will be applied uniformly based on specific criteria or lead to drawn out negotiations with PSC contractors prior to POD approval and consequent project delays. It would therefore be helpful if the ministry could provide more clarity on what "certain economic level" will mean in practice, how it will be calculated by SKK Migas and confirmation that any adjustment made by the minister using his or her discretion will be limited to what is necessary to bridge the gap to meet this level. Of course, the minister now has broad discretion to reduce the PSC contractor's split where a project exceeds this level, albeit only at the point of POD 1 and subsequent PODs. For example, PSC contractors operating under the new regime who make a very large commercial discovery near existing infrastructure might find themselves with a lower production share as a result of this change.

The amendments under the new regime also seem geared to encourage PSC contractors under existing cost recovery PSCs to transition to a gross split PSC. 

Firstly, in the event of a transition, unrecovered operating costs are taken into account in determining whether a field meets a "certain economic level", as is still the case. However now, with the removal of the +/-5% cap on this discretion, a PSC contractor with a high level of associated unrecovered costs may receive an additional production share, not limited to an additional 5%, to account for these unrecovered costs.

Secondly, amendments to the application of the additional PSC contractor split to aggregate cumulative production have been introduced. Where a working area transitions over to a new gross split PSC, the cumulative production of the field is effectively reset to zero, allowing for an additional increase in the PSC contractor split during the early years of the PSC term. The January regime did not allow for this resetting upon signing of a new gross split PSC and instead cumulative production for the field to date would have been used. 

In addition to providing additional certainty for gas projects, it is likely that the amendments to the variable and progressive splits will mostly benefit mature or marginal projects that are already in production, including the large number of Indonesian PSCs that are due to expire over the next decade. While, at first blush, the amendments do not appear to be aimed at encouraging investment into offshore exploration projects, particularly those located in offshore frontier areas without much existing infrastructure, we expect that these projects will likely benefit through operation of the minister's discretion. Interestingly, the additional PSC contractor split for new frontier onshore areas has increased from 2% to 4%, but remains at 2% for new frontier offshore areas.

While it is extremely reassuring that the Indonesian government has revisited the terms of the gross split PSC, the new provisions will require further economic analysis and scrutiny in order to determine whether in practice the changes will improve the fiscal attractiveness of Indonesia compared to other Southeast Asian jurisdictions. According to a Wood Mackenzie study conducted in October 2016, Indonesia was placed 137th out of 148 global oil and gas fiscal regimes. It will be interesting to see the extent to which these latest changes improve Indonesia's attractiveness compared to other jurisdictions competing for international upstream investment, particularly given recent moves by other jurisdictions to improve their fiscal terms.

This move by the Indonesian government does signal a welcome willingness to listen to concerns raised by the industry. While we await further industry reaction and will be publishing a detailed update to our paper on January's regime, it's not too premature to conclude that the changes are a material improvement to January's model and will hopefully revive flagging interest in Indonesia's upstream industry, including increasing the likelihood of success for Indonesia's current bid round.

Steve Potter is an oil and gas specialist with Pinsent Masons MPillay, the Singapore joint law venture partner of Pinsent Masons, the law firm behind This article has been prepared using the authors’ own unofficial translation from the original Bahasa Indonesia regulation, and does not constitute legal advice.