Indonesia: MEMR Regulation 10 Of 2017 Of Indonesia: Blurring The Lines

Last Updated: 25 May 2017
Article by Bill McCormack and Jean-Louis Neves Mandelli

Indonesia's state-owned power company, PT PLN (Persero) (PLN) has a long track record of successfully financed independent power projects (IPPs) and a very well established form of power purchase agreement (PPA).  It has to date succeeded in implementing new government regulations (such as the Currency Law of 2011 requiring the mandatory use of rupiah in transactions within Indonesia) while maintaining the bankability of its PPAs.  Regulation 10 of 2017 issued by the Indonesian Ministry of Energy and Mineral Resources (MEMR), which came into force on January 19, 2017, introduces a new regime which applies to all new PPAs entered into by PLN (subject to some exceptions set out below) and potentially to amendments of existing PPAs.  This new regime seeks to regulate and—to some extent—amend structures and risk allocations that were previously well understood.  It is not yet clear how these will affect the terms of PLN's future PPAs.

This article sets out an analysis of the key terms of Regulation 10 and how it may impact existing and future PLN PPAs. 

Scope of Application

Regulation 10 applies to new PPAs to be entered into by PLN after January 19, 2017 in connection with any projects other than "intermittent" power generation projects (which we understand to mean solar and wind projects), hydropower projects below 10MW, biomass power projects and municipal waste-to-power projects (Article 2).  PPAs in respect of which the bidding had been completed and PPAs which were at preferred bidder stage, in each case, as at January 19, 2017, are also excluded from the scope of application of Regulation 10 (Article 31).

If Regulation 10 applies to a PPA, then the terms of the PPA cannot conflict with the terms of Regulation 10.  However, where a matter is not specifically addressed in Regulation 10, we understand that this can be freely negotiated with PLN.  This is a key principle for the interpretation of Regulation 10 and one which may be very helpful when it comes to reflecting its requirements into new PPAs.

It was initially unclear whether and to what extent existing PPAs may be affected by Regulation 10 if they are amended after its entry into force.  Based on the discussions we have had to date with the MEMR and PLN, we understand that existing PPAs should be exempted from the terms of Regulation 10 (even if amended in future).

Analysis of Key Potential Changes


Regulation 10 imposes a maximum term of 30 years from the Commercial Operations Date (taking into account the technical features of the particular project) (Article 4(1)).  A maximum 30-year operating period for a PPA is consistent with (if not longer than) practice in Indonesia and other jurisdictions.  Typically, coal-fired (non-mine-mouth) PPAs in Indonesia have a 25-year term; mine-mouth and hydro PPAs 30 years and gas-fired PPAs 20 – 25 years. 

Under Regulation 10, PPA tariffs should include a capital cost recovery component for at least the first 20 years (Article 4(4)). However, PLN's obligation to purchase electricity is expressed as applying "taking into consideration the repayment period under the financing arrangements" (Article 6(3)).  We understand that Article 6(3) is not intended to limit PLN's obligation to make tariff payments but to act as a guiding principle to PLN when discussing the structure of the capital cost recovery component. It is not clear how Article 4(4) and 6(3) would operate in the context of a financing with a tenor of less than 20 years from commercial operation. We would expect borrowers and lenders to want to ensure that the capital cost recovery component under the tariff allows for an adequate debt service coverage ratio during the tenor of the loans even if the cost recovery period under the tariff is longer.

This may mean that borrowers will seek a higher cost recovery during the earlier years of the PPA term.  This is not uncommon for PLN PPAs, however, if such a structure may no longer be possible in light of MEMR Regulation 24 of 2017 (which came into force on March 23, 2017).  This regulation suggests that the tariff applicable to any new PPA entered into by PLN—irrespective of the technology—would be determined by reference to the average generating price for the preceding year in the area where that project is to be located.  This had been anticipated for renewable energy projects (see our article on Regulation 12) but not for other power projects.

BOOT Structure

Article 4(3) of Regulation 10 requires all PPAs to be entered into on a "build own operate transfer" basis.  Most PLN PPAs signed to date (except for geothermal and hydropower PPAs) have effectively been entered into on a "build own operate transfer" basis, although this was not a legal requirement.  As such, the "build own operate transfer" structure should not materially change the risk allocation.  However, it would prevent sponsors from seeking to negotiate an extension to the initial PPA term in cases where this was permitted.

Currently, most PLN PPAs contemplate that in case of termination for generator default, there would only be a transfer to PLN if PLN elects to acquire the project assets.  We assume that this would continue to be the case for PPAs entered into under Regulation 10. 

Changes to Risk Allocation

Although in many respects Regulation 10 codifies a division of risk and responsibilities, which is consistent with PLN's precedent PPAs, it appears to introduce certain changes to this—particularly in respect of political risk and PLN grid risk.

Political risk – Typically, PLN agrees that the generator will be excused from performing its obligations under the PPA to the extent it is prevented from performing its obligations as a result of events of a political nature such as wars, civil disturbances, changes in law and actions or inactions without justifiable cause by Indonesian government instrumentalities.  If a change in law or any acts or omissions of Indonesian government instrumentalities prevent the generator from performing its obligations, the generator is also typically entitled to revenue compensation by being deemed to be available to generate power ("Deemed Dispatch Payment").  Should these circumstances persist for a protracted period of time, the generator usually also has the right to terminate the PPA and require PLN to purchase the project in exchange for a termination payment which is intended to allow the repayment of outstanding debt and the recovery of equity investments plus a return.  The generator may also be entitled to an adjustment to the tariff to compensate for increased costs resulting from a change in law.

One of the key changes introduced by Regulation 10 relates to the allocation of change in law risk.  Article 8(2) states that change in law is a risk that is borne both by the generator and PLN, and Article 28(7) states that PLN would be entitled to relief from its obligations in case a "change in government policy" causes a stoppage of the power plant.  This could be read to mean that the generator would no longer be entitled to Deemed Dispatch Payment from PLN.

While PLN is a state-owned enterprise rather than the state itself, meaning there may be a rationale for not taking change in law risk, it is not clear how this risk would now be addressed if the intention is indeed to relieve PLN from its payment obligations in these circumstances.  While the generator would remain entitled to a tariff adjustment to recover additional costs resulting from a change in law, this does not appear to allow for recovery of lost revenue.

Article 28 lists both "change in law" and "change in government policy" as different types of force majeure, each giving rise to different consequences, with the former entitling the generator to a tariff adjustment and the latter relieving PLN from its obligations.  It is not clear how these two concepts differ.  Taking their literal meaning, a change in law is usually the consequence of implementing a change in policy but a change in policy alone may have no impact on Indonesian law (unless it translates into a change in law).  It is difficult to understand why a change in policy would affect a project in the absence of a change in law (or why it would grant greater relief to PLN than a change in law).

We also note that the force majeure concept set out in Regulation 10 does not specifically list acts or omissions of Indonesian government instrumentalities.  While we understand that the instances of force majeure in Regulation 10 should not be read as exclusive and that—as a matter of law—the parties should be able to agree to additional force majeure circumstances in the PPA negotiations, whether this will be the case in practice will depend on PLN's interpretation of the regulation.

Grid risk – Typically, PLN is required to continue to make capacity payments on a "deemed dispatch" basis under its PPAs even if it is not able to take power as a result of a force majeure event affecting the Indonesian grid.  This is consistent with the typical project finance approach.  However, Article 6(2) of Regulation 10 provides that PLN will only be required to make these payments if the grid is affected by reasons other than force majeure.  This could be read as meaning that there would be no right to receive deemed dispatch payments at all if the grid is affected by a force majeure event, resulting in losses of revenue for the generator and affecting its ability to meet its operating costs and debt service obligations.  For natural disasters, the generator will be entitled to an extension to the term of the PPA to recover the lost revenues, which would help mitigate the grid risk.  However, this reading would still represent a significant shift from the typical position PLN has taken in its PPAs. 

A different view of how Article 6(2) would be implemented is possible.  Most recent PLN PPAs include a right to receive deemed dispatch if the grid is affected by force majeure only after a waiting period (usually 14 to 28 days).  It may be that there would still be a right to deemed dispatch but subject to a waiting period, as is presently the case.  This would be preferable from a bankability perspective.

Fuel risk – Expressed in Regulation 10 as being borne by the generator, this is consistent with the general regime applicable in the context of thermal IPPs (including PLN PPAs), as the generator is typically not considered available to generate power (and entitled to capacity payments) if it does not have access to fuel.  We would note that PLN PPAs usually include an exception to this rule in circumstances where there is no fuel as a result of a "government force majeure" (i.e., a political risk which PLN usually takes the risk on).  It is not clear whether this would cease to be the case. 

We also note that there are circumstances where PLN may be procuring the fuel for the project.  This is an option foreseen by Regulation 10.  In these circumstances, the generator would not be responsible for supplying fuel.  However, it is unclear whether PLN will fully take the supply risk (including compensation for the generator's lost revenues in case of failure to supply).  Recent PPAs indicate that if PLN is responsible for supply and there is an interruption, PLN would require a waiting period before entitlement to deemed dispatch.  This may be more of an issue for gas/LNG than for coal, since typically coal projects maintain a stockpile on site.  Article 14(2)(c) envisages that where PLN is procuring the fuel, the fuel supplier must guarantee the continuity of gas supply and pay penalties in case of failure to supply.  We would not usually expect third-party fuel suppliers to IPPs to agree to fully compensate the generator against revenue loss due to the limited value of the fuel supply arrangements.  It is not clear whether PLN is proposing that the generator should only be entitled to compensation to the extent provided by the fuel suppliers.

Construction risk – Regulation 10 allows PLN to require the acceleration of the date for the achievement of commercial operations in consideration for an "incentive."  We would expect the circumstances in which this right of acceleration can be exercised and the nature (and timing) of the incentive to be subject to significant discussion, as this would have an impact on the construction arrangements and the financing plan.

Operating risk – PLN PPAs typically include a low availability penalty (usually limited to a reduction in revenue) and a heat rate penalty (reducing the fuel cost recovery to the extent the plant is inefficient).  Regulation 10 envisages not only these availability and heat rate penalties, but also frequency and ramp rate penalties.  It is not clear what impact these may have on the generator's revenues.  Regulation 10 also expresses the availability penalties as being calculated on the basis of the amount of costs to be incurred by PLN due to unavailability of energy.  This may be over and above a simple reduction in revenue for the generator to the extent of the unavailability.  However, there is precedent for both PLN and offtakers in other jurisdictions taking a similar approach.  The extent to which this affects a project will depend on the level of penalties PLN is proposing.

Transfer of Ownership

Existing PPAs normally contain a Sponsors Agreement entered into between PLN and the sponsors/shareholders of the generator.  Under the Sponsors Agreement, a shareholder typically cannot transfer its shares in the generator until the fifth anniversary of the project's COD except:  (i) where it is required under the financing agreements or (ii) to that shareholder's affiliates or to another shareholder's affiliate. 

Regulation 10 limits the transfer restriction to COD only.  Pre-COD transfers are permitted if a transfer is made to a 90 percent owned affiliate.  All other transfers would require PLN consent.  We would expect that transfers made by the lenders in the context of an enforcement of share security would be approved up front by PLN.


Regulation 10 introduces some potential key changes to PLN's traditional risk allocation, in particular as concerns the allocation of political risk and grid risk, and the structure of the contract.  While Regulation 10 certainly blurs the previously clearly defined lines on which PLN PPAs were structured, whether and to what extent it will affect the bankability of future PLN PPAs is difficult to determine at this stage, and will only become clear as PLN implements PPAs on the basis of this new regulation.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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