The Ministry of Energy and Mineral Resources of the Republic of Indonesia (MEMR) recently issued Regulation No. 10 of 2017 on Principles of Power Purchase Agreements (Regulation 10/2017) which sets out a number of principles and key provisions which need to be reflected in power purchase agreements (PPAs) entered into between PLN and independent power producers (IPPs).

Key points:

• While the new rules largely confirm the terms and principles which have typically been reflected in past PPAs, it brings a number of changes to important principles governing the risk allocation between PT Perusahaan Listrik Negara (Persero) (PLN) and IPPs, some of which may hamper the bankability of IPP projects.
• PLN will now have to take a view on some of the new rules and decide how to reflect these in its standard form PPAs to be issued for future projects and for projects which are currently being tendered out.
• IPPs and lenders will be eager to see how PLN applies these changes: will this be done in a balanced manner with recognition of very real bankability issues, or will substantive changes to the existing bankable model be proposed?

1. Scope of Regulation 10/2017

Regulation 10/2017 was issued on 19 January 2017 and applies to all power projects to be developed by IPPs with the exception of (i) “intermittent” power projects (i.e. wind and solar), (ii) mini-hydro (up to 10MW), (iii) biogas and (iv) waste-to-energy projects.

Regulation 10/2017 is applicable from its date of enactment except to (i) projects which have a signed PPA, (ii) projects where the succesful developer has been issued with a letter of intent (LOI) from PLN, (iii) projects where bid closing has been reached, or (iv) in the case of geothermal projects, where the auction for the award of the relevant gothermal concession has been completed.

2. Key changes brought by Regulation 10/2017

2.1 All projects to be developed on a BOOT basis

Regulation 10/2017 (art. 4(3)) provides that all IPP projects must be developed on the basis of a build, own, operate and transfer (BOOT) scheme, where the IPP is required to transfer the ownership of the relevant project to PLN at the end of the term of the PPA. Although most Indonesian IPP projects are already effectively developed under the BOOT scheme (such as coal and gas-fired projects), this was not necessarily the case of certain geothermal and hydro projects which were developed under a build, own and operate (BOO) basis. These BOO projects entail the possibility for the IPP to negotiate an extension to the PPA as the generation asset is not meant to be transferred to PLN for a nominal value at the end of the term of the PPA, and therefore allow the IPP sponsors to further improve their return on investment. It now seems clear that such BOO projects will no longer be available in the future.

Further, Regulation 10/2017 also provides that the maximum term of PPAs is 30 years with the exact term depending on the type of power generation.

2.2 No deemed dispatch for force majeure affecting PLN’s offtake

Probably the single biggest concern raised by Regulation 10/2017 lies with the apparent change in risk allocation related to events of force majeure which affect PLN’s offtake from IPPs. Under the traditional PPA regime, the IPP would receive deemed dispatch payments based on the availability of the plant where PLN is not in a position to offtake due to events of force majeure (generally after certain grace/standstill periods where a natural event of force majeure affects PLN’s grid in order to allow PLN to try to effect repairs). Regulation 10/2017 (art. 5(1)c. and 6(2)c.) now seems to provide that PLN will be excused from its obligations (including payment obligations) in such case, although this is partially mitigated in the case of natural events of force majeure by the fact that the term of the PPA is then to be extended by a period equivalent to the period of force majeure. If this is indeed the case, this would represent a major shift in the risk allocation between PLN and IPPs as it will effectively mean that the IPPs are taking force majeure risk over PLN’s network and run the risk of not getting paid minimum availability payments which are meant to cover the IPPs fixed development costs. Such a risk allocation would be inconsistent with generally accepted principles of project finance which require risks to be allocated to the party best able to mitigate the risk, which an IPP is clearly not in the case of PLN’s grid system.

2.3 Potential changes to the concept of political force majeure

Regulation 10/2017 also seems to introduce changes to the risk allocation for political force majeure events. Political force majeure events under PLN PPAs typically consist of (i) actions or inactions without justifiable cause of Indonesian governmental instrumentalities and (ii) changes in laws, regulations or policies enacted by such governmental instrumentalities. First, Regulation 10/2017 only refers to the second type of political force majeure events (changes in laws, regulations and policies); second, it seems to provide that the risk for changes in policies needs to be shared between PLN and the IPPs and that in case such change in policy stops the development or the operation of the plant, parties (including PLN) will be released from their obligations.

Although it can be argued that any principle or provision not governed by Regulation 11/2017 falls outside its scope and that parties (PLN and the relevant IPP) may in such case freely agree on the terms and conditions governing their relationship under the PPA, the fact that articles 8 and 28 of Regulation 10/2017 refer to changes in laws, regulations and policy as “government force majeure” casts some doubt over such an interpretation. IPP sponsors and lenders will have to wait and see how PLN interprets and implements the terms of the regulation with regards to the boundaries of the concept of political force majeure. Further, it will also have to be seen how exactly future PPAs will accomodate the principle that the risk of change in government policies has to be shared between PLN and IPPs.

2.4 Minimum availability payment period

Regulation 10/2017 (art. 6(3)) provides that PLN has to offtake and purchase power generated by IPPs for a period of time to be agreed upon between PLN and the relevant IPP “having consideration for” the repayment period of the senior debt to the IPP lenders. Officials at MEMR have confirmed to us that this should not be read to say that the period during which PLN is bound to make minimum availability payments to the IPP (which are meant to cover the IPPs fixed development costs) should necessarily match the debt service period, but only that such period should be borne in mind by PLN when agreeing on the minimum availability payment period under the PPA. Here again, PLN’s interpretation and implementation of this provision will be crucial to IPPs and their lenders.

2.5 Power purchase price has to be in Rupiah

Regulation 10/2017 (art. 17) provides that the payment of power purchase by PLN needs to be settled in Indonesian Rupiah (IDR). This principle is not per se new as it reflects the terms of Bank Indonesia Regulation No. 17/3/PBI/2015 on the Obligation to Use Rupiah Within the Territory of the Republic of Indonesia (BI Regulation 17/3/PBI/2015) which has already been implemented in practice on numerous power projects. Regulation 10/2017 also provides that where the power purchase price can be settled in US Dollars (USD), such payment needs to be based on the Jakarta Interbank Spot Dollar Rate (JISDOR). Pursuant to BI Regulation 17/3/PBI/2015, such payment in USD can only be made by PLN provided an exemption to the obligation to pay in IDR has been obtained from Bank Indonesia. In our experience, however, even where an exemption has been obtained, PLN has nonetheless insisted on settling invoiced payments for electricity in IDR and has opted to have such IDR payments converted into USD at the prevailing JISDOR rate pursuant to a tripartite converting arrangement between the IPP, PLN and a designated state-owned bank. Based on our discussions with MEMR officials, the principle set out in Regulation 10/2017 is not meant to affect the current practice reflected above.

2.6 Penalties applicable to IPPs

Regulation 10/2017 (art. 21 and 22) lists all the penalties which may be imposed on IPPs. These consist of delay liquidated damages and certain penalties based on a failure of the plant to meet certain operational and technical requirements which are to be set in the relevant PPA. These include penalties on the availability factor, heat rate, outage factor, reactive power, frequency range and ramp rate of the plant. Although most of these penalties have been reflected in existing PPAs, the penalties on frequency range and ramp rate are fairly new and it will have to be seen how PLN implements these depending on the type of generation involved.

2.7 Restrictions to transfers of shareholding in the IPP company

Although PPAs tyically included restrictions on transfer of ownership in the IPP company for a certain period of time (commonly up to COD or a certain number of years after COD), IPP sponsors were thereafter free to transfer shares in the IPP company. Regulation 10/2017 now clearly (i) prohibits transfer of ownership in the project company prior to the commercial operation date of the relevant project, with the exception of transfers of ownership to an affiliate which is at least 90% held by the sponsor wishing to transfer its shares and (ii) provides that post-COD, transfers of shareholding in the IPP company are only possible subject to PLN’s prior approval. These new restrictions create uncertainty for sponsors who may be contemplating a shorter investment strategy, involving an exit from the IPP company during the operational life of the project.

Commentary

Regulation 10/2017 represents the first attempt by MEMR to legislate the commercial and legal terms of the PPA between PLN and IPPs. Prior to the enactment of this new regulation, the terms of the PPAs were largely left to the discretion of PLN which had, over time, developed fairly standardised forms of PPA for further negotiation with developers within certain boundaries. Regulation 10/2017 now prescribes certain commercial and legal terms and, arguably, removes PLN’s discretion to negotiate deviations from these. We understand that PLN is currently conducting a benchmarking exercise on a range of risk allocation principles typically reflected in its PPAs against “regional PPAs” and will subsequently update its current PPA forms (including for projects that are currently being tendered out).

It is difficult to take a definitive view on the key changes and potential risks for IPPs and their lenders set out above until PLN issues revised forms of PPAs. This is because the risk allocation embedded in Regulation 10/2017 ultimately needs to be reflected in the PPA and only then will the true impact on risk allocation and bankability be clear. During a socialisation meeting held at MEMR on 10 February 2017, representatives from MEMR indicated that the spirit of Regulation 10/2017 was not to change the traditional risk allocation under PPAs. It is hoped that PLN will adopt a similarly benign attitude when it comes to revise its model PPAs in recognition of the fact that the current model PPAs are generally well accepted and, subject to normal negotiation, bankable.