The last two months has seen a rush of activity from the Minister of Energy and Mineral Resources (MEMR) in issuing several new regulations regarding IPP risk allocation, gas-supply pricing and renewable electricity pricing. In particular, MEMR recently issued three new (and generally well received) regulations related to investment in the Indonesian power and new and renewable energy sector in an effort to further improve and accelerate investment in the industry. The regulations show a renewed effort by MEMR to deal with certain key areas of regulatory uncertainty relevant to the power sector. This update describes the key developments and reforms introduced by the following regulations:

(i) MEMR Regulation No. 49 of 2017 (Regulation 49/2017) which amends MEMR Regulation No. 10 of 2017 regarding the Principles of Power Purchase Agreements (Regulation 10/2017) (together referred to as Regulation 10/2017 (as amended));

(ii) MEMR Regulation No. 45 of 2017 (Regulation 45/2017) which revokes and replaces MEMR Regulation No 11 of 2017 (issued earlier in the year) regarding Natural Gas Use for Power Plants (Regulation 11/2017); and

(iii) MEMR Regulation No.50 of 2017 (Regulation 50/2017) which revokes and replaces MEMR Regulation No 12 of 2017 regarding the Utilisation of New and Renewable Energy for Electricity Supply, as amended by MEMR Regulation No.43/2017 (Regulation 12/2017).

While there remains some uncertainty as to how a number of aspects regarding these newly issued regulations will be implemented in practice (and how long it will take before they too are amended or replaced) the new regulations should, in general, be warmly received by the Indonesian power industry. In particular, Regulation 49/2017 seeks to improve the risk allocation between PLN and independent power producers (IPPs) in power purchase agreements (PPAs). Regulation 45/2017 amends the maximum price payable by IPPs for natural gas and provides further clarity on how the gas to power regulatory regime will operate. Finally, Regulation 50/2017 potentially provides significant improvement in the electricity price that will be available for new and renewable power projects in certain local grids.

For a summary of the other regulations recently issued by MEMR, please refer to our e-bulletins on the supervision of Indonesian energy and resources companies (available here), the simplifications to the mining and mining services industry licensing procedures (available here) and the amendments to the cost recovery regime in the Indonesian upstream oil and gas industry (available here).

1. Principles of Power Purchase Agreements

Prior to the issuance of Regulation 10/2017, the terms and conditions of PPAs entered into by PT PLN (the Indonesian state-owned power generation and distribution company) with IPPs have largely, from an Indonesian regulatory perspective, been subject to negotiation between the parties. That said, in recent years, relatively firm precedent PPAs have been prescribed by PLN (particularly in the conventional power industry) such that there are generally well established and accepted principles regarding the standard obligations and allocations of risk under Indonesian PPAs with PLN.

The enactment of Regulation 10/2017 on 23 January 2017 (the Effective Date) sought to formalize many of the arrangements set out in PLN’s precedents by introducing regulatory requirements for the content of PPAs related to certain types of power sources. Regulation 10/2017 also made several material amendments to the previously accepted risk allocations under Indonesian PPAs. In general, these amendments were in favour of PLN and triggered concerns from new IPPs about (among other things) the bankability of PPAs issued under the new regulatory framework.

MEMR issued Regulation 49/2017 in response to some of these concerns. In particular, Regulation 49/2017 has removed the risk of policy and regulatory changes from the set of risks required to be shared by PLN and the IPP. While only going a small way to address investor concerns in relation to Regulation 10/2017, this is still a welcome reform as it is commonly accepted that, in the context of PPAs, the risk of political force majeure (including changes in government law, policy or regulation) is most efficiently allocated to the relevant government or state-owned entity (such as PLN) as the party which is best able to control or influence this risk. This position has generally been adopted in existing typical Indonesian PPAs with PLN prior to the introduction of Regulation 10/2017 and, following the issuance of Regulation 49/2017, we expect that the provisions previously adopted by PLN in relation to the risk of policy and regulation changes will continue to apply.

In this regard, Regulation 10/2017 (as amended) continues to state that if a change in law/regulation results in higher costs, the tariffs payable to the IPP will be adjusted upwards and if a change in law/regulation results in lower costs, the tariffs payable to the IPP will be adjusted downwards. However, Regulation 49/2017 removes the problematic provision previously appearing in Regulation 10/2017 which stated that in the event that a change in government policy leads to the termination the PPA then both PLN and the IPP would be released from their obligations under the PPA.

Regulation 10/2017 (as amended) remains silent on whether or not equitable adjustments to the PPA milestone schedule or term of the PPA will be available for force majeure events. Regulation 10/2017 (as amended) is also silent on whether or not cost adjustments will be available for other political force majeure events (other than change in law/regulation). However, given the reforms introduced by Regulation 49/2017, we are optimistic that the new precedent PPA to be prepared by PLN to conform with Regulation 10/2017 (as amended) will continue to contain such relief for IPPs in relation to these force majeure events.

As far as we are aware, PLN has not yet finalized the new precedent PPAs to conform with Regulation 10/2017 (as amended) and there remains substantial uncertainty as to how many of the issues set out in Regulation 10/2017 (as amended) will be implemented in practice.

Application of Regulation 10/2017 (as amended)

Regulation 10/2017 (as amended) specifically sets out several mandatory provisions that must be incorporated into most (but not all) PPAs to be executed with PLN. Regulation 10/2017 (as amended) covers numerous types of power plants, including (but not limited to) conventional power plants, geothermal, hydropower (above 10 MW) and biomass power plants. However, Regulation 10/2017 (as amended) expressly does not apply to: (i) intermittent renewable power plants, (ii) hydro power plants below 10 MW, (iii) biogas power plants, or (iv) waste-based power plants. The terms and conditions for PPAs for these excluded types of power plants will be governed under separate MEMR regulations which have not yet been issued.

The PPAs for power plant projects which have not reached bid closing prior to the Effective Date are subject to Regulation 10/2017 (as amended). However, Regulation 10/2017 (as amended) does not apply to projects: (i) that have already reached bid closing prior to the Effective Date, or (ii) in which PLN has executed a letter of intent or signed PPA (including its amendments or adjustments) prior to the Effective Date. Further, and specifically for geothermal projects within unsigned PPAs, Regulation 10/2017 (as amended) does not apply to projects that have, prior to the Effective Date, reached (i) the auction process and price offer stage or (ii) the winner declaration stage.

Regulation 10/2017 (as amended) makes it implicitly clear that any existing PPAs will remain valid and legally enforceable until their expiry (without any requirement for these existing PPAs to be amended in accordance with Regulation 10/2017 (as amended)). However, Regulation 10/2017 (as amended) does not clarify whether or not the mandatory PPA provisions are required to be incorporated into any PPA amendment agreements which are executed after the Effective Date. As a result, in our view, there is some risk that any substantial PPA amendment agreements which are executed after the Effective Date may need to ensure that the PPA is also amended to become consistent with Regulation 10/2017 (as amended).

General risk allocations

Regulation 10/2017 (as amended) mandates the general risk allocations under Indonesian PPAs, as follows:

Click here to view the table. 

Deemed dispatch for force majeure eventsAs noted above, most of these general risk allocations are broadly consistent with those previously typically applied in Indonesian PPAs with PLN prior to the issuance of Regulation 10/2017. Further, as noted above, Regulation 49/2017 has now removed the risk of change in policy or regulation from the list of risks to be shared by PLN and the IPP.

Under the existing typical Indonesian PPA provisions (prior to Regulation 10/2017), in the event that PLN’s grid is disrupted due to a force majeure event, PLN would be under an obligation to make deemed dispatch payments to the IPP. This is to ensure that the IPP is not unfairly prejudiced (and can continue to satisfy its financing repayment obligations) during such a force majeure event. However, Regulation 10/2017 (as amended) specifically releases PLN from the obligation to make deemed dispatch payments in such circumstances. This change in the risk allocation for force majeure events is likely to raise a material bankability concern for Indonesian power projects. It remains to be seen whether or not financiers will be willing to grant IPPs suspension of payments relief during such a force majeure event. Otherwise, IPPs may need to obtain insurance to cover against this risk.

Take or pay commitment

Under Regulation 10/2017 (as amended), PLN is required to purchase electricity which is produced by the IPP pursuant to the PPA for a “certain period” which has been agreed between the parties. Regulation 10/2017 (as amended) states that the “certain period” will be agreed between the parties by considering the repayment period of the IPP’s lenders. If (as potentially suggested by Regulation 10/2017 (as amended)), PLN’s take or pay commitment is limited only to the senior debt period, then this would represent a material change to the economic profile of Indonesian power projects.

However, based on our informal, no-names discussions with MEMR, we understand that the Government intends for PLN to consider not just the repayment period of the IPP’s lenders but also the period required for the IPP to receive its investment/equity return. It remains to be seen how the provisions of Regulation 10/2017 (as amended) will be interpreted by PLN in preparing its new precedent PPA.

Mandated BOOT Scheme

All PPAs subject to Regulation 10/2017 (as amended) must adopt a Build, Own, Operate and Transfer (BOOT) scheme. Under this scheme, at the end of the term of the PPA, PLN will become the owner of the power plant project. Previously, this BOOT scheme was, in practice, most commonly adopted for conventional power plant projects. As discussed further below, Regulation 50/2017 has also extended this concept to various new and renewable power projects.

Transfer Restrictions

Regulation 10/2017 (as amended) expressly restricts the transfer of the IPP sponsor’s direct shares in the relevant project company until the project achieves the Commercial Operation Date. This general transfer restriction is consistent with the provisions typically seen in Indonesian PPAs with PLN and other recently issued regulations. However, importantly and unlike most sponsors’ agreements, Regulation 10/2017 (as amended) does not provide any exception for this restriction in relation to pledges or assignments pursuant to project financing arrangements. As a result, this could continue to affect the bankability of Indonesian power projects. Regulation 10/2017 (as amended) does, however, provide an exception to this transfer restriction for transfers to affiliates whereby the affiliate’s shares are more than 90% owned by the sponsor wishing to transfer the shares. This very limited 90% ownership threshold is significantly higher than the 25% or 50% ownership threshold typically previously found in Indonesian power project sponsors’ agreements prior to the issuance of Regulation 10/2017.

2. Natural Gas Use for Power Plants

In a purported effort to increase the utilisation of natural gas and to secure domestic gas supply for Indonesian power plants, MEMR recently issued Regulation 45/2017 to revoke and replace the (also) recently issued Regulation 11/2017. While Regulation 45/2017 broadly follows the regulatory framework introduced by Regulation 11/2017, Regulation 45/2017 has introduced several key changes as discussed further below.

Similar to Regulation 11/2017, under Regulation 45/2017, the calculation for the natural gas price for power plants depends on its point of delivery/transfer. However, Regulation 45/2017 has further clarified how the natural gas price will be calculated based on whether it is delivered to the upstream delivery point, the plant gate or at another point. In addition, pursuant to Regulation 45/2017 the tariff applicable for the transportation of natural gas other than through natural gas pipelines will be determined by MEMR (rather than being based strictly on economic or market value).

One of the most significant changes introduced by Regulation 45/2017 is that for power plants not located at a natural gas wellhead, PLN and IPPs may purchase natural gas through gas pipelines at the plant gate at a maximum price of 14.5% of the Indonesia Crude Price (ICP) (rather than 11.5% of ICP/MMBTU as previously prescribed by Regulation 11/2017). To the extent that PLN and IPPs cannot secure the purchase of natural gas through gas pipelines at the plant gate at a maximum price of 14.5% of the ICP, then PLN and IPPs may purchase LNG at the plant gate (provided that the price of such LNG (including regasification and distribution costs) is less than the price of natural gas available through gas pipelines). Further, to the extent that the price of domestic LNG at the plant gate is the same (and on the same terms) as the price of imported LNG at the plant gate, then PLN and IPPs must purchase the domestic LNG. The maximum price for the purchase of natural gas at the wellhead has not been amended by Regulation 45/2017.

Previously (and somewhat unrealistically) Regulation 11/2017 required natural gas contractors to ensure the sufficiency of natural gas supply for 20 years (being the standard term of Indonesian PPAs). However, Regulation 45/2017 has clarified that natural gas contractors must now only ensure the sufficiency of natural gas supply based on the estimated condition and reserve of the relevant natural gas field. Further, if the natural gas contractor obtains an extension to its production sharing contract, then the contractor must also extend its gas supply agreement with PLN or the relevant IPP.

3. The Utilisation of New and Renewable Energy for Electricity Supply

Regulation 50/2017 (which revokes and replaces Regulation 12/2017) contains a generally similar regulatory framework for new and renewable energy power plants to the framework previously set out in Regulation 12/2017. The two key changes introduced by Regulation 50/2017 relate to the appointment process and the electricity pricing mechanism for new and renewable energy power projects.

The new appointment processes for new and renewable energy power projects under Regulation 50/2017 are direct selection or direct selection with a capacity quota (which replaces the auction and reference price processes included in Regulation 12/2017). Pursuant to Regulation 50/2017, PLN is required to arrange and publish technical guideline(s) on the implementation of such direct selection process as well as publish a new standard PPA, to expedite the process for the purchase of electricity based on the revised regulatory framework.

In relation to electricity pricing, one of the main criticisms of Regulation 12/2017 was that new and renewable energy projects in certain local grids (particularly in Java and certain parts of Sumatera) were being required to directly compete with numerous local low-price coal fired power plants, effectively making such new and renewable energy projects economically unfeasible. However, the new pricing mechanism for new and renewable energy power projects under Regulation 50/2017 is that in circumstances where the PLN electricity supply cost is equal to or lower than the average national PLN electricity supply cost (BPP), the sale price for the electricity purchased by PLN from relevant IPP shall be based on mutual agreement. While uncertainty remains in relation to how this pricing mechanism will be implemented in practice, in general, this amendment should be a welcome relief to new and renewable energy sector.

The details of these changes are set out in the table below (which, for the first time, now also includes sea water movement and temperature energy):

Click here to view the table. 

It should also be noted that Regulation 50/2017 no longer uses the term “benchmark price” for the electricity price – instead, Regulation 50/2017 uses the term “sale price”. We understand that the term “benchmark price” was used by MEMR for accelerating the procurement process for the purchase of electricity by PLN from an IPP (whereby PLN and IPP would not be required to obtain MEMR approval for an electricity price which is based on the “benchmark price”). However, as Regulation 50/2017 now refers to “sale price” (instead of the “benchmark price”), all electricity sales for new and renewable power plant projects must now obtain an electricity price approval from MEMR.

In addition, Regulation 50/2017 now provides that all new and renewable energy projects (not just hydro and geothermal projects), other than waste power projects, must be awarded on a BOOT basis. This is broadly consistent with the regulatory regime set out in Regulation 10/2017 (as amended).