The Indonesian government has introduced a number of recent changes to energy regulation including changes to 'government force majeure' risk allocation, efforts to improve electricity infrastructure, notification of IPP shareholding composition and management changes, and updates to regulations on renewable energy for electricity.
Government force majeure risk allocation – resolving bankability concerns
Together with several other recent Regulations of Indonesia’s Minister of Energy and Mineral Resources (MEMR), the MEMR has issued Regulation No. 49 of 2017 (Regulation 49) to amend Regulation No. 10 of 2017 on Power Purchase Agreement Principles (Regulation 10). Regulation 10 is discussed elsewhere in this update.
Regulation 49 removes the sharing of risks arising from changes to government policy or regulation (government force majeure) set out in Regulation 10 so that government force majeure risks no longer have to be allocated to both PT PLN (Persero) (PLN) and the project company. Consequently, Regulation 49 removes relief from obligations arising from a policy change that causes a project to be terminated or a power plant to become inoperable. Such relief was previously afforded to both the project company and PLN under Regulation 10.
These changes appear to have been welcomed by power plant developers, since the risk allocation and relief set out in Regulation 10 had raised bankability concerns.
Unfortunately, issues still remain concerning the absence of deemed dispatch payment by PLN in case (a) the government force majeure affects the ability of the project company to generate power, or (b) natural force majeure causes PLN to be unable to distribute the electricity generated by the project company.
Regulation 49 does not contain transitional provisions. While Regulation 49 does not specifically permit power purchase agreements (PPAs) signed since the issue of Regulation 10 to be amended so that the parties can benefit from it, we believe that they can.
With the issuance of Regulation 49, PLN and project companies will again need to negotiate the PPA provisions on risk allocation relating to and arising from government force majeure. However, the parties can now agree for the risks to be allocated to the party that can best manage them.
Government efforts to boost electricity infrastructure in Indonesia
In an effort to achieve the targeted electrification ratio and to encourage efficient, fair and transparent electricity supply, Indonesia’s Ministry of Energy and Mineral Resources (MEMR) issued three regulations in early 2017:
- Regulation No. 10 of 2017 on Power Purchase Agreement Principles (Regulation 10)
- Regulation No. 11 of 2017 on Utilisation of Gas for Electricity Generation, later replaced by MEMR Regulation No. 45 of 2017 on the same topic
- Regulation No. 12 of 2017 on Utilisation of Renewable Energy Resources for Provision of Electricity, later replaced by MEMR Regulation No. 50 of 2017 on the same topic.
We discuss here some issues arising specifically from Regulation 10.
Regulation 10 intends to regulate certain provisions in a power purchase agreement (PPA) between the state electricity company PT PLN (Persero) (PLN) as the off-taker, and independent power producers (IPPs).
Interestingly, the regulation also covers commercial aspects of the sale and purchase of electricity, whereas in the past these aspects were always subject to negotiation between PLN, the IPP and the commercial lenders to the project, taking into account precedents for PPA projects that had reached financial close.
The new regulation applies to all power projects, including geothermal, biomass and hydropower projects. It excludes intermittent power projects such as mini-hydro power plants, which will be subject to separate regulations.
Regulation 10 requires that a PPA between PLN and an IPP should include at least the following provisions:
Regulation 10 will affect how PPAs are drafted and negotiated between PLN and IPPs going forward. Below are some of the key changes to the existing PPA model arising from Regulation 10.
|Issue||Old PPA Model||Changes under Regulation 10|
|Project Scheme||Projects are awarded under a Build, Own, Operate, Transfer (BOOT) scheme, or in the case of geothermal and hydro projects, under a Build Own Operate (BOO) scheme.||All projects to be awarded under a BOOT scheme.|
|Deemed Dispatched in Force Majeure||Deemed dispatch occurs if PLN is unable to receive electricity within a certain grace period (including due to a force majeure event) such that PLN is obliged to pay for the electricity in full. The length of the grace period is subject to negotiation between PLN and the IPPs, taking into account the specifications of the particular power plant, among other things.||PLN is not obliged to pay deemed dispatch if it arises from a force majeure event.|
|Take or Pay Commitment||Take-or-pay commitment is generally for the full term of the PPA.||The language in Article 6(3) suggests that the take-or-pay commitment of PLN may be limited to the duration of the financing repayment term, as opposed to the duration of the PPA. The intent of this provision is unclear.|
|Penalties||Provides certain penalties, including penalties for failing to meet the applicable availability targets, reactive power requirements, and frequency requirements.||Adds some new penalties, including penalties for failing to meet PLN dispatch centre instructions to ramp up or ramp down.|
|Transfer of Shares Restriction||Typically requires sponsors to maintain ownership of a certain percentage of shares in the IPP company until the project’s COD, for example, five years after COD.||Transfer of shares in the IPP company is permitted, except for a transfer to an affiliate of the sponsor that is more than 90% owned by the sponsor. Any transfer of shares in the IPP company after the project’s COD is only permitted upon approval in writing from the purchaser, and the transfer must be reported to the MEMR through the Director General of Electricity.|
|Definition of Government Force Majeure||Captures changes in policies, regulations and law||Appears to capture only changes in policies and regulations and to exclude changes in law. The wording of Articles 8 and 28 will need clarification as it appears to be contradictory with respect to whether changes in law can be considered Government Force Majeure.|
|Risk of Government Force Majeure||Current PPA precedents are negotiated on the basis that a risk should be allocated to the party best able to manage and mitigate the risk. In line with this principle, current PPA precedents stipulate that PLN as a state enterprise bears the risks related to government force majeure, including changes in government policies and regulations.||Responsibility for risk of government force majeure is shared between PLN and the IPP. The PPA will detail how that is allocated. In principle, where a change in policy prevents a power project in development from continuing, or an existing power plant from operating, then PLN and the IPP are released from their obligations.|
In August 2017, Regulation 10 was amended by Regulation 49, which deleted the provisions on Government Force Majeure. Regulation 49 has been discussed in more detail earlier in this paper.
Several other provisions of Regulation 10 are also noteworthy:
the PPA term must not exceed 30 years from the project’s COD, depending on the type of plant
under a PPA, the calculation of the capacity fee (component A) on the electricity sale price is based on the investment value having depreciated for at least 20 years
where a change in law results in a higher cost impact to the developer, the tariff will be adjusted to compensate
PLN may request the IPP to accelerate the COD in return for incentives (to be specified in the PPA); likewise, the IPP will face certain penalty payments upon failure to meet an accelerated COD that has been agreed
if PLN is unable to purchase the electricity produced under the PPA, PLN must pay the IPP a penalty (take or pay) in proportion to the investment component.
Impact on existing projects
All related power projects whose tender processes have commenced but which have not reached bid closing, and all future related power projects, must comply with Regulation 10. However, Regulation 10 does not apply to PLN projects where:
- bids have already been submitted (ie have reached bid closing)
- the letter of intent (LOI) has already been signed
- the PPA has already been signed, including a price adjustment or amendment to an existing PPA
- in the case of geothermal power projects:
- the project is currently being tendered and a price has been offered
- the winner of the tender has already been determined, or
- the PPA has been signed.
IPP regulation replaced after three weeks
MEMR Regulation No. 42 of 2017 on Supervision of Energy and Mineral Resource Business Activities (Regulation 42 – see legal update on our website here) was issued in mid-July but has already been revoked. Regulation 42 has been replaced by MEMR Regulation No. 48 of 2017 on the same topic (Regulation 48). Regulation 48 also revokes certain provisions on transfers of shares found in MEMR Regulation No. 10 of 2017 on Power Purchase Agreement Principles, issued in January 2017.
Regulation 48 was issued after various industry associations objected to Regulation 42, and requested its cancellation. Their concerns centred on new approval requirements for changes in the shareholding composition or management of energy companies which appeared to go against the current drive towards deregulation and de-bureaucratisation by allowing the government to intervene in corporate management affairs.
Regulation 42 had required prior approval from the MEMR for any transfers of shares or management changes in the Board of Directors or Board of Commissioners of the holders of Electricity Supply Business Licenses or Izin Usaha Penyediaan Tenaga Listrik (Independent Power Producers or IPPs) and other energy companies. Both requirements were omitted from the replacement regulation.
Shareholding composition changes
Similar to Regulation 42, Regulation 48 only permits a transfer of shares in an IPP once the power plant has reached its Commercial Operation Date (COD) and after approval is obtained from the buyer – in this case, state electricity company PT Perusahaan Listrik Negara (Persero). An exception to the COD requirement stays in place for a transfer to an affiliate of the project sponsor (i.e. one level below the sponsor) that is more than 90 per cent owned by the sponsor.
Regulation 48 basically replaces the approval requirement for a transfer of shares in an IPP with a requirement for notification to the MEMR’s Directorate General of Electricity (DGE).
Our reading of the new regulation suggests that the notification requirement for a transfer of shares only applies to transfers of shares in IPPs conducted prior to the COD (subject to the above requirement). However, during the MEMR’s dissemination of the new regulation, it has stated that the notification requirement under Regulation 48 applies to any transfer of shares in IPPs, whether conducted before or after the COD. Clarification on this issue may be needed from the MEMR.
The notification and supporting documents must be submitted within five business days after the Minister of Law and Human Rights (MLHR) acknowledges the shareholding change.
Similar to a transfer of shares, any change to the Board of Directors and/or Board of Commissioners of an IPP must also be notified to the DGE. The notification and supporting documents must be submitted within five business days after the MLHR’s acknowledgement of the management change.
Special provisions for new energy and renewables
For IPPs that generate electricity using new energy or renewables other than geothermal, the notification of shareholding composition and management changes to the DGE must also be copied to the Directorate General of New Energy, Renewables and Energy Conservation.
Note that the provisions of Regulation 48 (including the notification requirements) do not apply to IPPs that generate electricity using geothermal resources.
Regulation 48 aims to simplify the supervision and development of the energy sector by relaxing the requirements set out in Regulation 42 but without abandoning the initial purpose of the regulation, namely to simplify energy sector supervision by Indonesian regulators, particularly for electricity.
Regulation 48 is expected to accommodate investors’ aspirations and address the concerns of business associations about the previous regulation. We believe the rapid response from the Indonesian Government reflects its seriousness in addressing their concerns.
Updates to renewable energy regulations
In early 2017, the Minister of Energy and Mineral Resources (MEMR) issued Regulation No. 12 of 2017 on the Use of Renewable Energy for Electricity Generation (Regulation 12) which set out, among other things, how to determine the tariff for purchasing the electricity generated by renewable projects. Regulation 12 received a mixed response – mostly negative – from stakeholders. This was particularly due to the setting of tariffs, which discouraged investors from pursuing renewable projects in Indonesia. After first being amended in July 2017, Regulation 12 was eventually revoked and replaced by MEMR Regulation No. 50 of 2017 on the same topic (Regulation 50).
Two main changes in Regulation 50 that we wish to highlight, relate to the purchase of electricity from renewable sources.
The first major change relates to the electricity purchase price benchmark. As in the previous regulations, the electricity purchase price benchmark continues to be linked to the main costs incurred by PLN in generating electricity locally and nationally (excluding costs incurred to distribute electricity). In Indonesian, this cost is known as Biaya Pokok Penyediaan Pembangkitan (BPP Pembangkitan). However, Regulation 50 regulates that for renewable power projects located in a region where the BPP Pembangkitan is the same as or lower than the national BPP Pembangkitan, the electricity purchase price will now be determined by mutual agreement between the project owners and PLN, on a B2B basis.
The second major change is that prices for electricity purchases from any renewables must now be approved by the MEMR. This was not a requirement found in Regulation 12.
Regulation 50 also (i) changed the provisions on the purchase of electricity from marine/seawater hydropower plants, and (ii) took out the feed-in-tariff as the basis for purchasing electricity generated from renewable energy sources.
The process for procuring electricity from renewable sources is unchanged– procurement must still be conducted through direct selection. Specifically for solar PV and wind projects, direct selection must be based on a capacity quota.
For renewable power projects in regions where the local BPP Pembangkitan is higher than the national BPP Pembangkitan, the rules stay the same. In brief, the purchase price must not exceed 85 per cent of the local BPP Pembangkitan of the particular region. An exemption applies to hydro, municipal waste and geothermal power plants, where the maximum electricity purchase price can match the BPP Pembangkitan value for the relevant region.
Regulation 50 applies only to projects for which PPAs have not been signed. However, Regulation 50 appears to allow existing projects (ie where the PPA was signed before the issuance of Regulation 50) to apply to the projects the electricity purchase price method set out in Regulation 50. In practice, this would mean asking PLN to renegotiate the PPA purchase price, and then seeking MEMR approval for that new price. However, PLN is under no obligation to entertain such a request.
For further information, please download the PDF below for a table comparing the procurement methods and tariffs found in earlier regulations with those in Regulation 50.
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