The Indonesian government has recently passed new regulations introducing significant changes to the power and upstream oil and gas sectors. In this briefing note, the first in a series, Sean Prior, Counsel of Mayer Brown JSM and Fadjar Kandar, Managing Partner of Kandar & Partners highlight the latest developments in the power sector and their likely impact on Indonesian investment.

Changes in the Power Sector

WHAT ARE THE KEY CHANGES?

a. In January 2017, Indonesia’s Ministry of Energy and Mineral Resources (MEMR) issued three power-related regulations which make changes, respectively, to:

i. Terms and conditions of PPAs, under Regulation No. 10 of 2017 on Principles of Power Purchase Agreements (Regulation 10);

ii. Gas and LNG pricing for power plants, under Regulation No. 11 of 2017 on Utilisation of Natural Gas for Power Plants (Regulation 11); and

iii. Tariffs for renewable energy, under Regulation No. 12 of 2017 on Utilisation of Renewable Energy for the Provision of Power (Regulation 12).

WHAT ARE THE KEY IMPACTS ON INDONESIAN PPA TERMS?

a. Regulation 10 purports to introduce what the Government believes is a more equitable split of commercial risks between independent power producers (IPPs) and PLN. The two most significant changes under Regulation 10 are: (i) how the risk of government acts or omissions is allocated; and (ii) potential removal of the capacity-based PPA income stream once the IPP has repaid its senior debt.

b. Under current PPAs, if the government acts, or fails to act, in a way which constitutes a political force majeure event (including a change in law or the unfair refusal of a permit) then, under a standard PPA, the IPP may terminate the PPA after 180 days and sell the plant to PLN at a price sufficient to repay the senior debt. The IPP is typically entitled to a price adjustment as well should a political force majeure event occur. Regulation 10 requires, instead, that PLN and the IPP both bear the risk of a “change in policy or regulation (government force majeure)”. Rather than explaining how that risk should be allocated between them, Regulation 10 states that this point will be regulated under the PPA. If the next form of PPA issued by PLN reduces IPP protection in this area, this is likely to be of significant concern to international sponsors, as without a right to transfer the plant for a price equal to (at least) a senior debt payout, sponsors may struggle to attract sufficient international funding on a project finance basis.

c. Under existing conventional PPAs, PLN’s monthly payment is made up of a capacity component and a variable component. This formula is well understood and accepted as bankable in the market. Regulation 10 states that: (i) PLN is only required to take and pay for electricity produced by the IPP for a certain period of time; and (ii) this period of time should be agreed between the parties by considering the period of repayment to the IPP’s lenders. This provision has, therefore, triggered concern among developers that the next model PPA issued by PLN may not provide for capacity payments once the IPP has paid off its senior debt. It is also unclear how a refinancing would be treated in this context. 2 Mayer Brown JSM | Indonesia Briefing: Latest Changes in Energy Law (Part 1)

d. Other changes include the following:

i. Regulation 10 requires the developer to transfer the plant to PLN at the end of the PPA period (i.e., 30 years). This is already a requirement for coal plants, but has not been a requirement for geothermal or hydro plants. This loss of residual value will impact the way in which a developer would calculate the potential value of developing such a plant.

ii. Regulation 10 also introduces increased restrictions on share transfers in the IPP. Before COD, transfers of shares in the IPP will be restricted except to a 90% owned affiliate. Even after COD, a sponsor will still need PLN’s approval to sell shares.

c. These changes are potentially significant and, if they reduce protections which have been key to what has historically been a bankable IPP template, this will trigger significant concerns among developers and financiers. However, it is important to note that: (i) the language of Regulation 10 is broad and conceptual; and (ii) the government has also made a number of public statements suggesting it does not intend to change the PPA model significantly. Indonesia frequently issues regulations which are open to a wide degree of interpretation, because it creates greater flexibility in implementing policy. Therefore, it is possible that the government intends these new rules to work in a manner which does not remove the key bankability pillars of the current Indonesian PPA form. However, Regulation 10 has introduced significant uncertainty which will remain and likely reduce activity in the market until either the next round of PPAs or further implementing regulations clarify how these principles will be applied in practice.

ARE EXISTING PPAS AFFECTED BY THE CHANGES?

a. No. Projects with an existing PPA, a letter of intent or which have reached bid closing stage before the issuance of Regulation 10 are not required to implement the changes. Furthermore, Regulation 10 will not apply to any ongoing amendment process for an existing PPA that commenced prior to the issuance of Regulation 10.

b. Regulation 10 does, however, apply to power projects that are in a procurement process but have not yet reached bid closing.

c. Regulation 10 does not apply to mini-hydro (less than 10 MW), wind, solar, biogas or city waste to energy power plants since they are subject to separate MEMR regulations.

HOW DOES REGUL ATION 11 OF 2017 AFFECT GAS PRICING?

a. Regulation 11 aims to increase PLN’s use of gas in Indonesian IPPs. Regulation 11: (i) sets a ceiling price for gas used in IPPs; and (ii) sets out circumstances where PLN or an IPP can import LNG to use in a power plant.

b. The ceiling price for gas to be used in a power plant is set at 8% of the Indonesian Crude Price (ICP) per mmBtu for wellhead plants, and 11.5% of ICP for non-wellhead plants. For non-wellhead plants, PLN or the IPP may use LNG instead of gas if the gas price exceeds 11.5% of ICP.

c. Regulation 11 stipulates that if the LNG price is higher than 11.5% of landed costs of ICP (FOB excluding transportation costs), PLN or the IPP may import LNG provided that the price of the LNG is no greater than the 11.5% ceiling. If the price of imported LNG is above the ceiling, PLN or the IPP must instead buy pipeline gas or domestic LNG, but can pay a price greater than the 11.5% ceiling.

d. The price of pipeline gas is set based on economic viability, without escalation.

e. Regulation 11 imposes a continuing requirement to comply with these price restrictions. However, many long-term gas or LNG purchase contracts are based on a variable price formula. Regulation 11 does not address what would happen if, under such a variable price formula, the price were to move beyond the regulatory limit. The parties may be required to cap any contract price at the regulatory limit. Regulation 11 does not, however, require that existing LNG or gas supply agreements for power plants be amended. 3 Mayer Brown JSM | Indonesia Briefing: Latest Changes in Energy Law (Part 1)

HOW DOES REGUL ATION 12 OF 2017 AFFECT RENEWABLE ENERGY PRICING?

a. Regulation 12 now sets the tariffs for solar, wind, hydro, biomass, biogas, city waste to energy, and geothermal power plants.

b. The basic rule under the regulation is that a renewable tariff is capped at 85% of the electricity supply costs (BPP) for the region in question, and 100% of BPP for geothermal and city waste to energy plants, provided the regional BPP is higher than the national average. If the regional BPP is lower than the national average, then the tariff is capped at 100% of the BPP, unless otherwise agreed in the case of geothermal and city waste to energy plants. The purpose of this rule is to reduce the average BPP (i.e., the cost of generation) across Indonesia.

c. Where electricity is generated by high technology sources heavily dependent on local conditions (essentially solar and wind), the price will be based on a capacity quota auction, with a minimum quota size per auction of 15 MW across one or more projects. Prices are otherwise set by direct appointment or by a reference price (which is presumably the price calculated under item (b) above, but no detail has been provided regarding how the award process would work in practice).

d. Article 11 of Regulation 12 raises a specific concern for geothermal developers, since it states that PLN may only purchase power from a geothermal IPP in accordance with proved reserves after exploration. Geothermal developers will not want to commit significant time and money to projects without a PPA to lock in guaranteed offtake and pricing, so it remains to be seen whether a PPA that is conditional upon proving reserves will be sufficient to satisfy this Article (and be acceptable to PLN).

e. The government’s stated aim in issuing Regulation 12 is to provide greater certainty. Industry players have, however, raised a number of additional concerns about the regulations. These include reservations that the incentives are not strong enough, that some of the rules have been tried before with geothermal power without success and that the frequent changes in regulations create greater uncertainty over whether the law will be applied consistently in the future. That said, this last comment is a recurring theme in most Indonesian sectors.