15 August, 2017
Three new regulations have been introduced in Indonesia this year, aiming to standardise and speed up negotiations over power purchase agreements (PPAs), the use of natural gas for electrical power generation, and the use of renewable energy. However, the changes have raised concerns in the power industry.
The first of the three regulations aims to regulate the PPAs between Indonesia's state-owned electricity company PT Perusahaan Listrik Negara (PLN) and independent power producers (IPPs) and covers commercial aspects for all types of power generators including thermal power plants, geothermal power plants, hydroelectric power plants and biomass generators.
The regulations aim to increase standardisation in the negotiation of PPAs across all electricity projects in Indonesia, particularly on smaller non-tendered projects. They impose mandatory requirements which more or less reflect those in existing PLN thermal, geothermal and hydroelectric PPAs. The benefits of saving time and money at the bid and negotiation stage have to be balanced with the restrictions on how IPPs can best design solutions to capacity issues.
All projects must now be based on a build, operate and transfer (BOOT) arrangement, as opposed to the traditional build, own, and operate (BOO) basis and the term of the PPAs must not exceed 30 years commencing on the commercial operation date (COD), taking into account the type of power plant used for a particular project.
IPPs would need to assess the risk and economic viability of this model in relation to each of their projects.
Additional penalties have also been introduced relating to the IPP's performance obligations. For example, if an IPP fails to achieve the mega volt ampere reactive power requirements, frequency monitoring requirements and ramp up and down instructions from PLN dispatch centres, it will have to pay a penalty to PLN. The amount of that penalty is set out in the PPA.
A recent amendment to this regulation restricts the transfer of shares in IPPs, which will now require approval by the Ministry of Energy and Mineral Resources (MEMR). Such transfer may only be made after the power plant achieves commercial operation. Prior to the COD, transfer of shares may only be made by a sponsor to an affiliate in which the sponsor owns at least 90% of the shares. Prior to this latest amendment, transfer of shares after the COD was permitted with PLN's approval and the MEMR was to be informed accordingly. This amendment will diminish the effectiveness of any upfront approval given by PLN in the PPA for changes in shareholdings. Perhaps more significantly it appears not to carve out transfer of shares to or by financiers on enforcement. This will not affect new projects where, at the cost of more administration and legal fees, sponsors can devise a two level investment but must put lenders to existing projects on notice of a potential weakness in their security.
These changes alongside others relating to risk allocation between the IPP and PLN have been said to raise bankability concerns in relation to future PPAs, although the extent to which concerns are warranted remains to be seen. PLN is quite within its rights to set the terms for its own contracts, but those terms have to be attractive and bankable if projects are to be developed.
The second regulation covers the use and the price of natural gas as fuel for electricity generation. It aims to ensure that natural gas is available at a fair and competitive price, and to control both the development of power plants using natural gas fuel and the process of natural gas allocation to these power plants.
In accordance with the regulation, the MEMR may allocate certain volumes of natural gas originating from PSC contractors, with the appropriate upstream licences, for purchase by PLN or IPPs. Besides obtaining natural gas based on such allocations, PLN or the IPPs can purchase natural gas directly from licensed third party traders under certain circumstances.
Allowing the IPPs to directly appoint natural gas suppliers is to be applauded, although it is peculiar that PLN can also appoint suppliers without discussion with Perusahaan Gas Negara (PGN) or Badan Pengatur Hilir Minyak dan Gas Bumi (BPH Migas), the state-owned gas company and the downstream gas regulator, respectively.
In addition, MEMR will determine the price of natural gas for power plants based on several factors such as the economic value of the field, with no escalation, domestic and international price of natural gas, domestic purchasing power, and the level of infrastructure and the location of the power plants. If an escalation is required, the escalation amount must be mutually agreed.
There are price ceilings applicable to the purchase of natural gas by power plants. The procurement price for natural gas by power plants located at wellheads is capped at 8% of the Indonesian Crude Price (ICP) per million British thermal units (MMBTU) at the power plant gate in the event the procurement is made by way of a direct selection. However, if the power plants wish to procure natural gas at a price higher than the ceiling price, the procurement would need to be undertaken by way of an open tender.
Power plants not located at the wellheads may purchase natural gas at a maximum price of 11.5% ICP / MMBTU and PLN or IPPs would be permitted to use liquefied natural gas (LNG) instead of natural gas if the gas price exceeds the maximum. The LNG price will be calculated based on the economic value of the field and using a formula agreed at a free on board (FOB) price.
If the domestic LNG price (FOB) is higher than 11.5% ICP / MMBTU (parity to oil), PLN or the IPP may import LNG provided that the price of the imported LNG is no greater than 11.5% ICP / MMBTU at the purchaser's regasification terminal (landed price). The pricing bottom line under this regulation seems to be that if the imported LNG and natural gas prices are more than 11.5% ICP / MMBTU (at landed price) then PLN or the IPP can go anywhere else to buy domestic LNG or natural gas and there does not seem to be any restriction on the price which can then be paid once shown that the price is more than the ceiling.
Domestic LNG and natural gas are given first priority, which will be good for the Indonesian upstream industry. Taking into account transportation costs, these should always be cheaper than imported equivalents if only because the sellers have no alternative market. However, it remains to be seen whether the regulated price offered for either piped natural gas or LNG will be sufficient to incentivise the gas / LNG supplier as well as the upstream players to develop the reserves or make the supplies otherwise available to the power sector.
The pricing formulae under the regulation also seem rather simplistic and it may be possible to add 'extras' to generate the final price, but still come within the stated pricing caps.
This second regulation was enacted as a part of the government's effort to strengthen the gas market by increasing demand and attractiveness to investors. That said, analysts have commented that Indonesia's gas market is poised to undergo critical changes in the near future as demand is projected to rise faster than production. Should this happen, Indonesia may soon be a net importer of natural gas and there would be concerns on securing gas supply for the power sector in future.
The last of the new regulations covers the purchase of electricity from plants powered by renewable energy sources. It aims to promote the adoption of new technologies by the IPPs and focuses on increasing the efficiency of the power plants so as to allow a more affordable electricity price for Indonesian people. The regulation also sets a maximum or benchmark price for electricity produced by the renewable energy power plants. The latest revision to the regulation introduced in July amended the tariff formula for electricity generated by hydroelectric power plants while retaining the formula for other renewable energy power plants.
Based on the revised regulation, if the electricity supply cost of a region is higher than the national average, the renewable power tariff will be capped at 85% of the relevant regional electricity supply cost save for city waste power plants (PLTSa), geothermal power plants (PLTP) and hydroelectric power plants (PLTA) where the power tariff will be capped at the electricity supply cost of the relevant region.
When the electricity supply cost of a region is equal to or lower than the national average, the renewable power tariff will be equal to the relevant regional electricity supply cost save for PLTSa, PLTP and PLTA where the electricity price will be mutually agreed by the parties.
The regulation is largely driven by PLN and government’s desire to reduce government subsidy to PLN. Previous to the promulgation of these regulations, there was a high feed-in tariff for renewable energy. Nevertheless, PLN was failing to enter into significant numbers of PPAs with renewables developers.
While the aim is to ensure that PLN’s procurement of electricity from renewable energy sources is made at the lowest price possible, the price ceilings are likely to render many renewable energy projects uncompetitive except for onshore wind in Sulawesi and renewables generally in the outer islands where electricity prices are much higher than on Java / Sumatra. The difficulty for developers with the outer islands is that significant logistics constraints make the capital cost of development significantly greater there and there is less confidence in their ability to deal sensibly with local governments around matters such as permits. A further flaw in the price methodology is that it treats 'intermittent' energy sources, such as wind and solar that need back up from diesel or gas generators, in the same way as more reliable sources such as biomass or biodiesel. This could reduce the likelihood of achieving the Indonesian government's ambitious target of 25% of the electricity generation coming from renewable sources by 2025.
The PLN has not signed many renewable energy PPAs, so the new regulation may actually increase the number of projects it pursues by giving a clear indication of what projects are viewed as competitive. We will have to wait to see whether this new regime will translate into a significant, or indeed any, increase in renewable energy projects brought into operation.
For further information, please contact:
Ian Laing, Partner, Pinsent Masons
ian.laing@pinsentmasons.com
