Indonesia’s attempts to diversify its energy mix have had limited success so far. The government is trying to tweak the regulations to support pre-election policies but will investors benefit from the changes?
Indonesia’s plan to add natural gas power generation has attracted several international investors but progress has been slow so far.
Three years have passed since state-owned utility Perusahaan Listrik Negara (PLN) launched several tenders for gas-fired peaker power generators. Those independent power producer (IPP) projects have been inching forward because of delays finalizing out gas supply terms.
A consortium of Marubeni, Indonesian state-owned oil and natural gas corporation Pertamina and Sojitz signed a power purchase agreement (PPA) in 2017 for the 1,760MW Java 1 gas-fired power plant and floating storage and regasification unit (FSRU) project. In the same year, a Medco-Ratchaburi Electricity Generating Holding (RATCH) joint venture signed a PPA for the 275MW Riau piped gas IPP.
Neither has reached financial close within the usual 12-month timeframe.
The challenge in gas-fired projects has been in matching the terms of gas supply with the terms of the PPA to provide a seamless risk allocation, says Laurie Pearson, Of Counsel at Norton Rose Fulbright.
The biggest hurdle has been how to allocate liability for take-or-pay obligations
“The biggest hurdle has been how to allocate liability for take-or-pay obligations under the gas supply arrangements and gas supply force majeure”, she explains.
PLN is responsible for fuel supply to the projects in addition to being the power offtaker, so it is incumbent on the state utility to assume these risks, she says.
The project company will need to be insulated from events outside of its control that disrupt the IPP’s operation and may give rise to continuing take-or-pay obligations under the gas supply agreement.
If PLN is responsible for gas supply, then typically, there will be a compensation in case of failure to supply in the form of deemed dispatch provisions / capacity payment being met in these circumstances, adds SMBC’s Head of Project and Export Finance Luca Tonello.
PLN will supply the fuel for all new gas-fired projects and bear the impact of gas price fluctuations.
To shield the national utility from price hikes and maintain electricity tariffs for consumers, the Indonesian government has tried to maximise the procurement of natural gas for power plants from domestic sources while also trying to lower the price of domestic gas to be used for power generation.
In 2017, the Ministry of Energy and Mineral Resources (MEMR) issued a regulation that set the maximum purchase price of natural gas at the plant gate at 14.5% of the Indonesian Crude Price (ICP).
This results in gas pricing of USD 8 – 8.9 per million British thermal unit (MMBTU) based on an ICP of around USD 60-70 per barrel.
The calculation of the gas price still refers to the Indonesian crude price so if the ICP price increases then the gas price becomes more uncompetitive for power plants. That is why the MEMR is working on regulation of gas prices for power plants, notes a project finance lawyer, because from the ministry’s perspective the prevailing gas price is still considered too high and uncompetitive.
At the same time MEMR is trying to press down on tariffs that might have been in principal agreed with the power project, the lawyer adds.
The energy ministry is targeting a gas price of USD 7 per MMBTU and intends to introduce new rules for gas for power projects by the end of this year, MEMR’s Electricity Director General Andy N. Sommeng said in May.
The mechanism could be similar to the regulation issued in March that caps the price that PLN or domestic power producers will pay for local coal for power generation. The cap at USD 70 per ton for two years was 30% below the market price at the time.
While there is no sanction for failure to comply with the benchmark price, the government does provide an incentive for coal companies fulfilling their domestic market obligation (DMO) and complying with the coal benchmark price. The incentive is a 10% increase in allowed annual production capacity.
The DMO is set by MEMR every year to ensure that a minimum percentage of domestically produced coal, oil and gas are allocated for use within the country.
Tonello says that MEMR’s efforts to regulate natural gas prices for power plants are a positive development for gas-fired IPPs. This is because the energy ministry will have additional control of the gas price charged to IPPs and ultimately to PLN and power consumers, as the gas price is generally a pass-through under the PPA.
Gas price is … a key incentive for PLN to develop additional gas-fired power plants
“While gas price is not a variable taken into account to determine gas-fired IPP profitability, it is a key incentive for PLN to develop additional gas-fired power plants if gas prices charged to IPPs/PLN makes more economic sense to PLN versus competing fuel sources in its fuel mix”, he elaborates.
The retail price of electricity is controlled by the government and not by PLN so when the cost of energy production increases it cannot pass those costs through to consumers. As per national policy, power generated from different fuel sources must sell for the same retail price.
Coal-fired generation will always be cheaper than gas-fired power in Indonesia, notes Wood Mackenzie senior analyst Edi Saputra.
The levelised cost of electricity (LCOE) from coal ranges around USD 45 to 60 per MWh while for piped gas supplied combined cycle plants it is USD 65 to 85 per MWh, he says. LNG is higher – between USD 85 to 100 per MWh – because of the additional cost of regasification.
For example, the Java 3 power plant to be built by PLN subsidiary Pembangkitan Jawa-Bali (PJB) and a private sector partner – in Gresik, East Java province – will use piped gas from the Jambaran and Tiung Biru gas fields in Cepu block gas.
PLN will pay around USD 7.6 per MMBTU at the plant gate which is more competitive than LNG prices, Saputra says.
LNG could cost around USD 10 per MMBTU, including regasification, assuming linkages to oil prices around USD 60-70 per barrel, he explains.
Indonesia has extensive proven gas reserves of 102 trillion cubic feet but as an archipelago, it does not have a nation-wide pipeline network for distribution. Domestic liquefaction and regasification facilities are required to move natural gas from producing areas to consuming areas.
In several markets like West Java or North Sumatra PLN cannot rely on piped gas anymore because production is in decline and depleting in terms of gas supply so they have to move to LNG, Saputra says.
He expects the LNG to come mainly from domestic projects in Kalimantan, Papua, Tangguh and Bontang right and maybe in the future Abadi.
Looking at the supply demand balance in the near term, Saputra says there is a lot of domestic surplus and Indonesia will offer around 3 million tons of uncontracted gas to the spot market this year. LNG demand in the country is forecast to be 2.8 million tons in 2018.
Pertamina has said that Indonesia expects to start importing LNG from 2020 as demand outstrips supply.
The increase in LNG will bring an increase in total cost as well, which is why PLN prefers to have more coal for baseload plants and use gas to meet the fluctuating demand during the peak period.
The Indonesian government in March officially lowered the amount of gas-fired power generation it intends to add as part of a reduction in total new capacity from all fuel sources, because electricity sales at PLN grew at around 3% in 2017 instead of the expected 8.3%.
Around 14.27GW of gas-fired generation is included in PLN’s Electricity Supply Business Plan (RUPTL) for 2018-2027.
Despite the scaling back and pace of progress, Marubeni and Korea Electric Power Corporation (KEPCO) were among investors competing to partner with PJB for the 800MW Java 3 IPP.
That project and Nebras Power and PJB’s 800MW Sumbagut power plant and FSRU are understood to be the new IPPs going ahead and engaged in negotiating PPAs with PLN.