Where to put big batteries within Australia’s ‘skinny’ power grid

We have to make sure that the communities we work in are accepting these plans because these are assets that will sit there for 20-25 years

CEO INTERVIEW Where to put big batteries within Australia’s ‘skinny’ power grid

About 400km northwest of Brisbane stands a new 100MW battery energy storage.

Australia’s pursuit of renewable energy brings about a need to set up energy storage systems to address the intermittence of these energy sources. In a market where there is plenty of land an aging coal fleet and this is going to get retired over time. As those assets retire, there is an increasing requirement for solar, wind and offshore capacity to contribute to replacing coal over the next 15 or available and a “unique” power grid, developers are asked—where is a good place to build a battery?

In an interview with Asian Power, Vena Energy CEO Nitin Apte shared the company had two key considerations–good power grid connection and strong demand–when it built the first utility-scale battery energy storage system (BESS) in Queensland, Australia. Nitin emphasised the need to be well-integrated into the community and the power grid operators.

“When we look at locating our sites, we have to make sure that the communities that we work in are accepting these plans because these are assets that will be there for 20 or 25 years,” he said.

The Wandoan South BESS, one of the largest in Australia, stands 400-kilometre northwest of Brisbane in the Darling Downs region. It is connected to Powerlink’s Wandoan South Substation. The project, which has a 100-megawatt (MW) capacity, can store up to 150 megawatt-hours of energy, which is comparable to power about 57,000 households in Australia per year.

Tell us about the Wandoan Southwest Battery Energy Storage System and what drove Vena Energy in developing one of the largest BESS in Australia.

In Australia and generally, in markets where there is high renewable penetration, one of the aspects is renewable energy intermittency because you’re only producing solar energy during the day, you’re only producing wind energy when the wind is blowing. To address intermittency, there is a need for storage where you can store the excess energy generated and dispatch it when there is increased demand or low levels of available generation. That’s the overarching reason why we’re looking at batteries in general, in Australia, and across all our markets.

Australia has a higher penetration than some of the other jurisdictions that we operate in. We selected this location because of two reasons–one is, a battery should be located at a place where you have a good grid connection so that you can readily charge the battery at times when there is excess generation, caused by low demand or high renewable generation. Rooftop solar and solar plants produce a lot of energy during the middle of the day and when coupled with existing baseload generators, exceeds demand. Instead of turning off the solar farms, this energy that is generated can be stored in the BESS and used when demand peaks, normally in the evenings when everybody gets home. This way we can dispatch the stored energy as required to meet the demand.

The second aspect is you want a location for the battery where there is also strong demand. It’s a combination of good connection and strong demand. While Wandoan is 400km from Brisbane, it’s a location where there are newly installed CSG wells that utilise electricity driven compressors to transport the gas to Gladstone. Thus, there’s is good demand in terms of electricity requirements.

We are also currently building the 168 MW Wandoan Solar Project, which is close to the Wandoan South Battery Energy Storage System, and there’s already a high-voltage electrical infrastructure being established at that location. We find that co-locating our solar plants and battery site allows them to utilise shared infrastructure where possible and optimises O&M cost.

How is this project instrumental in the clean energy goals and transition in Australia?

There is an increasing penetration of renewable energy in Australia and a battery or storage system, like ours, addresses both intermittencies as well as provides ancillary services to the grid, in terms of frequency control, and so forth. In general, Australia has 20 years. This transition is why we need to establish not only new generation but also storage. The combination of renewable generation and storage facilities that can assist in profiling the generation to match the demand and provide network services is our strategy to accelerate this transition.

How is Australia performing in terms of the BESS development? What are the challenges that will likely emerge in the market?

In terms of federal regulations as well as state regulations, there is a strong desire and consumer appetite for renewable energy. We have a very strong pipeline in Australia and we are constructing the 167 MW solar plant in Wandoan, as well as the second phase of our Tailem Bend Solar Project in South Australia. The Tailem Bend Solar Project is going to be co-located with our second battery project which is a 41.5MW one-hour storage battery. We are developing a hybrid grid where both the battery and solar farm have single connection point. This is the first of its type in Australia. I think Australia is performing quite well in terms of supporting the renewable transition. Just recently, there have been some announcements on offshore wind as well, in Victoria. This means there is recognition and a desire for renewable energy. There’s plenty of land in Australia, growing demand and good natural resources in general. I think, however, when we look at locating our projects, we have to ensure that the communities that we work in are supportive because these are assets that will be there for 20 years, 25 years. It needs to be well integrated into the community. That’s always a factor that we consider. The second is that Australia has its own very unique grid. In bringing on renewable assets onto the grid, you need to work with the grid operators to make sure that your projects are well integrated into the grid. Getting assets onto the grid is something that must be done properly. We spend a lot of time preparing grid models and working closely with the grid operators to make sure that our projects are well accepted onto the grid.

Any new projects you have lined up in Australia?

We are very active in Australia, and we’ve got a development pipeline in Queensland, New South Wales, and South Australia where we have sites that are under development. Our strategy in general would be to build and co-locate renewable and battery storage in the future. I think that makes sense, but then we’re also looking at stand-alone sites for the battery systems as well, depending on what the grid requirements. We are currently developing an offshore wind project in Victoria called Blue Marlin.

What other Asian markets are you looking at to implement projects in support of their energy transition needs?

Vena Energy is a Pan Asia Pacific renewable company, and we operate in nine jurisdictions. We have over a gigawatt of projects currently under construction across the region. We have been expanding across Asia Pacific over the last several years, and we intend to continue driving that growth. We’re constantly looking at new markets to evaluate both the regulatory environment, the need for renewable energy, the economics, and to be able to evaluate those conditions, in order for us to decide whether we should go into new markets or not. The way I would describe Vena Energy’s business is really our three pillars. One is our core, solar and onshore wind development, and renewable energy production. The second is offshore wind, because there is a great need, if you will, especially in markets where there is land scarcity such as North Asia, Taiwan, Korea, and Japan. Those markets are most suitable for offshore wind development.

COUNTRY REPORT: SINGAPORE Singapore digs deep to unleash geothermal energy potential

But the volumetric extent of hot rock where geothermal can be sourced is unknown.

Sampling site at Admiralty Lane where Romagnoli’s team is doing a study on geothermal energy potential (Photo courtesy of NTU Singapore)

Unlike its Asian neighbours, Singapore has no known shallow heat source. That is why the country exerted more efforts to unearth its geothermal potential to diversify its energy sources. It turned out that its geothermal potential could cover a sizeable portion of Singapore’s energy mix, an expert said.

The country’s Energy Market Authority (EMA) in April issued a request for information to conduct a geophysical investigation project to assess the country’s geothermal energy potential. The EMA said that progress in technologies such as the Advanced Geothermal Systems enabled the extraction of heat from hot dry rock and at greater depths, opening the potential for geothermal applications locally as the country is within a region of high subsurface heat flow.

“If found to have substantial geothermal resource potential, Singapore could consider the technology options available to deploy geothermal energy locally,” the EMA said.

“Singapore has several hot springs and estimated anomalous heat flow. The higher-than-average heat flow could potentially heat up the granite rock underlying Singapore,” said Alessandro Romagnoli, Associate Professor from the School of Mechanical and Aerospace Engineering at the Nanyang Technological University (NTU).

In Singapore, the volumetric extent of the hot rock is unknown, Romagnoli said, adding that it is also possible that the actual potential may be less than what is expected.

According to the International Renewable Energy Agency (IRENA), geothermal resources are thermal energy that is stored as heat in the rocks of the Earth’s crust and interior. Areas with high-temperature water or water vapour at or near the surface were often called “active” geothermal areas. Water or water vapour from fissures to deeper depths in areas saturated with water may be tapped for electricity generation “at relatively low cost.”

If an area lacks such, geothermal energy can still be accessed through drilling to a deeper depth and injecting water through wells to utilise the heat in dry rocks, IRENA said.

Ongoing study

Romagnoli is leading a study by NTU on Singapore’s geothermal energy potential in partnership with TUM Create and Surbana Jurong Group.

The study, which started in October 2021 and is expected to conclude by October 2023, focuses on the northern and eastern regions in Singapore like the Sembawang Hot Spring Park that have higher surface temperatures and are deemed to have potential.

Romagnoli said that the Sembawang Hot Spring is within the Simpang Granite pluton bedrock, citing the latest geological map of Singapore by the Building and Construction Authority. According to a 2019 study by Gillespie et al., the Simpang Granite pluton has a “high concentration of naturally occurring heat-generating elements.”

“Our ongoing study seeks to measure the rocks’ elemental concentration and the temperature of the granites from our deep boreholes. We can better estimate the geothermal energy potential in Singapore when the volume of the hot granite is better constrained,” Romagnoli said.

He said that they have collected data like borehole logs, shallow borehole temperature data, and heat-producing element concentrations in the country’s granite at shallow depths. They have also updated the geological map of Singapore.

The data is used in developing their inhouse geological model and near-surface temperature distribution map which helps them in identifying sites for deep exploratory drillings.

“Data from the deep boreholes will be used to verify and constrain our computer model, an essential tool to help us in resource estimation and further development plans,” Romagnoli said. “Our current upcoming activities are the boreholes deep drilling and temperature measurement,” he added.

NTU said in a statement that another study on geothermal supported by the National Research Foundation includes the testing of a quantum gravity sensor to look at the composition and structure of selected geographical sites in Singapore. This can help weigh the applicability of potential sites for geothermal power generation.

Low-carbon alternative

As part of its sustainability initiatives, Singapore’s energy sector is moving towards the “four switches” to achieve net-zero emissions by 2050, according to the Energy 2050 Committee Report

If found to have substantial geothermal potential, Singapore could consider tech options available to deploy geothermal energy locally

released by the EMA. Geothermal energy is amongst those considered.

The first switch to adopt is the use of natural gas for power generation, but gas turbine manufacturers can make more energy-efficient models of natural gas-fired power plants. Carbon capture utilisation and storage technology may also be used to remove the carbon footprint.

Solar power, the most viable renewable energy source in Singapore, is the second switch to the energy transition, whilst regional power grids and electricity imports are the third switches. Whilst longer-term low-carbon alternatives are still being developed, the third switch can help ensure energy security.

Low-carbon alternatives which include geothermal energy, are included in the fourth switch and are needed to decarbonise Singapore’s power sector in the longer term. The report said that hydrogen is a “promising candidate.”

Conventional hydrothermal systems are not applicable to Singapore due to its dry rock conditions, but next-generation geothermal systems that use fracking or closed-loop system methods are “potentially deployable in Singapore’s environment.” Nuclear power is still being developed and tested in other countries.

Sharad Somani, Head of Infrastructure at KPMG Asia Pacific, said it may be too early to tell which is the most viable option, but Singapore benefits “from its geographical position of being at the nexus of regional connectivity of logistics, pipelines, and power grid infrastructure.”

“It has the potential to be a regional energy hub at the centre of an integrated power grid. Separately, the potential of Singapore championing and trailing the use of green hydrogen to replace natural gas is another attractive option,” Somani said.

Aside from these, Somani added that some policy levers are needed, and one that Singapore has undertaken is the carbon tax. Coupled with carbon exchange for trading credits, this will also help companies to plan a decarbonisation map better.

“There is also a need to encourage companies to embrace decarbonisation alternatives and work with the government to focus on new technology solutions. Furthermore, Singapore can act as a test bed for technologies and promote pilot projects in energy storage, energy efficiency and distributed generation to evolve a holistic pathway to net-zero,” he said.

Challenges to geothermal potential

Romagnoli said that the extraction of geothermal energy is constrained by several factors such as how fast the heat energy from the hot rock can be extracted, how long the rock can remain hot enough, and how deep the hot rock resides.

“Highly fractured rocks tend to allow for faster heat extraction. However, if we extract the heat too quickly, the rock may cool faster than expected, thereby risking the lifespan of the resource,” he said.

Drilling and fracturing of rocks at great depth may be needed to access heat energy from deep hot dry rocks, but these processes remain “technically challenging” and “expensive,” he said.

New heat extraction systems, however, that do not require the fracturing of the rock make it more feasible for geothermal heat extraction in Lion City, he said.

Singapore’s limited exposure to geothermal energy development in the past several years also poses a challenge, but the recent move requesting information on geothermal energy exploration indicates an accelerated effort to tap into the energy source, Romagnoli said.

IRENA said that generally, there are challenges in developing a geothermal project when it comes to the assessment of the resource and how the reservoir will react once production starts. Amongst others, it said subsurface resource assessments and reservoir mapping are expensive to hold.

Test wells need to be done to allow developers to build models of the reservoir’s extent and flow and how it will react when water and steam are extracted for power generation. Despite much, much will remain unknown about the performance of the reservoir and how to manage it best during its operational life, before operational experience is gained, the agency said.

Aside from the increasing development costs, geothermal projects also have very different risk profiles compared to other renewable technologies in terms of development and operation. Their development also depends on the availability of comprehensive geothermal resource mapping, according to IRENA.

In developing unconventional geothermal resources, the use of enhanced geothermal or hot dry rock approach is less mature, adding that some projects cost significantly higher due to the deep drilling required, making the economics of such projects much less attractive, it said.

It said that research and development into “more innovative, low-cost drilling techniques and advanced reservoir stimulation methodologies are needed to help lower development costs to make them more “economically viable.”

Technologies

Shruti Raghuram, Junior Analyst at Rystad Energy, added development of the geothermal resource will rely heavily on subsurface conditions such as “permeability, porosity, availability of shallow reservoirs and reservoir temperatures.”

To address these concerns, Raghuram said Enhanced Geothermal Systems (EGS) and Advanced Geothermal Systems (AGS) could be the key to unlocking the energy source in Singapore.

He said that there are a few EGS and AGS start-ups globally that have drilled almost 50 wells, with around 37 wells in the pipeline in the coming years. They use innovations that target to mitigate the challenges in conventional systems to enable scalable resources globally.

Raghuram cited some techniques these start-ups employ such as EavorLoop which is a technology Eavor Technologies said is an ideal match for countries like Singapore. Other technologies include Deep Earth Energy Production’s horizontal drilling, CeraPhi’s CeraPhiWell, which aims to repurpose hydrocarbon wells to geothermal, and Sage Geosystem’s hybrid AGS-EGS technology.

“In a population-dense country like Singapore, geothermal has the potential to provide reliable baseload electricity if these technologies are leveraged appropriately. However, until more information on the subsurface conditions is revealed, the right mix of traditional and nontraditional geothermal systems cannot be determined,” he said.

“Geothermal as an energy source has been largely untapped in the past, but the significant traction it has gained in recent years could point to a larger adoption rate in the future – a step that is vital to achieve the 2050 net-zero emissions goals,” he added.

In a populationdense country like Singapore, geothermal has the potential to provide reliable baseload electricity

Alessandro Romagnoli

Sharad Somani

Disruptions in trade flows mean that coal is now a financially cheaper option than natural gas (Photo: Coal mines in Lakhanpur, Jharsuguda, courtesy of India Water Portal)

Asia turns back to coal amidst a global energy crisis

India and China are amongst the markets that have increased coal production to reduce reliance on imports for energy security.

In recent years, the power industry has seen markets switch to clean energy sources, leaving a trail of phase-out plans for coal-fired power plants across the globe. Now, the global energy crisis that saw disruptions in natural gas supply, leading to higher prices, is driving markets to re-trace their steps back to coal to secure energy supply.

Data from the National Bureau of Statistics showed China’s coal production rose by 11% to 2.19 billion tonnes in the first half of the year, whilst India’s coal production grew over 30% in June.

“Turning to coal is something that is necessary. We all know the impact it has on the environment, but if your natural gas price is four times more than what you can pay, then you don’t have a choice,” Ghee Peh, Energy Finance Analyst, Institute for Energy Economics and Financial Analysis (IEEFA), told Asian Power.

“These disruptions in trade flows mean that coal is now a financially cheaper option than natural gas. We are not saying one is better than the other. We are just saying one is cheaper than the other,” the IEEFA analyst said.

Decarbonisation goals of China and other Asian markets

China is one of the markets increasing its coal production to reduce reliance on imports. This will likely lead to a rise in carbon emissions in China to a level to remain within the government’s dual carbon target, as experts have clarified.

The projected increase in emissions will hardly affect China’s plan to achieve carbon neutrality and reach peak carbon emissions by 2030. This is because investments in new generation capacity will likely be earmarked for renewable energy technologies, particularly those needed in solar and wind power development.

“The important question to consider is not just about the capacity being built, but also how much of that is going to be used because building a coal plant doesn’t necessarily mean it’s going to be used all the time,” The Lantau Group Senior Manager David Fishman said.

Fishman cited the case of a province in northwest China where there is a surplus capacity of solar energy during the day, which is still insufficient to meet power demand during the night. Whilst a battery can be helpful, the province and other areas where renewables are being built will still need coal for when stored energy has been used up.

China will likely see more coal-fired power capacity as it backs up its renewables deployment, but as Fishman emphasised, China’s coal fleet will not likely lead to a high average capacity factor.

“You’re going to end up with more capacity, but the average capacity utilisation ratio for the whole fleet is going to be lower.”

In addition to this, Carlos Torres Diaz, Head of Power Research, Rystad Energy, said investments in new capacity in China will likely fund solar and wind technologies even as the market moves to increase its coal output at a faster pace.

IEEFA’s Peh backed this, saying IEEFA data from 185 financial institutions showed reluctance to invest in coal projects. Peh added that coal projects may be a bad business case due to other factors besides the challenges of having 185 institutions refusing to provide funding.

“You wouldn’t want to invest in new capacity because you will face community

Ghee Peh

Natural gas burns cleaner; the real issue is price

opposition, aside from facing no banking; and then if you put your cash into the [coal] mine and suddenly coal gets phased out, you lose $200m-$400m,” Peh said.

Rystad’s Diaz noted that increasing coal is a trend likewise seen in other countries that are looking to secure their energy supply. “European coal power generation has increased 11% this year. India has also aimed to increase domestic coal production and is currently studying the slower retirement of aging coal plants,” the Rystad expert said.

India has increased domestic coal output in the first quarter of the year. The country has also boosted imports of coal to meet its growing energy needs, according to GlobalData.

“There will be an increase in coal-based electricity generation in the region to overcome the current energy crisis,” Pavan Vyakaranam, Analyst at GlobalData, said.

He noted that of the total coal capacity under construction, nearly 95% is accounted for by Asia with China alone making up over 48%. Within Asia, China holds a share of over 51% of coal capacity under construction, followed by India which accounts for 20.6%.

Alternatives: Definitely not gas

Amidst challenges in coal, markets can look at other energy sources for alternatives, but Peh noted it is unlikely that natural gas could fill this role because of increasing prices.

“Natural gas is a lower CO2 option than coal–that is correct. It has less carbon dioxide emissions than coal. It burns supposedly cleaner, and we agree,” he said.

“But if your cost is three times more than coal for the average citizen at a time when wages are not going up and economies are not recovering faster, then the real issue is one of price.”

The IEEFA analyst added this there has to be some form of agreement on the price that will bring it closer to what consumers and governments can afford, which is US $10-$12 per mmBtu (One Million British Thermal Unit).

GlobalData’s Vyakaranam shared the view that renewable energy, such as solar and wind, supported by hydro or thermal gas could serve as alternative sources. He also saw nuclear power as an alternative to markets, such as South Korea, the Philippines, and Singapore, exploring adding nuclear energy in their power mix. Gas could also play a part, but not in the short-term, Vyakaranam said, citing the tighter gas supplies, high prices, and demand in Europe.

“For instance, Australia is rapidly deploying wind and solar projects and could have a dramatic shift from coalbased power to renewables,” he said. “Countries such as India and China also have aggressive targets for renewable power to achieve their long-term climate goals,” he said.

The Lantau Group’s Fishman, likewise, sees nuclear as an option for China as it serves as a baseload that runs all the time, which can be deployed and dispatched as needed, similar to coal. Nuclear power has a different level of flexibility with its runstate varying from 7,000 to 8,000 hours per year, compared to 4,000 to 5,000 hours per year in coal-fired power plants.

He added gas could be an alternative, but the high price and volatile international markets make it a less attractive option.

“Beyond that, the only other energy types that could fill a similar role to coal would be something like hydropower.”

Coal use to rise in a bid to secure energy supply in Asia

Coal remains the most practical means to stimulate affordable electricity generation growth

The use of coal-fired power is expected to continue growing and Asia will drive it as the region moves to secure its energy supply, Fitch Solutions reported.

“Asia will remain highly dependent on coal for power generation in the coming decade, given energy security concerns,” Fitch said in a report.

“Coal also still remains the most practical means to stimulate affordable electricity generation growth at the pace and scale needed to support continued economic growth in the region for many emerging markets.”

The report also linked this reliance on coal to the number of newer coal-fired power plants that started operating only within the last decade.

This comes amidst calls to reduce dependence on coalfired power during the COP26 in 2021, and countries, such as Indonesia and Vietnam, taking part with plans to end the construction of new plants.

Despite this, Fitch reported that the region will likely steer coal use expansion towards 2031 as a substantial number of coal-fired power plant projects in the region remains in the pipeline.

“We believe that the projects that are already undergoing construction or have reached financial closure will likely continue to progress, whilst those in the early stages will face significant risks of derailing,” the report read in part.

“This is in line with our long-held view that the current batch of coal projects will be among the last wave.”

According to Fitch’s Key Projects Database, more than 138 gigawatts (GW) of new coal power capacity are already under construction; whilst 238GW are in pre-construction stages in the region.

Additionally, major markets, such as China and India, which accounted for the largest share of coal projects in Asia, have not halted new projects within their jurisdiction. These markets, including Australia, have also opted out of announcing an end date for coal at the COP26.

“The agreement to reduce the role of coal-fired power was agreed with the language being softened from a ‘phase out’ of the sector to a ‘phase down’, leaving room for the sector to operate,” the report read.

“As such, in terms of absolute values, coal power will continue to grow over the coming years before it peaks toward the end of this decade and declines over the longer term,” the report concluded.

Currently there is no technology that can detect the resources inside the earth before drilling. It is possible that the proven geothermal reserve is not as we expected

Nisriyanto President and CEO, Supreme Energy

CEO INTERVIEW Supreme Energy takes a bold initiative to develop geothermal power plant in Indonesia

It carries out three projects on Sumatra Island, where 91% of its geothermal potential is unexplored.

Next to the US, Indonesia is the second country with the largest geothermal energy source in the world. Indonesia has a potential of 23,766 megawatts (MW) with an installed To increase output, Supreme Energy uses dual-flash technology innovation when operating geothermal power plants in Muara Laboh and Rantau Dedap. Nisriyanto said the use of dual-flash is considered Geothermal Power Plant capacity of 2,286 MW, the Handbook of Energy and Economic Statistics in 2021 from the Ministry of Energy and Mineral Resources shows. Of the national potential, the island of Sumatra holds the largest potential, amounting to 9,517 MW. However, the capacity of the geothermal power plant installed in Sumatra in 2021 is only 844,8 MW or 8,8% of its total potential. This means that there is still a staggering 91% of the geothermal energy potential that has not been explored.

PT Supreme Energy wants to further develop the geothermal sector in Sumatra. “We see that Java has been explored whilst Sumatra has not been developed much even though the resources are huge. In addition to the huge potential, the demand for electricity in Sumatra is also starting to grow,” said Supreme Energy’s President and CEO, Nisriyanto in an exclusive interview with Asian Power.

Three projects in Sumatra

Supreme Energy has three geothermal working areas in Sumatra, namely Muara Laboh in South Solok Regency, West Sumatra, then Rantau Dedap in Muara Enim Regency, South Sumatra, and Rajabasa in Mount Rajabasa, South Lampung.

The Supreme Energy project in Sumatra contributes to supplying electricity to the high-voltage power line (SUTT), dubbed Tol Listrik Sumatra Project, by state-owned electricity company PLN, with a capacity of 275 kilovolts that stretches from the southern side of Sumatra to the northern part.

Supreme Energy’s geothermal power plant in Muara Laboh mainly supplies electricity in the central part of West Sumatra such as Riau, Pekanbaru and Jambi, which so far have only relied on the 275-kilovolt network. “We see that the location of our power plant is very strategic in helping to maintain network reliability, especially in central Sumatra. With our electricity supply, we can contribute to meeting the electricity needs in central Sumatra,” said Nisriyanto.

The operation of the Muara Laboh geothermal power plant at the end of 2019 in West Sumatra marked the first time a geothermal power plant has operated in the province. According to the energy ministry in 2018, the power plants in West Sumatra, 50% comes from coal-fired plants, and 30% from hydropower plants.

The operation of Supreme Energy’s geothermal power plant also supports PLN’s new renewable energy mix target, which is targeted to reach 23% in 2025 and in 2021 so far reach 11.5%.

These three projects in Sumatra have signed a power purchase agreement (PPA) with PLN since 2012. The Muara Laboh project has been operating since end of 2019, the Rantau Dedap project only started operating at the end of 2021, whilst the Rajabasa project has obtained a permit from the government to start exploration in the working area but currently still negotiating with PT PLN on the PPA Extension.

“Currently, we are focusing on the implementation of these three projects, whose geothermal licenses and long-term power purchase agreements are already secured with PLN and we need to execute and develop them,” said Nisriyanto.

Each of the projects has a capacity of 220 MW. For now, Supreme Energy has operated the Muara Laboh Unit-1 Geothermal Power Plant of around 86 MW and is in the stage of developing another 80 MW Muara Laboh Geothermal Unit-2. Meanwhile, the Rantau Dedap Geothermal Power Plant has been operating with a capacity of around 91 MW. These two geothermal power plants are capable of supplying electricity to around hundreds of thousands of households. new in Indonesia and serves to maximise output by optimising lowpressure steam supply. “By using dual-flash, with the steam that drives the turbine, the energy will not be exhausted even at low pressure. So that under single pressure, the maximum has been 65-70 MW, but with dual flash, it can produce 80 MW,” he explained.

High risk of failure

Nisriyanto explained that the current operation of geothermal power plants of 86 MW and 91 MW by Supreme Energy from a capacity of 220 MW is due to the high risk when exploring geothermal. “Currently there is no technology that is able to detect the resources inside the earth before drilling. It is possible that the proven geothermal reserve is not as we expected. For example, of the six wells we drilled, only one well was successful. We have a very high risk related to the chance of success to develop geothermal,” he said. With the existing risks, where they do not only generate and operate a power plant to generate electricity but also have to find and prove a source of energy, geothermal developers are looking for reasonable returns that can be compensated with the existing risks. Nisriyanto stressed the importance of government support in facing the challenges of geothermal development. “Unlike oil and gas which can be exported to various parties, geothermal only produces electricity where PLN is the single buyer. As a single buyer, PLN is highly regulated by the government. Because the sale of electricity is determined by the government, as well as in determining subsidies,” he said. He hopes the government can provide the right policies in determining prices and subsidies by looking at the long term. “When compared to coal-fired power plants, the cost of developing geothermal power plants is indeed more expensive. For comparison, geothermal for 1 MW costs around US$4-5m, whilst 2 MW coal power costs US$2m because geothermal developers do not only build power plants but have to find the source of fuel first. However, it is possible that market conditions may change. As currently, the price of coal has shot up to US$400 metric ton from the previous US$60-80 per metric tonne, so the policies made should also be seen in the long term,” he said. Therefore, to anticipate major risks in geothermal power plant development, Supreme Energy focuses on working on projects that already have a PPA with PLN. “We are more focused on working on existing assets and increasing production in the three projects,” concluded Nisriyanto. Each of the projects has a capacity of 220 MW (Photo courtesy of Supreme Energy)