MASDAR, PLN NR CONQUER INDONESIA’S DEPTHS FOR SOLAR POWER
KOREA’S WIND ENERGY STALLED BY LACK OF ZONING RULES
WHY IMPORTED LNG IS NOT THE ‘BRIDGING FUEL’ IN CHINA’S ENERGY TRANSITION
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Taiwan presents a unique opportunity for offshore wind farm developers with its shallow water depths and optimal wind conditions. However, it faces approximately four fierce typhoons each year. To address this, the ChangfangXidao project employs typhoon-proof turbines for its offshore wind farms. Asian countries, particularly those in typhoon zones, can learn more about this innovative approach on page 12.
Indonesia is attempting to build a floating solar power plant in one of the deepest reservoirs in the world. The plant would have to be anchored to depths of 110 metres, a level which divers cannot go, so Masdar Indonesia and PT PLN Nusantara have had to develop new technologies to accomplish this feat. Once completed, it is to be the country's first floating solar plant, which also happens to be the largest in Southeast Asia. Read more on page 14.
Meanwhile, in South Korea, offshore wind farms are having problems connecting to the grid because of a lack of coordination between the government and developers. With the system currently running on a "free-for-all" approach, which uncertainties should key players expect? Know what experts have to say on page 18.
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The adoption of these emerging technologies is starting to influence asset valuations, prompting insurance companies to prepare for the associated risks. Get the latest insights on energy insurance on page 18.
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Easier grid access is now a reality for India's energy bulk consumers
As India boosts its adoption of renewables, the government has removed a bottleneck for consumers operating their own power plants or energy storage systems. New policies state that such consumers no longer have to secure a licence to establish, operate and maintain transmission lines to connect to the grid.
Summit Power's LNG plans offset gas decline for Bangladesh
Bangladesh struggles with deploying renewable sources due to scarcity of available land for development, and lack of strong irradiance and wind to generate electricity. As such, liquefied natural gas (LNG) will be key in driving the country’s energy transition and security as its accessible gas reserve dwindles.
PLN lights up Indonesia's most remote corners with universal electrification
Indonesia's state-owned electricity company, PT PLN, is committed to driving the nation towards full electrification with a particular focus on reaching remote and underserved communities. At present, PLN has connected an impressive 76,900 villages to the grid, marking progress toward universal electrification through the LISDES.
Despite Indonesia’s robust potential in the burgeoning carbon market, highlighted by a potential worth of $192m (IDR3,000t), industry leaders voice concerns over the lack of regulatory framework for foreign trade. This absence threatens to squander a significant opportunity in carbon credit demand.
Why Japanese utility firms are into the serious business of reselling LNG surplus
Japanese utility firms are facing an oversupply of liquefied natural gas (LNG) as demand for the resource declines with the country’s accelerating shift to nuclear and renewables for power generation. Due to the surplus, these utility firms are creating a business, reselling their LNG to other markets.
SIPG launches the first power plant simulator training programme
To address gaps in the skilled workforce and develop competencies, the Singapore Institute of Power and Gas launched the country's first centralized power plant simulator training program, aiming to standardize practices across the energy sector. It was introduced in collaboration with the Energy Market Authority (EMA) and power companies.
HOW TO ACHIEVE FINANCIAL GAINS IN COAL POWER PHASE-OUT
Investors may be surprised by the potential returns from shutting down over 800 coal power plants in emerging markets. According to the Institute for Energy Economics and Financial Analysis (IEEFA), investing in large-scale renewable energy projects and restructuring power purchase agreements (PPAs) can cover transition costs and yield significant profits.
Only 10% of existing global coal power capacity is for decommissioning by 2030, and experts say that this brings a significant opportunity to advance the closure dates.
Paul Jacobson, an IEEFA guest contributor and author of the report “Accelerating the Coal-toClean Transition,” emphasised the dual benefits of replacing aging coal power plants with largescale solar and storage systems.
“There is a solid business case for ageing coal power plants to be replaced with large-scale solar and storage systems, transforming the energy landscape and economic potential of emerging markets,” he said in the report.
Promising case studies
IEEFA’s analysis of case studies from Botswana, Colombia, Morocco, Romania and Thailand showed that “if the renewables are operational in the 2026 to 2028 timeframe, these five projects could completely end CO2 emissions by the end of 2028.”
This approach also works because significant gains from renewables PPAs are guaranteed for up to 30 years, it said.
Furthermore, these deals pay for all costs associated with the transition, including site decommissioning, recovery of equity losses of shutting down an operational asset, financing PPAs, construction and development of renewables, retraining workers, and upgrading grid infrastructure to support more clean energy.
Whilst this approach is profitable, IEEFA noted there is a problem with limited resources to identify similar opportunities and support local teams that can create bankable business cases.
“As many emerging markets lack the resources to develop coal-to-clean transactions, philanthropic funding can be transformative by bringing together global support and getting deals over the line,” the IEEFA expert wrote in the report.
“This is also an excellent opportunity for financial institutions to create their own deal flow of bankable coal-to-clean transactions.”
Renewable Capacity (GW) and Share of Renewables (%), Malaysia, 2023-2035
Source: GlobalData
Will Malaysia reach its 2035 RE target?
Whilst renewable energy (RE) capacity in Malaysia is seen to grow to 36.4% by 2035, this is still around 4% behind its 2035 target, according to a report by GlobalData, which also noted the country’s untapped potential when it comes to clean energy.
GlobalData’s “Malaysia Power Market Size, Trends, Regulations, Competitive Landscape and Forecast, 2024-2035” report said that green energy currently accounts for 13.3% of the country’s total capacity.
Renewable capacity in Malaysia is seen to continue to grow from 6.1 gigawatts (GW) in 2023 to 25.3 GW in 2035. Based on the latest growth trend, the country is expected to achieve 18.2% renewable capacity by 2025 and 36.4% by 2035, GlobalData said.
The Ministry of Energy and Natural Resources of Malaysia in 2021 announced a target of 31% renewable capacity by 2025 and 40% by 2035. Later in the National Energy Policy (2022 – 2040), the government announced an 18.4 GW renewable capacity target by 2040.
“Malaysia holds the potential to develop a renewable energy system in order to achieve energy security whilst addressing climate change concerns,” GlobalData said, noting that the country's most utilised renewable energy sources are solar photovoltaic, biopower, and small hydro.
Alternative energy sources
Aside from these three, GlobalData power analyst Sudeshna Sarmah urged Malaysia to tap opportunities in other renewable energy sources
to boost its capacity. The country previously launched the 30 MW Tawau geothermal project in 2015. However, the government later abandoned this.
Sarmah noted Malaysia also has a small wind energy capacity.
“Due to the unfavourable wind speeds during off seasons, the country has only one small onshore wind plant with a capacity of 0.2 MW. However, several small wind projects could still make a difference,” the expert said.
Government efforts
Sarmah also recognised that authorities have implemented efforts, such as introducing a large-scale solar programme with a total quota of 1,250 megawatts (MW) allocated for the 2017-2020 period.
Shantanu Srivastava, research lead for sustainable finance & climate risk at the Institute for Energy Economics and Financial Analysis (IEEFA), also said in its report that Malaysia is among the countries that allowed large commercial and industrial customers to buy directly from the power plants. This approach did not only expand the market for renewables, but also incentivised the development of clean energy plants for private industry.
In terms of finance, GlobalData noted Malaysia’s extension of the Green Investment Tax Allowance and Green Income Tax Exemption until 2023. To encourage participation in the net energy metering scheme, the income tax exemption for solar leasing companies was also extended until December 2026.
Furthermore, Malaysia has feed-in tariffs (for up to 1MW capacity) and Net Metering policies in place to encourage the adoption of renewables, Sarmah said.
Meanwhile, Srivastava said “the success of Malaysia’s Green Technology Financing Schemes (GTFS) – which provided loan subsidies for renewable projects – is instructive.”
From 2010 to 2017, there were 28 financial institutions that supported 319 schemes through GTFS, totalling $1.6b. Completed projects can generate 532.9 megawatt-hours of electricity annually.
The government has Feed-in Tariffs (FiT) for up to 1MW capacity and net metering policies in place to encourage the adoption of renewables
The Ministry of Finance in March 2019 approved the upgraded GTFS 2.0 that offers a 2% annual interest subsidy for the first seven years for project developers, with the government providing a 60% guarantee on project financing, Srivastava said.
“Governmental efforts such as strong policies and encouraging foreign investments towards setting up large scale renewable projects could push the country towards achieving its renewable energy goals,” Sarmah said.
Shantanu Srivastava
How vehicle-to-grid tech could stabilize the national power grid
Electric vehicles will not only be beneficial in transforming the transportation industry to shift to clean energy but also have the potential to contribute to the energy sector through vehicle-to-grid (V2G) technologies. However, policy support is needed as the technology is still nascent.
Sharad Somani, Partner & Head – Infrastructure Advisory at KPMG, said, V2G technologies are expected to contribute to balancing the supply and demand as it allows supply energy back into the grid during peak demand times.
“This balancing can help reduce the electricity supply by both coal and natural gas during peak hours by about 2.8% and 8.8%, respectively,” Somani told Asian Power
During emergencies, V2G “would have a high impact” as a power source, Somani said, adding that 6% of the global electricity production is estimated to be potentially
stored in EV batteries in the next 20 years. With the technology’s capability to store power, particularly the excess energy from renewable sources such as solar and wind during peak production times could raise the utilisation of renewable energy plants and reduce curtailment.
“V2G technology can contribute to energy transition by helping cleaner energy become effective and hence reducing reliance on fossil fuels,” he said.
Challenges
However, the V2G technology is still at the pilot stage, thus facing several challenges to large-scale deployment such as lack of charging infrastructure, and lack of awareness of consumers and building owners, as well as grid resilience and stability, said Oliver Redrup, Associate Partner, Strategy and Transactions –Infrastructure Advisory EY Corporate Advisors Pte. Ltd.
V2G technology can contribute to energy transition by helping cleaner energy become effective and hence reducing reliance on fossil fuels
Aside from these, Redrup noted that most Asian markets do not have the regulatory infrastructure that will support the deployment of V2G as the focus has been on the regulations and safety to allow EV charging and its deployment.
“Preparing the current power grid for V2G technology calls for collaboration between multiple public sector agencies including energy, transport, and finance as well as the private sector,” Redrup said.
“It will involve a combination of technical upgrades, regulatory adjustments, strategic planning, and investment from the private and public sectors to test and showcase the emerging technology and pilot it for large-scale deployment,” he added.
Market regulation
Redrup said that attention towards V2G has only gained attention recently, citing Singapore’s Energy Market Authority and the Singapore Institute of Technology awarding a grant to a consortium to develop and test-bed V2G.
STATE FIRMS DOMINATE SOUTHEAST ASIA’S PUMPED HYDRO DEVELOPMENT
State-owned utility firms are the top pumpedstorage hydro projects in Southeast Asia, with the top three developers in the region having significant government ownership as the facility's high cost makes them unattractive to private firms, according to Rystad Energy.
Current developments
Indonesia’s Perusahaan Listrik Negara is the top developer with 3.7 gigawatts of projects in the pipeline, followed by Vietnam Electricity, and Electricity Generating Authority of Thailand.
“The high upfront costs and the long time it takes to see a return on investment make pumped hydro projects less attractive to private companies,” the report from Rystad Energy read.
“Additionally, the licensing process can be unpredictable, dragging out project timelines and adding risk for potential developers,” it added.
This is different for the Philippines with private
firm San Miguel Corporate as its top pumped hydro developer. The fifth pumped hydro developer, Prime Infrastructure Holdings, is also a private firm in the Philippines. Rystad said the Philippines’ unbundled electricity market enables competition in both power generation and distribution, creating volatile wholesale electricity prices.
“This presents an economic incentive for pumped hydro storage, making it a more attractive option for developers in the Philippines,” it added.
Robust policies are driving the sector’s growth in the region in the short term, Rystad Energy said. For example in the Philippines, the Department of Energy aims to offer 3.1 GW of pumped hydro capacity as part of the upcoming Green Energy Auction Programme in the second half of 2024.
Vietnam also aims to reach 2.4 GW of pumped hydro by 2023 under the Power Development Plan 8, Rystad added. Indonesia, Thailand, and others in the region boost policy support for pumped hydro growth.
Deploying this technology will need grid investments to accommodate bi-directional power flow and metering schemes. As such, market regulators to to put in place “clear and consistent” policies for the technology to gain more traction,” Somani said.
“The current power grid is moving towards investments to accommodate EV charging requirements projected for the uptake of EVs,” he said.
“This is an opportune moment to consider V2G, formulate a long-term policy, and couple investments for EV charging loads with V2G capabilities,” the KPMG expert added.
Somani also noted that V2G was initially targeted as vehicle-to-home. In implementing V2G, the performance and design of battery chemistries need to be considered.
Most Asian markets do not have the policy support needed for V2G deployment
Indonesia's PT PLN is the top hydro project developer in Southeast Asia
Oliver Redrup
Sharad Somani
CHINA GRAPPLES WITH HYDROGEN SUPPLYDEMAND DISCREPANCY
Hydrogen is vital in China’s shift to lowcarbon energy. The country is even expected to exceed its 200,000 tonnes per annum (tpa) target for green hydrogen production by 2025. Still, there are challenges that Beijing should address for a smooth transition.
According to Rystad Energy, there is a supplydemand mismatch in China’s hydrogen sector. Demand is strong in the east but the renewable energy resources needed for production are abundant in the north.
Expanding pipelines
To address this, China works on expanding its pipelines, such as state-owned firm Sinopec that is developing a 400-kilometre (km) project connecting Ulanqab in Inner Mongolia to Yanshan in Baihing, with an initial capacity of 100,000 tpa, and expandable to up to 500,000 tpa.
Tangshan Haitai New Energy Technology in Hebei is also developing a $845m project from Zhangjiakou to the port of Caofeidian via Chengde and Tangshan, spanning 737 km. This is set to be the longest hydrogen pipeline once executed.
Sinopec subsidiary China Petroleum Pipeline Engineering Corporation eyes expanding this to 6,000 km by 2050. Provinces with stronger solar and wind potential are also ramping up their hydrogen production, with Inner Mongolia aiming for 480,000 tpa by 2025 and Gansu targeting 200,00 tpa, Rystad said.
“These provinces are heavyweights for transformation in the region, significantly affecting the 1 million target mentioned earlier and contributing enormously to China’s hydrogen production in the region,” the report read.
Limited capacity
Another issue cited was China’s renewable energy capacity to power electrolysers as the sector competes with other electrification needs.
Alkaline electrolysers operate within the range of 30% and 100% of their nameplate yield. Operating below this could lead to safety risks, Rystad warned.
If the power supply is insufficient, resulting in electrolysers running at less than 30% of their maximum capacity, these technologies will shut down. Otherwise, it could lead to gas mixing and potential explosion.
“Despite these challenges, Rystad Energy expects the share of green hydrogen to continue to grow in China, especially since it is installing new electrolyser capacity at a world-leading pace every year, a similar trajectory seen in the solar PV and wind industry, which China continues to lead,” the report read.
Why imported LNG is not the ‘bridging fuel’ in China’s energy transition
IPP
Whilst liquified natural gas (LNG) is touted as the “bridging fuel” for the energy transition, it will not serve such a purpose in China–the largest coal consumer in the world–as it remains expensive and policy favours local energy sources.
In a report, the Institute for Energy Economics and Financial Analysis (IEEFA) said that China is leveraging more on its domestic energy sources including coal, renewables and indigenous natural gas than imported LNG because of energy security concerns and incentives.
“Policymakers in both LNG exporting and importing countries should approach claims about the necessity of LNG as a ‘bridge fuel’ with a high degree of skepticism,” Sam Reynolds, the report’s co-author and LNG/Gas Research Lead for IEEFA Asia. “The case of China clearly shows that LNG has played a minimal role in displacing coal in the country’s largest coal-consuming sectors.”
Import costs
The average cost of imported LNG is nearly three times the cost of domestically produced coal and gas, it said, citing Chinese customs data. It is also 37% to 61% more costly than pipeline gas imports from Russia and
Voltalia began construction of its 126 MW Sarimay Solar Power Plant in Uzbekistan, scheduled to begin operation in the second half of 2025.
Voltalia said the project is part of a multi-energy complex in the Khorezm region with a 50 MW/100 MWh battery storage unit and a 100 MW wind farm under development. It will cut around 116,000 tonnes of carbon emissions annually.
The European Bank for Reconstruction and Development and the Japan International Cooperation Agency will lead the financing for this project.
The case of China clearly shows that LNG has played a minimal role in displacing coal in the country’s largest coalconsuming sectors
other Asian markets. The report added that coal generation is cheaper by $30 to $40 per megawatt-hour than natural gasfired power generation, whilst onshore wind and utility-scale are half the price of gas-fired power generation.
IEEFA noted that recent policies target to “strictly control” coal-to-gas switching, with coal positioned as the “cornerstone of electrical reliability” rather than gas.
Power mix
As such LNG imports are not slowing the growth of coal consumption, according to IEEFA, adding that coal demand has grown over LNG imports yearly since 2017.
In the power sector alone–which comprises 60% of the total coal usage, natural gas generation’s share has remained at just 3% since 2015.
The share of other RE sources like wind and solar has quadrupled to 16%.
Electric Power Development Co (J-Power) started the renovation works at the Ogamigo Hydroelectric Power Station in Japan’s Gifu Prefecture, with the plant expected to start operations in December 2024.
The repowering work includes comprehensive renovations of the main equipment such as water turbines and generators.
Once completed, Ogamigo Power Station's power output will increase by 1,300 kilowatts (kW) to reach, 21,300 kW.
The designs aim to streamline operations for reliability.
TagEnergy will start the construction of the second stage of the $2.7b (A$4b) Golden Plains Wind Farm with a capacity of 577 MW.
The power plant will be composed of 93 wind turbine generators, with the funding secured through non-recourse finance from a global group of lenders, including Australia’s green bank, the Clean Energy Finance Corporation.
The wind farm's 756 MW Stage 1 is also under construction, with 25% of turbines installed. Once both stages are completed, it will have a total capacity of 1,333.
Voltalia starts Uzbek solar plant
Sam Reynolds
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How well does APAC manage its solar PV waste?
Attaurrahman Ojindaram Saibasan Senior Power Analyst, GlobalData
The APAC region has trailed in providing any specific policies for solar waste management, although we can see several upcoming developments in countries like India and China. Japan already has some policies, and several companies are proactive in the space already. Solar panels’ life cycle generally is 25 years. As the market is huge, the requirement [for solar waste management] would be more.
Right now, there is more awareness towards this, and governments are trying to work towards it. For example, India’s Ministry of Environment, Forest and Climate Change recently amended the electronic waste management rules to include solar cells and modules. The Ministry of New and Renewable Energy (MNRE) has also identified solar PV recycling as one of the thrust areas in its new renewable energy Research Development.
The MNRE and the Council on Energy, Environment and Water, published a study estimating that India’s solar PV waste would be around 600 kilotonnes (kt) by 2030 and will be over 19,000 kt by 2050. They suggested the introduction of E-Waste Management Rules and building collection centres and storage facilities.
The storage facilities collection should be near the plants themselves so that there are no additional transportation costs, or they altogether give it to third parties who are specifically into solar PV (photovoltaic) recycling.
Similarly in China in August 2023, the ministry said that they were going to drop new industrial rules to decommission or dismantle the recycled solar PV plants to achieve a solar PV circular economy where the waste is recycled to newer solar PV panels. China’s capacity is huge and is estimated to have 1.5 million metric tonnes of waste by 2030 from solar premium modules.
Japan, in July 2022, mandated generators to give a reserve fund for solar PV plants, which would be returned to the companies at the end of the life cycle of their plants to afford the disposal of these facilities.
Recycling costs
The major key point [for solar waste management is] the varying levels of toxicity in the materials used in solar PV panels such as lead, cadmium, and tellurium and they are very toxic to the environment. The waste management is pretty poor in Asian countries, and if we are to add to that, it will contaminate more water and soil resources.
It is a huge concern because some of the solar plants are in very remote areas. The deterioration of the environment is a key aspect that governments and companies should look into. There are no specific or robust policies around it, which need to be implemented soon.
The most important factor is that it is not very economical. For example, the estimated cost for recycling is around $15 to $20, whereas if you just fill it through a landfill, that will cost you $1 to $2 only, and even if you try to recover materials from it, that would fetch you only $3 to $5 around that range.
That does not make the subject very exciting but with proper support from the government and incentives or like mandates, such things would make it essential to recycle. This could be in the form of tax rebates and incentives to recycle that will encourage them to do this.
They can draw examples from the European Union, wherein the companies include the cost of recycling at the end of their lifespan in the project cost.
There are companies that are active in solar waste management. Japan’s NPC, for example, developed solar recycling equipment which claims to recycle over 90% of the materials.
Sharad Somani Partner, Head of Infrastructure, Asia Pacific and Head of KPMG ESG, KPMG in Singapore
The management of waste from solar panels in the Asia Pacific region is still evolving. There are currently no solar recycling plants in Southeast Asia and no policies to handle waste from solar panels adequately.
As the adoption of solar technology has grown rapidly, so too has the volume of waste generated from end-of-life solar panels. In Singapore, for example, up to 5,000 tonnes of solar waste could be generated within the next two years.
Several countries are starting to implement strategies to handle this waste, focusing on recycling and proper disposal methods to manage environmental impacts and recover valuable materials.
Effectively managing solar panel waste is crucial to prevent environmental pollution and ensure the sustainability of the renewable energy sector. Hazardous metals, such as lead and cadium, in parts of some solar panels, can harm human health and the environment if not disposed of properly.
Notably, effective solar panel waste management presents significant new business opportunities. By 2030, the cumulative value of recoverable raw material from end-of-life panels is estimated to be around $450 million.
Tech and infrastructure challenges
The primary challenges in managing solar waste revolve around technology and infrastructure, policy and regulation, and economic viability. Most countries in the Asia Pacific region lack specialised facilities for solar recycling; and the regulatory framework remains largely underdeveloped. At the same time, costs associated with recycling can be high, around $20-$30 to recycle a panel whilst sending it to a landfill costs $1 to $2.
Actions governments and policymakers can take to tackle these challenges are geared towards the reuse and recycling of solar panels. Possible solutions include increasing legislation related to the treatment of solar waste; creating incentives to encourage innovation to make solar waste management more economically viable; and incentivising the refurbishment of solar panels.
Some countries have made significant progress in managing solar panel waste. In Singapore, Etavolt (technological spin-off from Nanyang Technological University) is the first initiative to support the country’s photovoltaic system. It works with firms to sustainably recycle used solar panels and determine which solar panels can be upgraded. This involves on-site regeneration of solar panels, a full-scale recycling plant and a mobile recycling plant for the recycling of solar waste.
Japan, by comparison, has issued voluntary guidelines on the proper disposal of end-of-life solar panels. This is an important ESG (environmental, social and governance) matter that will become mainstream in the coming years.
Many regulators and companies will require and commit to the circular economy principle for solar/green power technologies. Investor pressure and green compliance principles will mean proactive plans to manage and ensure solar waste management.
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PLANT WATCH: CHANGFANG-XIDAO
Changfang-Xidao uses typhoon-proof turbines to power 650,000 households
This means that the Class T turbines installed could withstand gusts of 65 metres per second.
WITH shallow water depths and the best wind conditions, Taiwan presents an opportunity for offshore wind farm development. But there is a caveat: the market is located in a typhoon-prone area. To overcome this, Copenhagen Infrastructure Partners deployed Class T wind turbines for its Changfang-Xidao offshore wind projects.
Changfang-Xidao, with a capacity of nearly 600 megawatts, is composed of 62 Vestas V174 turbines located 11 kilometres off the west coast of Taiwan.
“We have obtained a certification and then classification as class T,” Marina Hsu, Managing Director, CIP in Taiwan, told Asian Power. “T stands for ‘typhoon.’ That means [the turbine] could withstand the gusts of 65 metres per second.
“Taiwan is a typhoon zone, so we wanted to make sure that when it hits, our turbine with such a big structure could withhold and withstand the typhoon,” Hsu said.
According to Taiwan’s Central Weather Administration, Taiwan was hit by a total of 375 typhoons between 1911 and 2023, with an annual average hit frequency of three to four times. The country’s typhoon season is between July and September.
The Changfang-Xidao project, which could generate electricity enough to power 650,000 local households and is estimated to reduce carbon dioxide emissions by 1.1 million metric tonnes, costs over $3b (NT$97.6b) to develop.
The funding was secured through a non-recourse, syndicated loan from 27 different lenders across America, Europe, and Asia, with seven export credit agencies guaranteeing the project, Hsu said.
Conducive environment
Taiwan is located off the coast of southern China, with the Pacific Ocean on its east and the South China Sea on its southwest. This location creates a "funnel effect" for the wind to come in.
“Taiwan has some of the world’s best wind conditions,” Hsu said, adding that the seabed condition in the market is also conducive for offshore wind projects as it has gradual descent and a shallow depth of around 20 to 30 metres, specifically for the Changfang-Xidao project.
Aside from this, Taiwan also has a “very robust” government regime that supports the development of offshore wind projects. For example, Hsu said that the government offers feed-in tariffs (FiT) for such projects.
During the project's construction, FiT stood at $0.17 (NT$5.5) per kilowatt-hour.
“The FiT, in a way, incentivises our investment,” she said. “But right now,
Taiwan is a typhoon zone, so we wanted to make sure that when it hits, our turbine with such a big structure could withhold and withstand the typhoon
Taiwan has graduated from the FiT and entered into a corporate power purchase agreement routine for the new wind farms.”
Delivered on time
With the project reaching a financial close in February 2020, just a few months before the pandemic hit, Hsu said navigating the construction amidst a global lockdown was one of the greatest challenges they had to overcome.
“We are the first project in Taiwan that has not applied for an extension of time with the government. All the projects before us were delayed, and they asked for a government waiver to extend the delivery time,” Hsu said.
Constructing the project was especially challenging because all vessels carrying material for development, including technicians, were coming from abroad, mainly from Europe and the Philippines.
As the materials and the workforce needed were already sailing and flying towards Taiwan when restrictions were imposed, Hsu said they decided to redirect them to Japan, which was the closest country that did not have such limitations yet.
“They board the vessel so they become one in Japan, and then they sail to Taiwan. We had to use a very big crane to pick up all the components, so there was no human interaction. It is only the crane pulling in all the equipment onto the vessel, and they set sail to the project site and install,” Hsu said.
This strategy cost CIP over $2.5m (NT$81.4m) but it saved the company around a month of construction amidst the uncertainties, Hsu said.
She added that using a huge
installation vessel costs around $748,000 (EUR700,000) daily. If such a vessel came to the site and was unused, that would be a huge waste of money.
Hiring skilled technicians coming from the Netherlands, Hungary, Indonesia, and Vietnam, amongst others, was also vital as CIP’s suppliers were starting from scratch. Wind turbines weighing around 1,300 tonnes and standing around 85 metres tall would require hundreds of welders.
To bring these welders to Taiwan, the company, along with the suppliers, had to lobby the government to secure permission.
“This calls for some sort of soft skill — how recognised and established you are as a developer in Taiwan — so that the government will open some green lanes for you,” she said. “The financial strength, experience, and political capital helped us through.”
Localisation
Despite bringing in foreigners to help in developing the prince, Hsu said that they had the “highest localisation.”
They hired a team of around six to seven specialists to train local workers to help in training and teaching the suppliers in the welding process.
“Taiwan has no offshore wind industry. Therefore, you need to train the suppliers from the ground up, from zero, how to build factories, and then train all the staff and have them deliver to the European standard,” Hsu said.
Over 70% of the staff members are local. Hsu said that next year, they aim to reach 90% localisation and have a fully localised crew within three to four years.
The new turbines are tagged as "Class T" for typhoon-withstand
TAIWAN
Marina Hsu
PLANT WATCH: CIRATA FPV
Masdar, PLN NR conquer Cirata's depths for solar power
The power plant can provide electricity to around 50,000 households in West Java. INDONESIA
Developing Indonesia’s first-ever floating solar power plant, which happens to be the largest in Southeast Asia, is already challenging enough. But installing it on the deepest reservoir to ever have such technology poses another layer of obstacles. That is why Abu Dhabi-based renewable energy firm Masdar and PT PLN Nusantara Renewables have come in — to develop two different anchoring systems to compensate for the location’s depth.
Fatima Al Suwaidi, president director of Masdar Indonesia, said that they installed over 300,000 bifacial solar modules on top of the Cirata Reservoir in the West Java Region covering a 250-hectare plot.
Challenging installion
The Cirata Floating Solar Photovoltaic (FPV) has a capacity of 192 megawattspeak or 145 MW alternating current, capable of powering around 50,000 households whilst reducing over 214,000 carbon dioxide emissions annually.
However, the reservoir has a depth that could reach around 100 to 110 metres, and extreme slopes of as much as 40 degrees, requiring the companies to develop two anchoring systems to ensure the stability of the floating solar panels.
“Given that [the project was developed on] quite a deep reservoir, this has created not only a blueprint for Indonesia, but it has [also] set the benchmark for the floating PV industry worldwide,” Al Suwaidi told Asian Power. “We designed a fully integrated system that can tolerate such depth and the
We conducted the relevant field tests to make sure that both anchoring systems are not only suitable for that lakebed or that reservoir but also could withstand any sort of risk that might come about in the next 25 years
challenging soil nature in Cirata reservoir.”
For the power plant, they designed different anchoring systems for areas with lower slopes, and those that have higher slopes. These are needed to ensure the security of the floating solar panels, as the mechanism needed for the anchor to hold onto the soil of the lake bed would be slightly different on varying slopes.
“We conducted the relevant field tests to make sure that both anchoring systems are not only suitable for that lakebed or that reservoir but also could withstand any sort of risk that might come about in the next 25 years (during its full project life),” Al Suwaidi said.
Due to the reservoir’s depth, Al Suwaidi said they had to ensure the construction of Cirata FPV was done in the safest manner possible. As such, they crafted a system that will enable the installation of the mooring and anchoring without requiring human divers.
“This was a very important breakthrough for us because we needed to make sure that safety remains our priority and that we’re able to deliver this project to the government in an approved and acceptable timeline,” she said.
Policy side
Masdar and PT PLN Nusantara needed $145m to build Cirata FPV, with Standard Chartered Bank, Sumitomo Mitsui Banking Corporation, and Societe General acting as the lenders.
As this was Indonesia’s inaugural floating solar power project, Al Suwaidi said that
applying for permits and licenses was also challenging because they had to clearly define and explain the type of power plant they were working on.
The entire process was a “learning experience” for both companies, as well as the government of Indonesia who were open to exploring such development.
“We were able to support them in establishing a new government process on floating solar development. As part of that challenge and learning experience, the government was able to even release a floating solar guidebook which was inspired by the Cirata project,” she said.
Assessing the environmental safety and impact of the project was also challenging, being a first for the country.
Al Suwaidi said that understanding the environmental impact of the project is vital for them to identify how to mitigate such impact and see how they could potentially maximise the project.
Involving local community
During the project development, the two companies established a “fully integrated and interconnected system” that involved the local communities, Al Suwaidi said.
Masdar and PT PLN Nusantara provided over 1,400 jobs during the construction phase. They tapped the support of the nearby villages and the women in the community for the installation of some cabling onshore. The youth were also brought in to ensure the security of the location, whilst the fishermen provided support during the offshore installation. Al Suwaidi noted that they were all instrumental in navigating the reservoir.
Aside from this, they also provided capacity-building programmes to raise awareness about the project, with a lot of fishermen and farmers earning certificates in solar operation and maintenance that would allow them to work in any solar power plant in the country.
The companies also conducted workshops with domestic suppliers by inviting Tier 1 suppliers from China to teach them about upgrading facilities, addressing quality and performance matters, and obtaining certifications. They also held empowerment programmes for women, youth, and people with disabilities. “It was very important for us that beyond the development of the power plant itself, we look at the nearby villages,” Al Suwaidi said.
Expansion plans
Even before the launch of Cirata FPV in November 2023, Masdar and PLN NP had already signed a deal in September for the development of the project’s second phase by up to 500 MW.
This came following a regulatory move from Indonesia’s Ministry of Public Works and Housing that allows renewable energy to cover up to 20% of a water area, providing Cirata FPV the option to triple its capacity.
The Cirata Floating Solar Photovoltaic Plant has a capacity of 192MW-peak or 145MW alternating current (Photo from Masdar Indonesia)
Fatima Al Suwaidi
ANALYSIS: ENERGY INSURANCE
Insurance strains intensify for lower-tier energy clients amidst market shifts
Industry experts eye offshore investments as most attractive, yet more expensive.
The energy insurance market has remained relatively stable with global uncertainties and buyers exerting significant influence. However, a closer analysis reveals a growing disparity in attractiveness amongst insurance carriers, affecting the available terms for different types of clients, as cautioned by global insurance broker, WTW.
“The widening desirability gulf refers to the gap between the best and the rest of the energy companies. What we are seeing is that those clients who are proactive in the risk management of their business typically translate to a desirable insurance placement as they have a far more favourite risk engineering rating. In addition, those clients who actively engage with the insurers, through updated asset valuations and responsive to risk recommendations, are also favoured,” Charlotte Watts, Energy lead for Asia at WTW told Asian Power magazine.
“However, for clients who may be viewed by insurers as less attractive on account of lower premium volume or risk exposures, they will face a greater challenge for optimum capacity.”
Insurers have shifted their risk appetite towards highly desirable upper-tier business, whilst less desirable placements may encounter challenges in obtaining optimal capacity, according to WTW’s latest Energy Market Review.
The relatively low loss activity in 2023 has resulted in profitability across energy sectors, with insurers showing no signs of withdrawing from the market. However, the widening gap in attractiveness favours upper-tier clients, potentially leading to softer rate trajectories in 2024.
From an insurer’s perspective, Brendan Dunlea, regional head of Property & Engineering, QBE Asia pinpoints how financing is integral towards Asia’s energy transition.
“Most of the time, particularly in larger projects, the investors, and the financiers have to be very happy with the insurance coverage provided that it meets their needs in the event of a large loss. Ideally, there should be a very strong partnership between the insureds, the OEM — when I say the OEM it means the original equipment manufacturers — and the insurers because we have a lot of unknowns with new technology,” Dunlea told Asian Power in a separate interview.
Pressures
Competitive pressures further complicate the landscape, as oversubscribed placements
It is vital for insurers to support their client base with these new emerging technologies
trigger a race amongst insurers to offer compelling solutions.
“This, in turn, causes competitive tensions from insurers who are offering clients more compelling solutions in order to retain their business. In addition, we are seeing competition from other regional hubs outside of Asia Pacific (for example in London or the Middle East) which are looking to gain a larger market share in Asia Pacific,” Watts added.
Historically, frustrations amongst Asian energy companies stem from premium increases and stricter terms during hard market cycles.
“Looking ahead, we are starting to see insurers looking to partner with selected clients over multi-year longterm agreements in order to offer a more compelling and meaningful solution,” Watts predicted.
Covering emerging tech Emerging technologies like carbon capture and hydrogen also present both opportunities and risks.
“Given the continued focus by insurers on meeting their own ESG targets and a potential reduction in traditional energy premium pool, it is vital for insurers to support their client base with these new emerging technologies in the future, but also crucially now through this transition
phase,” Watts told Asian Power
On a regional level, Dunlea recounted the fire damage caused by battery energy storage systems (BESS).
“Particularly if we look back to 2017 to 2019, in Korea, where they were one of the ones at the forefront of developing batteries, there were a lot of fires. Most insurers avoided BESS at that point. Brokers were struggling for capacity and many owners had to self-insure to some degree,” he recalled.
“But now that they’ve developed the batteries a lot better, there’s a better understanding and better protective measures in place. Insurers are now more comfortable covering this type of technology.”
Financing remains a significant hurdle in the energy transition journey. Warranty terms and OEM reliability go hand-in-hand in building investor confidence and securing financing for long-term sustainability.
“And again, it also brings the partnership aspects into play. Hydrogen will be relatively slow-moving, but there are a number of projects out there that are more or less test facilities. Of course, these will be on a smaller scale. The lessons learned from these will help all parties: the OEMs, the insured and the insurers find solutions for the more inevitable, bigger projects. But that's the thing at the moment. Globally, we're not set up for the transfer of hydrogen,” Dunlea reminded.
Insurers are now more comfortable covering emerging tech, like battery energy storage systems, once better understanding and protective measures are in place
Brendan Dunlea
Charlotte Watts
COUNTRY REPORT: SOUTH KOREA
Korea's wind energy stalled by lack of zoning rules
Without designated zones for power projects, wind farm developers employ a 'freefor-all' method of identifying their own sites.
Offshore wind energy presents a significant opportunity for renewable energy growth in South Korea given its geographical constraints but the country’s developer-led approach to deploying such projects presents uncertainties in the development.
Unlike in the US and other European markets where the licensing authorities pre-designate an area for wind development, South Korea requires developers to find their development sites, Grant Hauber, Strategic Energy Finance Advisor, at the Institute for Energy Economic and Financial Analysis said.
“[In other markets], what that does is enable preliminary studies to be done. It avoids being in sensitive areas, like where fishing or marine habitats, things that they do not want to disturb,” Hauber said.
“In Korea, it is much more of a free-forall, where developers have to go out and delineate a site [and] preliminarily study and then use that as an occasion for the business license,” he added.
Arbitrary processes
Jinyoung Baek, Managing Director & Partner, at Boston Consulting Group said companies need to measure the quality of wind on the coastline themselves. Once they have identified a location, they will have to proceed with the permitting processes and resolve issues with stakeholders.
The random identification of sites also makes transmission planning to get the cable to the shore “super uncertain,” the IEEFA expert said.
Hauber said cables do not necessarily follow a straight-line route in the sea bed as developers would also need to take into
It is much more of a free-for all, where developers have to go out and delineate a site [and] preliminarily study and then use that as an occasion for the business license
account the things they have to avoid. At times, around two to three substations will be needed for interconnections.
This presents another challenge for the Korea Electric Power Corporation which will be responsible for transmission interconnection.
Creating mistrust
This set-up leads to a lot of controversy and mistrust amongst fishing communities and environmental groups that protect marine habitats, adding more risks and uncertainty to offshore wind projects.
“Not having the actual site sort of predetermined and sanctioned by the government does not create a level playing field,” Hauber said.
Janice Cheong, Policy & Project Manager, at the Global Wind Energy Council (GWEC), it is difficult to garner local consensus because there is no requirement under the developerled approach to engage with the local stakeholders early on.
Due to this, there is a need to incentivise the participation of local communities and focus on capacity building.
“From the local government side, a local regeneration vision can be in place early on that can build long-lasting social acceptance and support for development,” she said.
Cheong added that capacity building and education to establish a workforce at a local level will help to “bridge potential gaps in understanding of offshore wind development.”
Offshore wind landscape
According to the GWEC, South Korea only has 150 megawatts (MW) of offshore
wind projects running, far from its target of reaching 14.3 gigawatts (GW) by 2030. But overall, the country has a total of 624 GW of technical potential for offshore wind.
Reaching such targets could be beneficial, particularly for coastal cities economies, as the project could bring an investment of around $62.6b (KRW87t).
Aside from this, the projects could provide over 770,000 job opportunities across value chains including positions such as marine engineers, factory workers, business, managers, and health and safety specialists, amongst others.
GWEC noted that developing a 500 MW offshore wind farm would already require 2.1 million direct person-days, on top of the various direct or induced jobs.
However, the current landscape is “extremely complex” due to the lengthy permitting processes, requiring developers to secure 22 different permits from 10 various government agencies. This then prolongs the permitting process, taking an average of seven to 10 years.
Incentives are in place to boost the development of offshore wind projects in the country. One of which is the weighting scheme for renewable energy certificates (REC), with weightings for offshore wind reaching up to 3.7, Baek said.
“It's a quite significant economic incentive. Based on this high REC weight, the operators expect to achieve a favourable project internal rate of return estimated between 8% and 10%,” he said.
Cheong also said that the sector is seeing strong momentum because of its large pipeline of projects, of which 28 GW have received electricity business licenses. The country has also conducted an annual auction for the 20-year fixed-price contract for wind for two years.
Policies needed
The government could also provide support by investing in the preparatory process ahead of bidding by leading the subsea surveys and laying out plots for project development, providing developers with information as to the type of technology they could use.
“If you make that freely available to bidders, that allows them to sharpen their pencil and come up with realistic proposals that are closer to what they would be able to implement,” Hauber said.
“Unless they have access to detailed subsea survey data, and, you know, preliminary environmental assessments, which most do not, it is guesswork,” he added.
Aside from this, government stakeholders should also push for the One Stop Shop Bills, as well as lobby for the passage of “The Special Act for Promotion of Offshore Wind Power Development,” GWEC’s Cheong said.
The proposed legislation, which was not passed in the 21st National Assembly and needs to be re-tabled in the 22nd Assembly, will ease the seabed siting process and provide clear guidance for offshore wind projects.
The Sinchang Windmill Coastal Road on Jeju Island, South Korea
Jinyoung Baek
Grant Hauber
Accelerating Indonesia's Development
PT Sarana Multi Infrastruktur (Persero) is a Special Mission Vehicle (SMV) of the Ministry of Finance with a role and mandate to act as a catalyst
CEO INTERVIEW
How NEFIN's delayed projects impacted shortterm goals but yielded future gains
CEO Glenn Lim explains how a delay turned out good as the company aims to reach 667 MW of capacity by 2026.
For NEFIN Group, the next few years will be focused on getting back on track and developing its projects that were due in 2023. A total capacity of 65 megawatts had been stalled because of the surge in prices of solar components.
“We have to intentionally postpone the project so that it arrives at a date where it is more economically feasible to implement,” NEFIN Group CEO Glenn Lim told Asian Power.
The International Energy Agency (IEA) said that the price of steel, copper, aluminium, and polysilicon rose in 2020 due to supply chain challenges, with the average monthly price of polysilicon reaching its peak in 2022 — about four times higher than in 2020.
In China, the price of steel which is a main construction material for utility-scale photovoltaic and onshore wind plants rose by 75%.
But in 2023, the capital costs for utility PV in Asia Pacific declined by 29%, resulting in an average of 23% fall in levelised cost of electricity. Distributed solar saw a 26% decline in cost; the technology is now 12% cheaper than residential power prices, according to Wood Mackenzie.
The decline makes utility solar the cheapest power source in the region, surpassing conventional coal, it added. So, the delay is not only logical, but a smart move on the part of NEFIN Group.
“The highest priority is to get our capacity online, especially those that we had delayed due to unforeseen market forces over the last few years, as soon as possible,” Lim said. “We want to catch up. By 2026, we want to get to 667 megawatts. So the next two years of catch-up will be actually very steep.”
How did the company fare in 2023 and what were the key challenges it faced?
We did pretty well. We increased our revenue by 40%. We managed to secure substantial capacity across Asia. The projects, which we expect to start construction this year, will be over 100 megawatts.
In early 2023, we experienced a steep increase in some of the components of solar projects due to the increase in interest rates globally and inflation which made some of our projects not economical. As such, we have to intentionally postpone the project so that it arrives at a date where it is more economically feasible to implement.
Surprisingly, the market was super volatile. Towards the second half of the year, the sudden surge in prices at the beginning nosedived which made our projects financially workable. Now, we have to double our capacity. This means that what was supposed to be done in a year is now postponed to the second half of the year, and you have to compress it. However, we only have this amount of headcount that we can handle so our people are running twice or thrice their capacity. That’s the problem that we are facing. We don’t want to rush. So some of our projects missed our last year’s target to be operation-ready, and it spilled over to Q1 this year. This year, the current pipeline looks very strong and good.
How many projects or megawatts were pushed to Q1 2024?
This number is pretty substantial: around 65 megawatts. This delay is not necessarily a bad thing. To be objective, yes, there was a delay; but due to the sudden huge decrease in the component price, the project became very good. The delay was maybe God’s blessing that luckily, we didn’t start earlier.
The Malaysian government awarded NEFIN with a 45 MWp solar farm project. Can you tell us more about this?
This project has come a long way. We started working with Intel back in December 2016. Along the way, we were hoping that the government enable the virtual PPA where companies like Intel can
The highest priority is to get our capacity online, especially those that we had delayed due to unforeseen market forces over the last few years, as soon as possible
procure green power, not just through their rooftop, but from a virtual way. And thanks to the new leadership of Malaysia, which enables this policy, and makes it possible for a lot of corporates to achieve their carbon-neutral goals.
What other opportunities or markets could NEFIN Group potentially enter or tap into?
Number one is ASEAN (Association of Southeast Asian Nations) for sure, due to the nomadism of the factories in ASEAN. Indonesia, Vietnam, Philippines, Malaysia, and Thailand, all these are markets for manufacturers to come up. These are good locations for the factories to be. But we also see some unique markets such as the Philippines which has a great demand for power over the next six years from now to 2030, so that is an emerging market for us. We also see that Taiwan, being a super island, also wants to reduce its reliance on liquefied petroleum gas (LPG). LPG prices over the last 12 to 18 months were rocket-high due to the RussiaUkraine war. It’s not sustainable to have a single source of that energy to keep the economy. There’s always a need to enable other renewable or alternative energy such that possibly nuclear, wind power, solar and hydropower
Is NEFIN also exploring other renewable sectors?
In China, we invested in battery storage, we do peak demand shaving, load shifting, and demand response. We are exploring some green but at this moment, we don’t think any of this project will come online until 2026. There’s always a need to enable other renewable or alternative energy alternatives.
Glenn Lim, NEFIN Group CEO
MALAYSIA
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Strategic partnership boosts ACE APAC’s New Zealand solar ventures
The company is working with local developer Far North Solar Farm for four solar projects.
In entering a new market, Aquila Clean Energy Asia Pacific (ACE APAC) partners with a local industry player as this makes the process more efficient. For its expansion in New Zealand, it partnered with Far North Solar Farm in 2021 to develop and construct a portfolio of solar power plants in the market.
ACE APAC and Far North Solar Farm have since secured portfolio debt financing from Westpac New Zealand for their four solar projects with a total capacity of 180 megawatts-peak (MWp). The first project, the 20.8 MWp Pukenui Solar Farm, is expected to start operations next year.
“When you enter a new market, the easiest way to do that is to partner with locals who know what they are doing. That has been our strategy in New Zealand and we were fortunate enough to find Far North Solar Farm,” Dennis Freedman, managing director for Australia & New Zealand at ACE APAC, told Asian Power
Despite the dominance of renewable energy (RE) in New Zealand, which accounts for 80% of its energy mix, Freedman sees the country as a strategic market for growth as it provides a conducive environment for deploying more projects.
Asian Power delved deeper into the energy investment partnership’s strategic plans in this exclusive Q&A.
Can you provide the funding details and explain how it will help boost your assets?
The funding package between Aquila and Westpac was a first of its kind in New Zealand. It was the first time that a foreign entity in New Zealand was able to secure portfolio funding on a fully-merchant basis for a portfolio of solar projects.
The funding package covers four eligible projects with 180 megawatts total combined installed capacity when they're finally built. The first project is currently under construction, the Pukenui Solar Farm, which is in the far north part of New Zealand, with just over 20 megawatts.
What made you decide on a partnership with renewables developer Far North Solar Farm?
ACE APAC is headquartered in Singapore and we operate in five different markets including New Zealand, Australia, Japan, South Korea and Taiwan. When you enter a new market, the easiest way to do that is to partner with locals who know what they are doing. That has been our strategy in New Zealand and we were fortunate enough to find Far North Solar Farm. They have established quite a strong presence locally in New Zealand with people on the ground and have put together a portfolio of projects where they obtained the land.
The energy transition is challenging enough. We encourage our team to find good partners to work with. This is also the approach that we have used in Australia where we have different partners in different parts of the country helping us originate projects.
The counterpoint is if we had not partnered with a local industry player, we would need to find a team of local developers and start knocking on the doors of landowners. That all takes time.
What opportunities does New Zealand present in terms of renewable energy development for the company?
We are focusing on Organisation for Economic Cooperation and Development (OECD) countries in APAC, of which New Zealand is one. If you look at the market fundamentals in New Zealand, it is nearly 80% renewable already. Compared to other markets, people might say that that is quite high.
So why in New Zealand? The government has a target of being fully renewable, so there is still around 20% of the total generation required to become renewables to replace existing coal and gas. We believe New Zealand still needs to install around 4,000 megawatts
If we had not partnered with a local industry player, we would need to find a team of local developers and start knocking on the doors of landowners. That all takes time.
(MW) to 5,000 MW of renewables to hit that target, assuming that there is no demand growth. However, we are seeing strong demand growth in most markets due to electrification, with people moving off gas-fired energy sources and taking up electric vehicles. If you think longer term, there are hydrogen strategies that may require more electricity too.
Through that lens, combined with the fact it is quite a stable regulatory environment, it is a market that we are comfortable working in. Our partnership with Far North allows us to move quickly and to establish a beachhead in terms of projects and people on the ground, which puts us in good stead to be a serious player in the New Zealand market.
Despite RE dominating New Zealand’s energy mix, what challenges are there in deploying clean energy projects?
I’m positive about the New Zealand landscape, insofar as government policy is quite stable and aligned. The understanding socially around the need to move to further renewables is quite strong in New Zealand. Essentially, there's an acceptance of the types of projects that we're building.
But at a more micro level, you do have challenges. When you are building a solar project or wind project in a new community that has not had that before, those changes can change the landscape. Sometimes, that can change the fabric of how the community operates, insofar as the landowner now has something that their neighbour may not. There are some dynamic changes there. Social licence, what we call, social acceptance, and being a good community citizen are very important. That takes time. That is different in every single project and every community that we operate, so that is probably the hardest thing.
The second challenge is around the grid. Again, this is not a New Zealand issue. This is a global issue. None of the electricity grids were developed, built, and planned with renewables in mind, per se, with diversified locations. So, finding areas on the grid that have the capacity for us to connect so that we can actually get our electricity into the system whilst respecting the laws of physics.
Dennis Freedman, Managing Director for Australia & New Zealand at ACE APAC
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XIA RI
Commercial production of white hydrogen unlikely in the short term
Ri Researcher ANBOUND
Hydrogen is touted as the “ultimate energy source of the 21st century.” Significant in promoting sustainable global economic development, it gradually becomes one of the important drivers for global energy transition.
However, the vast majority of hydrogen produced globally is mainly derived from fossil energy, a process that emits a large amount of carbon dioxide. This type of hydrogen is also known as “grey hydrogen.” In this production process, when carbon dioxide is captured, utilized, and stored, it is termed “blue hydrogen,” but it is subject to strict constraints on storage conditions. On the other hand, “green hydrogen” produced by electrolysing water using renewable energy is still very limited due to its high cost, hence it only accounts for less than 4% of total hydrogen production.
In comparison, white hydrogen is naturally generated or exists in the Earth’s crust, being a potential and minimally developed clean energy source. It is also referred to as “natural hydrogen,” “golden hydrogen,” and “geological hydrogen.” It possesses at least two major advantages: first, it does not emit carbon dioxide, and second, it does not require water electrolysis for production.
Yet, even as a potential and minimally developed clean energy source, due to factors such as uncertain reserves, early-stage technology, and high extraction costs, its mass commercial production is unlikely in the short term. From a practical perspective, with the exploration efforts of multiple countries worldwide, more and more reserves of white hydrogen are being discovered. Among them, significant natural hydrogen reservoirs have been found in Mali’s Bourakebougou, Australia’s Yorke Peninsula, Spain’s Monzón, the foothills of the Pyrenees in Spain, and the Lorraine basin in France, estimated at 5 million tons, 1.3 million tons, 5 million to 10 million tons, 1 million tons, and 6 million to 250 million tons of hydrogen respectively. However, whether in overall estimates or individual assessments, white hydrogen reserves are indirectly inferred through investigations of oil and gas or specific geological processes and environments, making it difficult to obtain accurate measurement data, and the actual resource quantity has yet to be confirmed.
Mali is currently the only country in the world actively extracting white hydrogen and benefits from unique geographic conditions. Most other
countries are in the early stages of understanding white hydrogen. Some are in the initial phase of white hydrogen exploration, while others, including both nations and enterprises, are just beginning to experiment with white hydrogen extraction. These entities will encounter various challenges and require continuous exploration of innovative technological solutions in areas such as hydrogen exploration, detection and analysis, and leakage management. It is worth noting that white hydrogen accumulations are likely to be very small, offshore, too deep, or in remote areas, which would impose high demands on extraction technology.
The relative cost of extracting white hydrogen remains rather high and that is difficult to change in the short term. In theory, as white hydrogen is a natural renewable energy source, it should be possible to extract it endlessly at a low cost. However, this is not the case in practice. According to estimates, the production cost of white hydrogen is approximately $1 per kilogram, while the production cost of green hydrogen is about $6 per kilogram. HyTerra, a company conducting natural hydrogen exploration in the United States, believes that production at a cost of $1 per kilogram is necessary to compete with natural gas. However, situations similar to Mali’s are not common. The deeper the drilling, the higher the purity of white hydrogen. If extensive deposits require deeper drilling, the development cost of white hydrogen may increase rapidly.
Spanish company Helios Aragón states that it can produce natural gas from the vast underground layers at the foot of the Pyrenees Mountains at a cost of EUR 0.75 (approximately $0.82) per kilogram. However, achieving a significant reduction in costs would require waiting for several decades, and it is difficult to say whether the cost would be lower than grey or green hydrogen. Helios estimates on its website that by 2060, the cost of producing white hydrogen will be as low as $0.50-$1.25 per kilogram, while grey hydrogen will cost $0.75-$1.6 per kilogram (currently $2-$4 per kilogram), and green hydrogen will cost $0.75$3.25 per kilogram (currently $5-$8 per kilogram).
All in all, the global understanding of white hydrogen is still in its early stages, with many unresolved issues in exploration, technology, and application. Therefore, commercial production of white hydrogen is unlikely to be achieved in the short term, and it is even less likely to significantly change the current situation of hydrogen energy and even the new energy supply.
Xia
Australia now offers exploration licenses for hydrogen
