Emerging Asia powering ahead with decarbonisation agenda
Ho Chi Minh City
Foreign Legal Consultant (partner level), Ginting & Reksodiputro in association with Allen & Overy
Headlines in this article
Asia is at the forefront of the global challenge to balance economic development, climate adaptation and mitigation, and energy security. The region is diverse, dynamic and pragmatic, facing both the risks and opportunities of the energy transition. From coal to renewables, from batteries to hydrogen, from offshore wind to nuclear, Asia is exploring deploying a range of technologies and solutions to meet its growing energy needs and reduce its emissions.
This report touches on some of the bright spots and shows how emerging Asia is playing a critical role in decarbonisation of not only their, but also developed Asia’s energy transition.
We cover some of the biggest developments in the region at present. These include:
- Our insights into the latest evolution of carbon markets in Asia
- The importance of hydrogen and ammonia in the transition agenda in the region
- Exploring Japan’s approach to accelerating their adoption with subsidies
- Addressing specific transport issues of both electric vehicle battery and sustainable aviation fuel production in Asia
- The opportunities and challenges for countries adopting offshore wind power as part of their energy mix
Carbon pricing has been a heavily politicised issue across emerging markets in Asia. This is unsurprising, given the tension that stems from the region being particularly susceptible to the impacts of a warming climate, while also being home to many young carbon-intensive assets and heavy emitting industries. Scott Neilson and Goran Galic explore the approach being taken by emerging Asian jurisdictions to the development of carbon markets.
Currently, carbon pricing regulation is inconsistent and fragmented across the region. It includes both carbon taxes and emissions trading schemes (ETS), although the latter is more common in Asia. In addition to domestically mandated trading and crediting mechanisms across several Asian jurisdictions, we observe a notable uptick in demand for credits being generated from voluntary carbon markets in the region.
In September 2023, Indonesia launched the country's first carbon emissions credit trading system. Trading will be voluntary in its initial stage, and the system will aim to adopt international standards to make the credits available to foreign buyers. The government also plans to launch its twice delayed carbon tax in 2025.
China has had a national market for emissions since February 2021. It is the world’s largest carbon market by emissions, however currently the carbon price is too low to be effective, and only covered entities are allowed to make trades.
Malaysia and Thailand are both considering the implementation of a carbon tax and ETSs. Malaysia recently launched a domestic emissions trading market, beginning with voluntary offset trade before rolling out an ETS at a later date. Thailand is considering establishing a national ETS, having already launched a voluntary scheme in 2015.
India is seeking to establish a domestic carbon market, which is to be implemented in three phases: increasing demand for voluntary carbon credits; enhancing supply of voluntary carbon credits; and introducing a mandatory system for certain sectors, modelled on the EU’s cap-and-trade system. The push for a national carbon market has sparked debate about whether the export of carbon credits to international markets should be banned until India’s climate goals are met. Similar arguments were raised in Indonesia, however the government ultimately decided that its carbon market would be open to foreign buyers.
Japan is currently in the early stages of developing a national ETS, which is slated for 2026. From 2033, auctioning is set to be introduced for large emitters in the power sector. In the meantime, a voluntary ETS (called the GX-ETS) is being run as a testing ground.
Similarly, Vietnam anticipates launching a pilot voluntary ETS in 2026, before launching a full ETS in 2028. There are also suggestions that a carbon tax could be developed under the revised Law on Environmental Protection, which took effect on 1 January 2022 and allowed the establishment of a carbon market.
In the Philippines, a bill was introduced in 2023 in relation to a Low Carbon Economy Act. It aims to establish a domestic cap-and-trade system, however no timeline has been specified.
Overall, many economies in emerging Asia are actively developing and implementing carbon pricing mechanisms to help them meet national mitigation targets. Momentum is growing across countries to make national policies more effective, consistent and harmonised in light of international commitments.
The greatest demand for credits in the region is being generated from voluntary carbon markets, consisting of mostly private entities purchasing carbon credits (under voluntary crediting mechanisms, such as Verra) for the purpose of complying with voluntary mitigation commitments. In terms of value in these markets, turnover hit an all-time high annual value of USD2 billion in November 2021, four times its value in 2020. After two years of rapid growth, carbon credit markets slowed in 2022 owing to challenging macroeconomic conditions and debates around mandatory carbon markets. Unclear plans to implement an ETS in a country in the future may dampen the voluntary market.
The current value of these voluntary carbon markets is a small fraction of the global carbon pricing revenue generated by compliance-based regimes. Notwithstanding this, we expect that in the long term, growth in the voluntary markets linked to emerging economies will continue as the approach to carbon pricing and trading continues to develop and mature.
Much of the focus on hydrogen and ammonia (and other related energy vectors, such as MCH) in Asia has been on Japan and South Korea (and, to a lesser extent, Singapore) as importers and Australia’s aspirations to be their leading supplier. But hydrogen development is gaining momentum across other emerging markets in Asia due to its potential to help achieve decarbonisation goals in a variety of domestic use-cases, particularly in relation to transport. Matthias Voss, Xue Wang, Goran Galic, Hitomi Komachi and Jackson Allen share insights on the potential for significant developments across a range of emerging Asian jurisdictions.
China is the world’s largest producer and consumer of hydrogen, but less than 0.1% of its production is green hydrogen. But the government has committed to change this, with the introduction of the Hydrogen Industry Medium and Long-Term Development Plan (2021–2035) which aims to produce 100,000 to 200,000 tonnes of green hydrogen a year and have 50,000 hydrogen-fuelled vehicles by 2025. By 2050, it is expected that about 70% of China’s hydrogen will be green. To that end, several projects are currently being developed by major Chinese SOEs such as Sinopec, which has recently started production at the 260MW Kuqa project in Xinjiang, which is currently the world’s largest operating green hydrogen project (though a number of larger projects in China will soon surpass it). China is quickly becoming a world leader, going from 10% of the world’s installed capacity of electrolysers in 2020 to 50% by the end of 2023.
India has a formal hydrogen strategy – the National Green Hydrogen Mission, which was published in 2023 and aims to continue the success that India has had in relation to installing renewable energy capacity. India’s goal is to develop green hydrogen production capacity of at least 5 million metric tonnes per year and add renewable energy capacity of about 125 gigawatts by 2030. In the past two years, multiple green hydrogen pilot projects have been commissioned. The government has also announced its intention to extend incentives to green hydrogen producers for 10% of their costs.
Malaysia is set to launch its Hydrogen Economy and Technology Roadmap, aiming to become a green hydrogen export hub by 2027. Malaysia has already begun hydrogen production for domestic purposes – in 2019, Malaysia built Southeast Asia’s first integrated hydrogen production plant, refuelling station, and hydrogen fuel cell-powered buses. Investors are looking at green hydrogen export projects using Malaysia’s ample hydropower supply, as for example in the Sarawak region. Malaysia also looks set to become one of the biggest hubs for CCS projects in Asia, with multiple international treaties signed, paving the way for blue hydrogen projects. So far, public tender is not required or contemplated for export projects. It is expected that local investors will take at least minority ownership in the projects. It is expected that the Gas Sales Act will be revised to address handling and safety regulations on hydrogen.
In the Philippines and Thailand, green hydrogen and fuel cell technology are still in the pre-commercial phase, however both countries have recently signed memorandums of understanding with international companies to advance hydrogen projects and research. Thailand also plans to replace 20% of gas and LNG with hydrogen (blue and green) between 2023 and 2027, as part of a proposed new national power development plan (which is currently awaiting approval).
Planning and construction of hydrogen production facilities has commenced across Indonesia and Vietnam. Construction started this year on Vietnam’s first green hydrogen plant (24,000 tonnes of green hydrogen a year), while Pertamina recently announced plans for a pilot project in Indonesia to produce 100kg of green hydrogen a day. While small-scale, this pilot project is significant for Indonesia, as the hydrogen production is linked to geothermal energy and Indonesia has unmatched potential in relation to geothermal resources. Indonesia is second only to the USA in current geothermal power production and is set to surpass it as early as 2025.
Unsurprisingly, given the very different contexts, key industries and available resources of the different countries, emerging Asian markets have taken very different approaches to the development of hydrogen and ammonia markets. However, there are some common threads emerging, and we may see regional approaches and markets start to appear as this decade progresses. For example, the use of ammonia in coal-fired power stations to reduce carbon emissions is a strategy which is being strongly pursued in Japan but is starting to spread regionally as Japanese companies (which are heavily invested in Asian power generation outside of Japan) have started research and feasibility studies for co-firing of ammonia and coal in Malaysia, Indonesia, the Philippines and Thailand. This example also helps to show that the scale of development in relation to hydrogen in emerging markets will be strongly impacted by take-up in, and appetite for investment from, the developed markets that are leading in this industry.
There is positive momentum growing in all of the emerging Asian markets discussed above. However, with the exception of China and India, scaling up production and domestic demand will arguably be an even greater challenge for emerging markets than markets such as Australia, Japan and South Korea (where it is recognised as a key issue to overcome), as the need to meet quickly and economically the energy demand of the high growth ASEAN countries trumps the ability to invest in new and expensive energy sources.
Existing conventional energy sources will remain a key staple in emerging markets in the near term.This may be addressed by direct renewable electrification (where possible and commercial) but we expect there will need to be a growing focus on availability of offset options. For this reason, and due to current constraints on renewable power and CCS in Japan and South Korea, these North Asian countries will be key destination markets for scaling up green and blue hydrogen production in Asian countries. Japan and South Korea look to finalise subsidy schemes for hydrogen and ammonia international supply chain projects towards the end of this year or the first half of next year. Projects globally, with no exception in Asia, are lining up their final investment decision and scale-up schedule with that of the Japanese and South Korean subsidy timelines.
We have been covering the developments in Japan’s subsidy regime for the use of low carbon hydrogen and ammonia over the past few years. Hitomi Komachi and Scott Neilson offer the latest update and insights.
Two of the biggest challenges with low carbon hydrogen and ammonia are the energy losses in their conversion and use cases and the staggering price gap with fossil fuel energy sources. The energy losses in using them as a carrier of energy suggest that the most compelling use case is where direct electrification is not feasible – like industrial processes that require a chemical reaction. The other challenge with low carbon hydrogen and ammonia (in part due to the energy losses) is their staggering cost – one calculation suggests that for every MWh of green hydrogen a USD12 per MWh subsidy on average is required; translates to every kilogramme of green hydrogen requiring USD396 of subsidy on average.
Japan’s subsidy regime faces two tides against it. A large part of the subsidy regime targets the power generation using hydrogen and ammonia, not the hard-to-abate chemical industry like shipping fuel or fertilisers. This is due to the sheer electricity demand that is not being met or cannot be met by renewable power sources today in Japan. The second tide is that the regime aims to address the large price gap between fossil fuel energy source and low carbon hydrogen and ammonia.
There are broadly speaking three categories of direct Japanese government subsidies aimed at supporting low carbon hydrogen and ammonia projects:
- NEDO Fund: The NEDO fund for research, development and pilot projects, on which please see our previous article here.
- Price gap support for international supply chain and support for domestic storage and transport: The price gap support (or the Contract for Difference scheme) for international supply chain projects and clusters support scheme for domestic storage and transport projects, on which please see our previous article here.
- Long-term Decarbonised Power Source Auction: The new long-term decarbonised power sources auction, which includes hydrogen and ammonia co-fired power, is a new auction which will start in January 2024.
Alongside this, government agencies and institutions like JBIC, JOGMEC and NEXI have been strengthening their investment and financing frameworks to accommodate and support investments in first-of-kind hydrogen and ammonia projects. Such projects face new bankability challenges, such as little to no track record on electrolyzer technology or CCS performance, new technology risk, ramp-up risk, volume risk and project-on-project risk within a complex array of infrastructure interfaces along the supply chain producing, transporting and distributing hydrogen.
These issues are magnified in the case of Japan, as it looks to overseas projects for the long-term commercial scale supply of hydrogen and ammonia, and every risk will need to be examined in the context of the jurisdiction where the particular infrastructure in the supply chain is situated, the green transformation journey of such host country and its legislative framework, and the geopolitical risks associated with cross-border supply chain projects.
Long-term Decarbonised Power Source Auction
The long-term decarbonised power source auction is the newest addition to the subsidy schemes developed by the Japanese government, and is set to further accelerate the demand for low carbon hydrogen and ammonia in Japan, amongst other sources of decarbonised power supply.
The auction is for the sale and purchase contracts of a variety of low carbon power sources, run on an auction basis, for 20 years, and to be run by and to be entered into with the Organization for Cross-regional Coordination of Transmission Operators, Japan. Electricity operators in Japan are eligible to apply for the auction. There is a range of eligible clean power sources (such as renewable power, nuclear and biomass) in the aggregate of 4000MW to be tendered out, out of which 1000MW is for refurbishing existing power plants (including for hydrogen and ammonia co-firing).
In particular, the following co-firing hydrogen and ammonia power sources will be included:
(a) the construction or replacement of power plants with hydrogen co-firing with LNG of 10% or more; or
(b) the retrofitting of existing power plants with hydrogen co-firing of 10% or more, or ammonia co-firing of 20% or more, provided that the capacity of the new co-firing facility exceeds stable supply of 50MW.
The bid price is subject to a different cap for each power source. In the case of the above:
(a) the greenfield or replacement hydrogen co-firing with LNG is subject to a cap on the bid price of JPY48,662 / kilo-watt per year; and
(b) the retrofitting hydrogen co-firing with LNG is subject to a cap of JPY100,000 / kilo-watt per year, and the retrofitting ammonia co-firing is subject to JPY74,446 / kilo-watt per year.
To translate these caps into USD MWh based figures (all USD figures in this section are based on the US/JPY foreign exchange rate as of 5 November), the subsidies range from USD37.19 per MWh to USD76.42 per MWh. These very high ceiling figures suggest that the government will be relying on the participants to determine the actual cost of production, rather than legislating it at this stage, which spurs healthy competition and is positive news for the private sector participants.
The current auction does not include CCS supplemented power plants, ammonia co-firing in LNG fired power plants construction or replacement, or e-methanol fired power plants, albeit it is noted that they will be eligible for later rounds.
To the extent a project takes advantage of the decarbonised power source auction, and seeks to also benefit from the price gap support for international supply chain projects, there are requirements to prevent double-recovery of costs through multiple subsidy schemes. Although the details remain to be seen, this is likely to be implemented through discounting the costs that benefit from one subsidy scheme, to the extent it is accounted for in another subsidy scheme.
A tentative budget breakdown requested by METI for the implementation of various hydrogen and ammonia subsidies, including those listed in 1-3 above, for the coming financial year is as follows (all USD figures in this section are based on the US/JPY foreign exchange rate as of 5 November):
|Budget for Hydrogen and Ammonia supply chain and infrastructure
|Budget requested for approval FY2024 (JPY Million) (US$ Million)
|International hydrogen and ammonia supply chain price gap support
JPY117,100 / USD783.96
*National Treasury Debt Burden (5 years): JPY578,500 / USD3,872.92
|Domestic hydrogen and ammonia supply infrastructure development project
|JPY3000 / USD20.08
|Investment in hydrogen, ammonia, etc. production, asset acquisition, etc. business
|JPY10,000 / USD66.95
|Technology development project for building a competitive hydrogen supply chain
|JPY8,600 / USD57.58
|Green Innovation Fund Project
|JPY2,756,400 / USD18,453.50
The first item and a part of the last item above form part of the GX budget within METI’s requested budget for the next fiscal year, being in the aggregate JPY1 trillion 98.5 billion yen (USD7 billion 354 million). A majority of this GX budget is requested through government “GX bond” issuance. Items two to three above form part of the Energy Special Account budget within METI’s requested budget for the next fiscal year, being in the aggregate JPY782bn yen (USD5bn 232m).
The above allocation shows that Japan continues to focus its budget on R&D and pilot projects through its original Green Innovation Fund established by NEDO a few years ago, whilst it is clearly gearing up for initiatives under the GX Act, including the JPY5 trillion (at the moment, around USD33bn 473m) price gap support programme, the JPY1 trillion (at the moment, around USD6bn 694m) infrastructure and retrofitting projects, and another JPY 1 trillion (at the moment, around USD6bn 694m) R&D programme.
The building blocks for Japan’s subsidy scheme for low carbon hydrogen and ammonia are stacking up steadily. The key ingredients for the price gap support for the international supply chain, including the criteria for low carbon hydrogen and ammonia (and others flagged in our previous article), will be the next key items to be finalised, as the CfD scheme is finalised in the coming months.
We are working with a number of international developers and investors who are lining up their hydrogen and ammonia projects to fit with the timeline indicated above. We look forward to seeing the first-mover hydrogen and ammonia projects being structured, thanks to the robust, bespoke and multi-layered Japanese subsidy regimes, in the coming years.
Xue Wang highlights findings based on our experience advising on nickel smelter projects in Indonesia, giga-factory projects and wider battery value chain experience.
Electric vehicles (EVs) form an essential part of the green transition, as they offer a cleaner and more efficient alternative to fossil fuel-based transportation. However, the rapid growth of the EV market in recent years also poses significant challenges for the supply chain of high performance batteries and the critical minerals that go into their production, such as lithium, cobalt, nickel, and manganese.
Asia is a key region for the EV battery supply chain, as it hosts some of the largest and most advanced battery manufacturers, such as CATL, LG Chem, Samsung SDI, and Panasonic (according to data from SNE research the top three battery makers – CATL, LG and Panasonic – together make up nearly 70% of the EV battery manufacturing market), as well as some of the largest and fastest-growing EV markets, such as China, Japan, South Korea, and India, and critical mineral resources.
An International Energy Agency publication provides the following statistics. China produces three-quarters of all lithium-ion batteries and is home to 70% of the production capacity for cathodes and 85% for anodes (both are key components of batteries). Over half of lithium, cobalt and graphite processing and refining capacity is located in China. In comparison to Europe, which is responsible for over one-quarter of global EV assembly, it is home to very little of the supply chain apart from cobalt processing at 20%.
South Korea and Japan also have considerable shares of the supply chain downstream of raw material processing, particularly in the highly technical production of cathode and anode material. South Korea is responsible for 15% of global cathode material production capacity, while Japan accounts for 14% of cathode and 11% of anode material production. South Korean and Japanese companies are also involved in the production of other battery components such as separators.
The unprecedented demand for batteries and minerals has led to the implementation of various policies and subsidies to encourage the development of the domestic EV supply chain industry, such as tax incentives, consumer rebates, charging infrastructure, and research and development support, but also restrictions on the export of raw materials (such as nickel from Indonesia) as well as increased scrutiny of ESG diligence along the supply chain.
However, scaling up the battery production and securing the mineral supply also requires massive amounts of capital and coordination up and down the supply chain, from mining and refining to manufacturing and recycling. This creates opportunities and challenges for investors, developers, and financiers who are looking to tap into this lucrative and strategic sector and compete for security of supply of battery minerals and production facility.
We have seen the emergence of limited recourse project financing being used to raise capital for upstream mineral extraction and processing facilities, as well as battery giga factories around the world, including in APAC, allowing sponsors and projects to raise large amounts of capital to fund further build out of battery supply chain projects and mitigate the risks among the various stakeholders.
These projects illustrate the growing investment appetite and innovation in the electric vehicle battery supply chain in Asia, which is crucial for the green transition and the competitiveness of the EV industry.
Most investments in the production of sustainable aviation fuel (SAF) have taken place outside of the Asia Pacific to date, but activities in APAC are rising. How will APAC, comprising a collection of countries with widely diverse and disperse needs and regulatory landscapes, tackle the next big bang of energy transition, this time in the aviation sector? Hitomi Komachi offers brief commentary.
Sustainable aviation fuel (SAF), also known as aviation fuel derived from biomass, waste or carbon captured from gas emissions, is making a headway in the APAC aviation industry.
Already, SAF is set to be the main tool by which the aviation industry globally will achieve their Net Zero emission targets by 2050. The International Air Transport Association (IATA) is counting on SAF to carry the industry 65% of the way to its goal, with other pathways to decarbonisation including fleet renewal, electric and hydrogen aircraft propulsion and air traffic management. A number of countries and major airlines around the world have each introduced targets to replace 10% of aviation fuel by SAF by 2030 or more. Most SAF investments have, up until 2023, taken place in Europe and the U.S., driven by comprehensive EU policy drivers including blending mandates and increasing cost of using fossil fuel, and the U.S. IRA credit for the production of SAF.
2023 marks a new era for SAF in APAC, triggered in part by the introduction of blending mandates by a number of countries in APAC like Japan and South Korea. Taking a whistlestop tour around the APAC countries, we consider what role this region may play for the emerging SAF industry.
In May 2023, Neste announced the opening of its expanded refinery for SAF in Singapore, increasing its production of SAF from 100,000 tonnes to 1 million tonnes of SAF per year, derived from waste oils, fats and other residues. Once SAF is produced in the Tuas region, it is sent to a blending facility to be combined with conventional fuel and certified to meet jet fuel standards, before delivery to airlines at the Changi Airport. The Civil Aviation Authority of Singapore, Singapore Airlines, and Temasek launched the sale of SAF credits in July 2022, and is part of a pilot project which involved 1,000 tonnes of neat SAF being supplied by Neste and blended with refined jet fuel at ExxonMobil’s facilities in Singapore. It remains to be seen whether a transparent and trusted market for the trading of SAF credits will emerge as a result of recent activities, but as a regional hub, Singapore is certainly set to be a promising ground for this.
Japan established its SAF roadmap and announced that the government will mandate, in 2030, 10% SAF use for international flights at Japanese airports, and oil wholesalers will be accountable for this measure. Japan’s transport department had announced last year a goal of replacing 10% of domestic airlines' fuel use with SAF by 2030. In April 2023, locally blended SAF was produced in Japan for the first time. Neste is supplying SAF to Japan airlines and All Nippon Airlines through its partnership with Itochu Corporation. In addition to its use case, Japan may also become a major producer of SAF in the long-term. Research by the Japan Transport and Tourism Research Institute (JTTRI) estimates Japan could, theoretically, produce between 7.06 million kl and 13.13 million kl of SAFs per year by 2030, comprising a 40% blend of carbon dioxide and hydrogen and 32% municipal and industrial waste. JTTRI expects the actual SAF supply to reach up to 1.34m kl per year by 2030, sufficient to provide 10% of the fuel consumption in the country.
Korean Air signed a memorandum of understanding with Shell to purchase and supply SAF at major airports in APAC and the Middle East for five years, beginning 2026. As in the case of Japan, Korean Air is also currently sourcing SAF from Neste, but currently has no domestic producer of SAF. South Korea announced plans to expand biofuel blending mandates but only set a target of 2026 for the introduction of SAF. The Ministry of Land, Infrastructure and Transport and the Ministry of Trade, Industry and Energy have responded by stating they will revise the Oil and Alternative Fuels Business Act by 2026, fostering the production of biofuels from sources like corn, sugarcane, and waste cooking oil. GS Caltex and HD Hyundai Oilbank have announced plans for SAF production, and they have the advantage of existing refineries located along coastlines to facilitate imports and exports, as well as existing transport and pipeline infrastructure which could be used for SAF.
The Indian government committed to putting in place a policy framework to move towards a blending mandate for SAF. India is the third-largest domestic aviation market in the world with forecasted yearly growth of around 9% going forward. Some airlines have tested blends in India already, and Vistara has piloted a long-haul flight using SAF. Airport operators Groupe ADP and GMR Airports together with Airbus, Axens and Safran have signed a MoU to conduct a joint study on SAF and their potential in India.
The 14th Five-Year Plan for the Green Development of Civil Aviation, issued by the Civil Aviation Administration of China, focuses on promoting breakthroughs in the commercial application of SAF and sets a target of achieving consumption of over 50,000 tonnes of SAF by 2025. However, compared to other energy transition technologies, China has been slow in its uptake of SAF, and until early 2023, Sinopec’s facility outside of Shanghai was the sole SAF production facility in China. In April 2023, Cathay Pacific committed to developing four power-to-liquid production facilities in China with State Power Investment Corporation. If these facilities become operational between 2024 and 2026, as planned, then SAF production in China could start before those in Europe, and China could, again, quickly rise to the top in terms of market share in the production of SAF, as it has become in other new technology low carbon energy sources, like green hydrogen, renewable power and batteries.
The Australian government is accelerating its plans to decarbonise the aviation sector, having formerly launched the Australian Jet Zero Council focused on end-to-end SAF production and announcing a funding program for local production of SAF to be coordinated by the Australian Renewable Energy Agency (ARENA). In order to benefit from funding, SAF will need to be derived from locally sourced renewable feedstocks, and power-to-liquids and e-fuels are excluded from the program. Separately, Qantas Group established a AUD400m climate fund as part of its broader emissions reduction policy. Qantas already has a AUD290m partnership with Airbus to help deliver commercial-scale SAF production in Australia and a commitment of AUD110 million for other SAF projects overseas. Currently Qantas relies on around 10 million liters of SAF supply per year from Heathrow and 20 million liters per year from California. The Queensland government is supportive of onshoring production, and has announced an investment in a new alcohol-to-jet production facility producing SAF from sugar cane, with other investors Jet Zero Australia and LanzaJet.
There are several themes coming out of this overview.
Firstly, while policy focus is growing there is little formal regulation in APAC. Japan and South Korea have the firmest demand side targets and policies. Interestingly, Indonesia had the earliest blending mandate but did not succeed in meeting it, partly as a result of the global move away from palm-derived energy sources. Encouragingly, both Singapore and India have stated intentions and are now moving forward with policy formulation. A significant laggard to date is China, but it is showing signs that it may be on the way to a quick catch-up and acceleration in SAF production.
Secondly, some parts of APAC show promising signs of becoming some of the biggest feeders of waste feedstock for SAF, such as China, India and Japan, due to the waste by-product of the biggest economic and industrial centres being in these locations. The landscape of possible feedstock providers is different to the usual energy and natural resource landscape where, for example, Japan is heavily dependent on importing natural resources. Many of the SAF projects in Europe, and early stage SAF projects in the APAC region, are dependent on the import of waste from China. Such projects could become victims of “waste nationalism” if China accelerates production of SAF domestically. So far, such trend hasn’t been seen but this risk is under discussion in many projects, particularly given the wider geopolitical dynamics. There is ample feedstock for certain technology pathways for sustainable aviation fuel in APAC, given this is a region which is home to the biggest population and demand centres in the world.
Thirdly, whilst there are many pilot projects, the difficulty lies in scaling and the cost of scaling in particular. According to the International Air Transport Association (IATA), global SAF production in 2022 was slightly above 300 million liters, which accounts for around 0.1% to 0.15% of total jet fuel demand. Only a handful of suppliers can produce SAF at scale.
SAF projects are complex, deploying new processing pathways to convert the relevant feedstock into jet fuel, and feedstock production often is a (start-up) project on its own. Production of ethanol from sugar bagasse, for instance, is a semi-agricultural, semi-refinery business, requiring the right environment, season, and technology to extract ethanol from bagasse.
Weather and environmental impacts of upstream agricultural waste feedstock have a direct impact on feedstock supply, and there are questions of prioritisation – given that feedstock in many cases is the byproduct of a primary product, such as sugar. This also goes towards qualifying SAF for the end-customers’ compliance requirements or eligibility for subsidies. Project-on-project structuring challenges are everywhere, upstream, midstream and downstream (e.g. blending facilities). Competition for good-quality and certifiable feedstock is high and there is a drive to secure partnerships and joint venturing early with potential high quality feedstock suppliers and offtakers.
APAC in particular offers high quality feedstock for SAF, and some of the biggest potential SAF demand centres across the region with high growth potential, which are relative advantages of APAC compared to other regions. With APAC governments’ commitments and support, including blending mandates, many investors are coming to invest in SAF in the APAC region. With the right level of support from the APAC governments, production and investments in SAF in APAC are set to grow significantly in the coming years.
While there have been significant increases in renewable energy capacity in recent years driven by commitments to Net Zero, there is still a long road ahead in emerging markets in Asia, where coal and natural gas still account for a significant proportion of the total energy mix.
Recognising this, ambitious goals for the increase of renewable energy have made their way into national power development plans for many countries and it is clear offshore wind has a key role to play in the energy transition agenda in emerging Asia. Xue Wang, Adam Moncrieff, Sarah Wilson, Michael Tardif and Jessica Lee offer observations on this proven but currently underutilised energy source.
Offshore wind – a promising option
Offshore wind is a promising cost-competitive and reliable option where land availability is limited and strong and consistent wind resources are available, for example in China, Taiwan, Vietnam, Japan, India, South Korea and the Philippines. The offshore wind market in Asia is set for rapid growth in the coming years, driven by the increasing demand for renewable energy, a supportive policy environment, strong investor appetite and ambitious targets in key markets.
According to the International Renewable Energy Agency, Asia could account for more than half of the global offshore wind capacity by 2050.
However, the development of the offshore wind industry in Asia has faced many head winds; affected by the challenges of cost inflation, supply chain tightening and vessel availability which also affect other offshore wind markets globally, as well as jurisdiction specific challenges.
Big plans in emerging markets
China remains the global leader in the offshore wind market, with more than 30 GW of installed capacity and ambitious plans to expand further in the coming years.
Taiwan completed the first phase of its Round 3 offshore wind auctions at the end of 2022. Taiwan continues to be a focus for many investors, despite recent challenges and delays faced by some of its offshore wind projects. However, with the most recently awarded projects increasingly being dependent on corporate PPA offtake as the main revenue source, this will present additional challenges for their bankability.
A strong pipeline of large scale projects, especially floating wind projects, are on the horizon in South Korea. South Korea has set a target of 14.3 GW of offshore wind capacity by 2030 (reportedly set to increase) and announced several mega projects, such as the 8.2 GW Sinan project and the 6 GW Ulsan floating wind project, which are expected to attract significant investment and create thousands of jobs.
With a 3,000-km coastline and strong wind speeds, Vietnam has the natural conditions required to develop a strong offshore wind market. The Vietnam government released the Power Development Plan 8 that sets an offshore wind target of 6 GW by 2030 and 70–91 GW by 2050 signaling the government’s commitment to the industry.
India has committed at COP26 to install 30 GW of offshore wind by 2030 and this year shared a strategy paper detailing the offshore wind auction trajectory for 2023 to 2030, pinpointing regions such as Gujarat and Tamil Nadu with the highest potential for offshore wind energy.
Developers in Japan are eagerly awaiting the outcome of the Round 2 offshore wind auctions, which are expected to be announced in March 2024. Japan has a target of 10 MW by 2030 and 30-45 GW by 2040 and huge potential for offshore wind capacity (of which a significant proportion is floating wind, due to its deep coastal waters). However, the development of the offshore wind market has been slower than expected due to uncertainty around the auction process, limited scale of the projects, supply chain constraints and port availability, and extensive environmental assessment and stakeholder engagement processes.
The Philippines is making plans to conduct its first green energy auction for offshore wind and, this year, the Executive Order No. 21 was issued mandating the preparation of a policy and administrative framework for offshore wind in order to accelerate development of the offshore wind market in the Philippines (though there remains no specific target for offshore wind at present).
New frontiers - floating offshore wind
On the horizon is floating offshore wind, where a handful of smaller projects around the world have provided valuable learning for the development of larger scale GW projects, starting in China where the PFS-1 Southeast Wanning project will be among if not the largest floating offshore wind project globally. However, higher costs and technical and logistical challenges as compared to its fixed-bottom counterpart, as well as supply chain issues, likely mean that widespread installation of large floating offshore wind is still some way off.
Challenges and head winds
Like many global markets, the development of the offshore wind market in Asia is currently facing significant challenges in terms of managing project economics due to cost inflation, declining subsidies and price competition (where governments have largely moved away from feed in tariffs), as well as supply chain constraints. Analysis from the Global Energy Wind Council shows that by mid-2020s supply chain bottlenecks may become an issue in all regions, except China. Substantial investment in the offshore wind supply chain will be needed to facilitate the growth of the offshore wind market at the pace currently targeted.
In addition, many jurisdictions, especially emerging economies in Asia, face additional challenges such as grid limitations, port availability, restrictive local content requirements, PPA bankability and the need for regional cooperation to avoid supply chain challenges and ensure availability of the vessels and skilled workforce needed for installation. Stability and certainty in the regulatory, permitting and seabed leasing regimes and auction rules is also lacking in emerging Asia and will need to be addressed.
A positive outlook
Notwithstanding the challenges, the offshore wind market in emerging Asia remains attractive and has huge potential. However, given global competition for supply chain and resources among the immense pipeline of offshore wind projects worldwide, it remains to be seen to what extent developers will prioritise and devote resources to projects in emerging markets in Asia. This will depend in part on whether and how well the challenges outlined above are tackled in emerging Asia though regulatory and framework development, incentives and regional collaboration.