This is an extract from a recent report “Hydrogen Demand and Supply in ASEAN’s Industry Sector: Current Situation and the Potential of a Greener Future” by ERIA.
Between 2015 and 2021, hydrogen demand increased in ASEAN countries with two industry sectors, i.e. ammonia and oil refining being its drivers. Hydrogen demand in industry sectors in ASEAN grew from around 3.270 million tons per annum (MTPA) in 2015 to around 3.745 MTPA in 2021. The most important share of hydrogen demand in ASEAN came from the ammonia industry, which increased steadily from around 46% in 2015 to 49% in 2021. Oil refining’s share, the second biggest, dropped from around 37% in 2015 to around 32% in 2021. By 2021, hydrogen demand from the methanol industry share reached almost 15% in 2021, increasing from around 11% in 2015. The iron and steel industry on the other hand, saw its small hydrogen demand share drop from 2.2% in 2015 to 0.7% in 2021. The chemical industry’s hydrogen demand share remained below 4% during the 2015–2021 period.
Global Hydrogen Economics
The majority of hydrogen currently used as feedstock for ammonia and methanol in Southeast Asia is produced via steam methane reforming (SMR). In the region’s major refining centres, SMR hydrogen is produced simultaneously with captive hydrogen from reforming and platforming and by products from various refining processes. By contrast, the steel industry still relies mainly on traditional basic oxygen furnace technology. Considering medium- and long-term process optimisation, technology synergies and scale effects, the figure below demonstrates the current cost advantage of SMR versus blue and green hydrogen alternatives, which is expected to reverse by 2040E–2050E
Electrolyser costs are, thus, expected to decrease due to learning and economy of scale, reaching US$200–US$300 per kW by 2030E. The cost of electricity makes up 30%–60% of the hydrogen levelized cost of energy (LCOE). As a result, when the LCOE of solar and wind power decreases to US$20 per MWh by 2030E, the cost of green hydrogen will fall to US$1.1–US$2 per kg by 2030E (IESR, 2022b). By 2050E the cost of green hydrogen could fall below US$1 per kg, with proton exchange membrane (PEM) electrolysis being even cheaper than alkaline electrolyser costs by then.
Global Green Ammonia, Methanol, and Steel Economics
Neuwirth and Fleiter (2020) report on their studies on the potential and production cost estimates for green hydrogen in the German chemical industry. Assuming electricity prices of EUR0.05/kWh and onsite alkaline electrolysis technology the authors estimate the production costs of hydrogen, ammonia and methanol between 2020, 2030E, and 2050E to reach levels Neuwirth and Fleiter (2020) calculate the 2020 production cost of green ammonia in Germany to be around EUR1,250 per ton, higher than SMR-based production costs of about US$960 per ton. They anticipate the cost of green ammonia to decline to US$1,030 per ton in 2050, as economies of scale and learning gain importance. By comparison, IEA’s Ammonia Technology Roadmap (2021b) estimates green and blue hydrogen based ammonia production costs to depend very much on electricity, i.e. energy costs and technology capital expenditures (CAPEX), as well as on future carbon prices.
IEA (2021b) observes that the US$600 per ton production cost of blue hydrogen-based ammonia breaks even with SMR hydrogen at a carbon price of about US$30 per ton. Moreover, electrolysis based ammonia production cost ranges from US$600–US$1,200 per ton, depending on electricity and electrolyser costs. Green hydrogen is clearly more likely to be competitive with SMR when electricity prices are low, natural gas prices are high and electrolyser costs low. Nevertheless, even at low electrolyser costs, electricity costs of lower than US$0.04 per kWh are required to render green hydrogen competitive. Moreover, electrolyser costs must decline by 60% to reach about US$400 per kW electrolyser capacity costs to become comparable to the level of grey hydrogen. By contrast, according to IEA’s Global Hydrogen Review (2021a), Hydrogen Council and McKinsey & Company (2022), and IRENA (2020), electrolyser CAPEX estimates still range from about US$1,000 per kW to US$1,750 per kW. Only in 2030E is the electrolyser system CAPEX expected to fall to US$230–US$380 per kW. Nevertheless, uncertainties in technology innovation affects the feasibility and timing of the necessary cost reductions
Green Hydrogen Transition in Southeast Asia
According to IEA (2021a) up to 850 GW of aggregate renewable electricity capacity is required to produce the world’s demand for 80 MTPA green hydrogen by 2050. The hydrogen supply required to feed a midsize 400 KTPA ammonia or 600 KTPA methanol plant ranges from approximately 75 to 85 KTPA. Southeast Asia’s largest refineries in Indonesia, Thailand, and Singapore produce approximately 30–70 KTPA of hydrogen, net of their own captive hydrogen from reforming and platforming processes, hitherto supplied by their own captive SMR. To supply these industrial facilities requires about 1,000–2,200 megawatts (MW) single-site, dedicated peak solar PV generation capacity, and up to 700–1,500 MW of electrolyser capacity.
In the Pacific region Australia, China, and the Republic of Korea are currently planning GW-scale single site electrolyser facilities. To date not sufficiently large single-site solar PV, wind, or geothermal electricity generation capacity exist in Southeast Asia. Amongst the announced GW-scale solar PV projects in the region are the Singapore’s Sunseap’s plans for up to 7 GW capacity around the Indonesian Riau Islands, which include a 2.2 GW floating solar PV project in Batam Island, Australia’s ReNu, and Anantara’s 3.5 GW project in Riau. Li et al. (2023) quotes the ASEAN Centre for Energy’s (ACE, 2020a) 6th ASEAN outlook for renewable electricity generation capacity in the region as summarised in Table 5.3. Thus, significant production, storage, and transport capacity expansion and investments are required.
A transition towards decarbonised hydrogen in industry can be expected to follow a path of staggered blue and green production and infrastructure development. Initially, the more incremental increase in CAPEX and operating costs (OPEX) of introducing CCS technology limits the loss in competitiveness and moderates any fiscal support necessary to incentivise and support the large industrial users and gas merchants. Fossil fuel companies are anticipated to favour the blue hydrogen route, at least in the near term. By contrast, the development of green hydrogen production and infrastructure projects will be much costlier and will require significant participation of the electricity sector, as the required power generation capacities will be larger than many solar PV, wind, geothermal, and other renewable power projects hitherto built or planned, even in industrialised Europe and North America. Therefore, whilst government and industry are working on multiple CCS projects across the region, plans must be made to initiate and implement several flagship green hydrogen projects to gain economies of scale and critical mass in green hydrogen production, storage and transport infrastructure, to help kickstart the green transition for all major hydrogen-consuming sectors.
Beyond replacing grey with blue and green hydrogen for the traditional industrial feedstock applications, likely scenarios introduce the utilisation of green hydrogen via green ammonia as energy carrier for storage and transport as well as complementary fuel for coal and natural gas combined cycle power generation. Moreover, in future decarbonisation scenarios, methanol can be used as a feedstock for e-fuels, to replace traditional higher emission diesel and gasoline across road transport applications.
Economics of Hydrogen in ASEAN
Several studies have analysed potential green hydrogen production, and storage and transport costs in Southeast Asia. The most important cost component is the renewable electricity cost. The solar PV electricity prices that Li and Taghizadeh-Hesary (2020) assume range from US$0.04 per kWh in Indonesia and Malaysia, US$0.038 per kWh in Thailand, and US$0.041 per kWh in Viet Nam. These electricity costs contrast to Li et al.’s (2023) higher estimated solar PV electricity prices of US$0.165 per kWh in Indonesia, US$0.108 per kWh in Malaysia, US$0.145 per kWh in Thailand, and US$0.092 per kWh in Viet Nam.
According to Li et al. (2023) regional grid and wind power prices are higher than solar PV except in Indonesia, where grid prices are subsidised. By contrast, hydropower and woody biomass prices are generally lower. Additionally, the Institute for Essential Services Reform (IESR) (2022b) uses Ministry of Energy and Mineral Resources (MEMR) data to estimate renewable electricity costs in Indonesia of US$0.07–US$0.16 per kWh (for onshore wind), US$0.06–US$0.10 per kWh (large scale solar PV), US$0.05–US$0.09 per kWh (geothermal) and US$0.05–US$0.11 per kWh (biomass).
Hydrogen production and onsite delivery costs
Whilst current costs of producing green hydrogen in the ASEAN region reach as high as US$8–13 per kg, levelized production costs of US$4.0–US$6.2 per kg and US$2.7–US$4.3 per kg are anticipated by 2030E and 2050E, respectively. As electrolyser and renewable energy capacity and operating costs decrease, we thus anticipate green hydrogen to become more competitive towards 2030E and especially towards 2050E. Note that, if the PV solar capacity factor is reduced from 20% to 15%, the levelized green hydrogen production costs increase to US$10–US$14 per kg at today’s cost levels, US$4.5–US$7.0 per kg by 2030E, and US$3.1–US$4.7 per kg by 2050E.
Clearly some combination of public sector co-financing, subsidies, or tax breaks, optimal carbon prices, and collaboration with multiple regulators, public and private companies are necessary to plan and implement the production of green hydrogen in the near term. As a consequence, the feasibility of implementing a green hydrogen transition in ASEAN industries hinges on an analysis of the political economy of hydrogen in the region.
Production of low-carbon or green hydrogen would become much greater when its price is low. Low prices of low-carbon hydrogen will happen when the low-carbon electricity and hydrogen production pathways can reach economies of scale in the most climate-ambitious scenario. The price of renewable electricity, the necessary land and infrastructure needs, and the price of electrolysers are key factors in estimating the future price of low-carbon or green hydrogen. Other important factors are the price of competing fossil fuels, especially natural gas, and the policies to set prices on carbon.
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