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The Future of Hydrogen Chapter 6: Policies to boost momentum in key value chains Box 20. Key ongoing hydrogen projects related to hydrogen trade in Asia Pacific Electrolysis. A 50 MW electrolyser in combination with wind, solar and batteries (150 MW, 150 MW and 400MWh respectively) at Crystal Brook Energy Park, Australia, is expected to move to a final investment decision in 2019 and commissioning in 2021 (Parkinson, 2018). A 30 MW electrolyser project near Port Lincoln, Australia, has AUD 118 million funding for a 2020 start (Government of South Australia, n.d.). This project will produce up to 18 ktH2/yr. Fossil fuel-based production. An AUD 500 million project to convert coal with CCUS to 3 tH2 for liquefaction and shipping to Japan by 2021 has a 50/50 funding split between Australia and Japan for the infrastructure in the two countries by 2021 (DIIS, 2018; HESC, 2019). A USD 100 million pilot project in Brunei to produce 210 tH2 from natural gas for shipping by liquid organic carrier to Japan for power sector use is under construction for operation in 2020. The Institute of Energy Economics Japan is exploring the feasibility of ammonia imports produced from natural gas with CCUS in Saudi Arabia. This imported ammonia could be used for power generation in Japan. The price of ammonia needs to be USD 350/t to be competitive with power generation from gas and coal in Japan. Kansai Electric Power plans to demonstrate ammonia co-firing with coal by 2020. IHI has been looking into firing ammonia with 20% methane in Yokohama since 2016. Hybrid. Evaluation of the scope for producing hydrogen from hydropower and natural gas with CCS for shipping to Asia is underway in Norway. Sources: Parkinson (2018), “Neoen plans world’s biggest solar + wind powered hydrogen hub in S.A.”; Government of South Australia (n.d.), “Hydrogen and green ammonia production facility”; DIIS (2018), “Local jobs and a new energy industry for the LaTrobe valley”; HESC (2018), “Latrobe Valley”. Hydrogen trade in Europe in the 2030 timeframe Extensive opportunities are open for hydrogen trade between countries in Europe. The gas grid is the most likely vehicle for such trade, but dedicated cross-border pipelines or internal waterways could also be used. Trade in hydrogen as well as electricity could help smooth low- carbon energy supplies between countries and help match low-cost supplies with demand, and imported hydrogen might be competitive with local production (Chapter 3). This is especially true for electrolysis hydrogen from renewables: production in North Africa from dedicated renewable electricity might have import costs in the near future as low as USD 4.7/kgH2 for over 500 MtH2/yr,60 which compares favourably with USD 4.9/kgH2 from renewable electricity in much of Europe. Hydrogen from natural gas with CCUS could also be imported from the Middle East at competitive costs as low as USD 2/kgH2 as ammonia, or USD 2.6/kgH2 if cracked to pure hydrogen. If CO2 storage is equally accessible in Europe at similar costs, however, it is likely to be more cost-effective to import the gas and produce hydrogen in Europe. Natural gas can be imported with local conversion to hydrogen with CCUS at a cost of around USD 2.3/kgH2. Energy trade with these regions is a pillar of European neighbourhood policy, and is expected to remain so. To support this policy objective the European Union supports energy infrastructure investments in Africa and the Middle East. These regions are included in the scope of the 60 Water desalination, where required, is estimated to add only 1% to these costs. PAGE | 191 IEA. All rights reserved.PDF Image | The Future of Hydrogen 2019
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