01 POWER ISLAND / 02 H2+NH3 / The_Future_of_Hydrogen-IEA-2020
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The Future of Hydrogen |
Chapter 6: Policies to boost momentum in key value chains |
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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 lowcarbon 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.
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The Future of Hydrogen |
Chapter 6: Policies to boost momentum in key value chains |
European Neighbourhood Instrument, which has a budget of over EUR 15 billion for 2014 to 2020. The Africa–EU Energy Partnership’s energy security objectives include doubling electricity interconnections and African gas exports to EU by 2020 compared to 2010. The European Union already imports around 12–14% of its gas demand from North Africa (mainly Algeria), although it is not yet clear whether these pipelines could be repurposed costeffectively to carry hydrogen at shares above a few per cent.
Near-term policy priorities
Targets and long-term policy signals. Alignment of countries’ national hydrogen strategies and roadmaps via bilateral and multilateral partnerships would help the management of risks at both ends of the value chain.
Demand creation. Imported hydrogen can be used in many sectors, but end users will only switch to hydrogen, or hydrogen-based products, if it is cost-effective to do so. Governments could help make hydrogen cost-effective in target sectors by using portfolio standards, mandates, performance standards, tax exemptions and CO2 pricing. Exporting countries could stimulate early exports by providing time-limited support to buyers. Infrastructure costs might be minimised by tendering programmes with international support. Reaching sufficient demand to justify investment in import and export terminals, and hydrogen supplies, might similarly be best achieved through international co-operation.
Investment risk mitigation. The first commercial-scale hydrogen export and import infrastructure projects will represent sizeable investments and may benefit from being structured as public–private partnerships with some direct public investment and multi-stage competitions to award contracts. In some cases, risks might best be managed by taking a modular approach and starting with funding smaller projects that reassure financers, although this might well not be effective for infrastructure such as tankers and storage facilities. Subsequent projects should benefit significantly from the exchange of learning and knowledge from the first projects, insofar as these need not be commercially confidential. It would be very helpful for risk management to have early clarity from governments on the question of tariffs, and to have clear permitting processes in place for hydrogen imports, especially for large, capital-intensive infrastructure projects in first-of-a-kind industries.
R&D, strategic demonstration projects and knowledge sharing. Uncertainty remains about the most effective type of carrier for shipping hydrogen, with much scope for thorough investigation of the options and improvement of efficiency and capital costs. Liquefaction efficiency, boil-off management, scalability and the efficiency of the cooling cycle require improvement. Strategic demonstration projects could target the scale-up of liquefaction and regasification facilities for hydrogen directly or in the form of ammonia.
Harmonising standards, removing barriers. International standardisation will be crucial in this value chain, including for “guarantees of origin”,61 hydrogen purity, the design of liquefaction/conversion and regasification/reconversion facilities, and for equipment specifications. Some IMO regulations may need to be revised and new ones established.
61 This is described in Table 12. Note: for hydrogen produced with CCUS leading to permanent CO2 storage or equivalent, a simple approach could be to multiply the hydrogen output by the CO2 capture rate to calculate a quantity certified “low-carbon” hydrogen. The rest of the hydrogen would be uncertified (i.e. having the CO2 intensity of unabated fossil hydrogen).
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