Hydrogen

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This IRENA report provides a more in-depth perspective on the nexus between hydrogen and renewable energy, on hydrogen supply economics in light of the rapidly falling cost of renewables and the role of hydrogen in the energy transition, as well as on existing challenges that have hampered hydrogen development to date.

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This report builds on the unique IRENA datasets for renewable power generation cost, electrolysers, and future power and energy system configurations.

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Country’s strategies differ in terms of hydrogen production pathways and key hydrogen end uses according to each country particularity (Kosturjak et al., 2019).

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IRENA’s Renewable Energy Roadmap (REmap) analysis indicates an 6% hydrogen share of total final energy consumption by 2050 (IRENA, 2019a), while the Hydrogen Council in its roadmap suggests that an 18% share can be achieved by 2050 (Hydrogen Council, 2017).

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Residential fuel cell applications in the residential sector have constantly increased and comprised 225 000 units installed globally as of the end of 2018.

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In the most recent case, in Norway in early 2019, the cause of an explosion in a hydrogen fuelling station was a faulty installation, and in the Republic of Korea a storage tank became contaminated with oxygen.

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In Germany, transmission system operator Amprion and gas net operator OGE have presented an investment-ready plan for a 100 MW electrolyser and a dedicated hydrogen pipeline in the north-west of Germany that could come online in 2023, a EUR 150 million (USD 168 million1) proposal (Amprion and Open Grid Europe, 2019).

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A 40 MW wind park coupled with electrolysers is planned near a chemical industry in Germany by VNG, Uniper, Terrawatt and DBI, including 50 billion cubic metres of storage and a dedicated hydrogen pipeline, with potential expansion to 200 MW by 2030.

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In Fukushima, Japan, a 10 MW electrolyser has been ordered by Toshiba to provide 900 tonnes per year of hydrogen from renewables, to be used for transport applications.

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The Japanese strategy also comprises the Yamanashi Fuel Cell Valley which includes a power-to-gas facility utilising a 1.5 MW PEM electrolysis coupled with a 21 MW solar PV system ( Ohira, 2019).

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Another domestic manufacturer, Suzhou JingLi Hydrogen Production Equipment Co., Ltd., signed co-operation agreements in August 2018 with Dalian Institute of Chemical Physics for new hydrogen generation via water electrolysis technology research and is also part of the “973” National Research Program “Large Scale Hydrogen Production of Wind Power”.

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The “ 863” and “973” national plans receive funding from MOST and include several projects related to fuel cell technology development, which seems to be the main focus for hydrogen development in China (Holland Innovation Network China, 2019).

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At present, mid-size hydrogen FCEVs are offered at a premium cost, around 50% more than similar internal combustion engine (ICE) vehicles, although a significant scaling effect could decrease costs if production grows substantially, according to manufacturers.

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In the UK, the role of hydrogen in combination with existing natural gas distribution infrastructure has been thoroughly explored in a region of 5 million inhabitants as a key option for decarbonisation of heating, and a large-scale pilot project is scheduled in the north of England (CCC, 2018; Sadler et al., 2018).

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However, the long-term market outlook is clouded, as oil demand may decline as the energy transition moves forward.

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It offers a prospect of continuity to fossil fuel producers, and it can help to meet climate objectives at acceptable cost.

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Blue hydrogen is deployed in limited niche applications today; for instance, a minimum amount of clean hydrogen is required for FCEVs in California (Carbs, 2014).

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Because the majority of the around 20 CCS projects currently in operation are dedicated to EOR, it is crucial to ensure that CO₂ is retained after injection.

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Rapid scale-up of CCS demonstration and deployment was identified early on as a necessary condition for its uptake (IEA, 2004).

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For instance, the Gorgon CCS facility was due to start operations in 2009 (IEA, 2004), while in reality it started a decade later (Global CCS Institute, 2019).

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In 2018, a feasibility study was started to explore the business case, technological challenges, hydrogen markets and CCS.

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The first plant is planned to open in 2025, and the hydrogen produced will be transported to parties within the harbour or elsewhere in the Netherlands.

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Such infrastructure can be leveraged to facilitate the delivery of hydrogen, as well as acting as a large and low-cost source of storage capacity (Panfilov, 2016).

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The infrastructure should be assessed, but for most components a share in volume4 of 10-20% seems to be achievable without major investments (IRENA, 2018a; Judd and Pinchbeck, 2016; Müller-Syring et al., 2013).

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In Germany, the gas grid is undergoing a 10-year, EUR 7 billion (USD 7.8 billion) renovation to switch 30% of its customers from natural gas with lower methane content (L-gas) to gas with higher methane and higher calorific content (H-gas).

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What is certain is that to move to 100% hydrogen, most appliances – as well as most of the transmission and part of the distribution system for natural gas – will need major upgrades.

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Because hydrogen can be produced at low cost in remote desert locations and shipped to markets, regions such as the Middle East and North Africa and countries such as Argentina, Australia, Chile and China, among others, see new opportunities.

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A conversion to a hydrogen economy therefore offers new economic prospects to countries and regions that rely today on fossil fuel exports for a significant part of their national revenues.

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This translates into around 4-16 terawatts (TW) of solar and wind generation capacity to be deployed to produce renewable hydrogen and hydrogen-based products in 2050, considering losses along the supply chain.

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In IRENA’s REmap scenario for 2050, 19 EJ of hydrogen from renewable power translates into 5% of total final energy consumption and 16% of all electricity generation being dedicated to hydrogen production in 2050.

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EVs and heat pumps provide 75% and 270% more energy services, respectively, when compared to fuel cell vehicles and hydrogen boilers, respectively, in equivalent applications (CCC, 2018).

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Liquefaction: A significant amount of electricity is required to liquefy hydrogen via the liquefaction process, which currently leads to losses of 20% to 45% of the hydrogen energy content only (Berstad et al., 2013; Cardella et al., 2017; H21 NoE, 2018, p.

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However, it likely is not possible to produce significant amounts of hydrogen using exclusively cheap or free “otherwise curtailed” electricity if electrolysers operate only around 10% of the time or less.

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A balance needs to be struck between buying electricity at times of low prices and increasing the utilisation of electrolysers (IRENA, 2018a).

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According to IRENA’s analysis (2019b), storage needs for integrating large shares of solar and wind power will grow significantly in 2050, compared to today.

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A 440 MW hydrogen power generation retrofit of a gas power plant is being implemented in the Netherlands and is due for commissioning in 2023.

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Solar-wind hybrid systems appear as a promising solution and could achieve capacity factors well above 50% in places such as the Atacama Desert in Chile where they complement each other in terms of availability.

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For instance, a recently installed CSP project in Morocco is planned to produce electricity with a capacity factor as high as 65%, based on eight-hour thermal storage, which enables power generation also at night.

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Similar projects are still expensive, however, and generate electricity at a price of more than USD 80 per megawatt-hour (MWh) (IRENA, 2019c).

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The best case considers a low cost electrolyser of USD 200/kW, which at a broader scale is expected to be achieved only from 2040, although Chinese manufacturers claim that it is a reality already today.

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The low-cost renewable power of USD 23/MWh is seen today in wind projects in countries such as Brazil and Saudi Arabia (IRENA, 2019d).

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Thus, the question is how early competitiveness is to be achieved given expected developments in the different parameters, and to what extent complementary technologies can or will help this movement.

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The competitiveness of hydrogen from renewables will continue to improve between now and 2050.

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This model would allow for the development of large-scale wind and solar farms, as well as other renewables such as hydro and geothermal where applicable, where the resource potential and the investment conditions allow for lower costs of electricity from renewables.

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A recent analysis suggests that competitiveness is currently close and is expected to improve continuously as the costs of renewable electricity and electrolysers continue to fall (Glenk and Reichelstein, 2019).

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The international hydrogen market and related shipping can be considered similar to natural gas, and the hydrogen will likely need to be transported over long distances.

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Its low volumetric density, in addition to a relatively high energy content, means that it is lighter to transport, but it requires more space than fossil fuel alternatives.

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Liquefaction has as the main drawback its high consumption of power, accounting for roughly 20-40% of the hydrogen energy content in the liquefaction process6, in addition to eventual hydrogen loss due to boil-off.

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However, if pure hydrogen is required (for example, for fuel cells) and thus ammonia cracking is needed, liquefaction may be the most efficient route (Kojima, 2019; Wijayanta et al., 2019).

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Examples of potential liquid organic hydrogen carriers are methanol, toluene and phenazine (Aakko Saksa et al., 2018; Niermann et al., 2019).

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The graph shows that logistics costs matter in the total supply cost; typically, they account for 30-40% of the total supply cost.

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With such development, and considering past technological learning rates responsible for costs decreasing (Junginger, 2018; Louwen et al., 2018), electrolyser costs should halve from USD 840/kW to USD 375/kW between now and 2050.

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According to CCC (2018), costs of hydrogen from SMR with CCS are expected to increase by 2% on average from 2025 to 2040.

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Hydrogen can be produced at lowest cost in locations with the best renewable energy resources and low project development costs.

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This capacity is aimed primarily at the local iron mining industry but also with an eye to hydrogen exports. » Utility-scale solar PV costs decreased from USD 90/MWh in 2015 and are expected to reach USD 29.8-41.2/MWh in 2020 (Acil Allen Consulting and ARENA, 2018).

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On-grid, CORFO found as low as USD 1.6/kg for 2025 in its energy modelling. » Utilising a small amount of the solar PV potential in the Atacama Desert could lead to hydrogen production of more than 450 000 tonnes per year.

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Saudi Arabia: In the future, hydrogen from Saudi Arabia could be produced from a combination of wind and solar PV with the objective of increasing the capacity factor while marginally raising electricity costs (WEC, 2018).

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Wind farms at current power levels and CSP plants drop to USD 35-40/MWh. » The country’s power generation relies heavily on fossil fuels, consuming around 1 million barrels a day. » Hydrogen from renewables could support a better management of fossil fuels.

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If achieved, renewable power targets could reduce oil consumption to 141 million barrels of oil equivalent (Mboe) or 19% of the power sector’s fossil-fuel consumption.

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Electrofuels (e-fuels) are produced by the reaction of hydrogen with CO₂ (see Box 4) into liquid products with gasoline, diesel, jet fuel or naphtha-like characteristics.

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Recent pilot-scale cost estimates for DAC are lower than earlier expected, at levels of USD 94 to USD 232 per tonne of CO₂ (Keith et al., 2018), with some cost projections reaching below USD 60 per tonne of CO₂ by 2040 (Fasihi et al., 2019).

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Ammonia is a global commodity with production volumes of around 175 Mt/year.

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Because ammonia has an energy content of 18.6 GJ per tonne, roughly half that of oil products and comparable to biomass, it can also be used as an energy carrier.

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Losses in the process are significant, but they can be reduced if ammonia is used as a fuel instead of being cracked to extract hydrogen (Obara, 2019).

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It can be used as a fuel in the future, either directly combusted or reformed on board fuel cell vehicles (Agarwal et al., 2019).

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Whereas its role will be modest in the coming decade, and further cost reductions are required, hydrogen can grow thereafter to make a substantial contribution by 2050.

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python scripts/verify_primary_public_claim_group.py artifacts/cb7k_dom070_t07_primary_claims.json --source-file <local-raw-pdf>

Include the hydrogen economy in the revision of Nationally Determined Contributions (NDCs) for the Paris Agreement, due in 2020.

Evidence card JSONRendered card

Download the PDF to a local file, then run the committed verifier. A changed PDF is reported as drift rather than silently accepted.

python scripts/verify_primary_public_claim_group.py artifacts/cb7k_dom070_t07_primary_claims.json --source-file <local-raw-pdf>

A number of demonstration projects will come onstream in the coming years where transmission pipelines, gas distribution systems and districts are converted to hydrogen.

Evidence card JSONRendered card

Download the PDF to a local file, then run the committed verifier. A changed PDF is reported as drift rather than silently accepted.

python scripts/verify_primary_public_claim_group.py artifacts/cb7k_dom070_t07_primary_claims.json --source-file <local-raw-pdf>

Various studies (DNV GL, 2017a; Dodds and Demoullin, 2013; E.ON, 2019; Judd and Pinchbeck, 2016; Quarton and Samsatli, 2018) suggest that a transition of the gas pipeline system is viable, but that only practice will show the technical and economic viability.

Evidence card JSONRendered card

Download the PDF to a local file, then run the committed verifier. A changed PDF is reported as drift rather than silently accepted.

python scripts/verify_primary_public_claim_group.py artifacts/cb7k_dom070_t07_primary_claims.json --source-file <local-raw-pdf>

Launch demonstration projects at sites where hydrogen production and hydrogen commodity production can be combined.

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