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Hydrogen

More efforts needed
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In this report

Hydrogen technologies proved remarkably resilient during the Covid-19 pandemic, with their momentum remaining strong in 2020. It was a record year in policy action and low-carbon hydrogen production, with ten governments around the world adopting hydrogen strategies. Close to 70 MW of electrolysis capacity was installed, doubling the previous year’s record, and two facilities producing hydrogen from fossil fuels with CCUS became operational, expanding production capacity by ~15%.

However, this progress falls well short of what is needed in the Net Zero Emissions by 2050 Scenario. Moreover, low-carbon hydrogen demand for new applications remains low, limited to road transport only. Therefore, more efforts are needed in demand creation and in reducing emissions associated with hydrogen production.

Global hydrogen demand by production technology in the Net Zero Scenario, 2020-2030 

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Global hydrogen demand by sector in the Net Zero Scenario, 2020-2030

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Tracking progress

Hydrogen demand in 2020 was ~90 Mt, with more than 70 Mt used as pure hydrogen and less than 20 Mt mixed with carbon-containing gases in methanol production and steel manufacturing. Almost all this demand was for refining and industrial uses. Currently, hydrogen is produced mainly from fossil fuels, resulting in close to 900Mt of CO2 emissions per year.

Clean energy progress for hydrogen can be tracked by three main indicators:

  • The extent to which low-carbon hydrogen production replaces conventional hydrogen in existing industrial applications and meets demand for new applications.
  • Demand growth in new sectors (e.g. for some transport and industrial applications, production of synthetic fuels and electricity storage), where it can help reduce CO2 emissions if production is based on low-carbon technologies.
  • Scale-up, cost reductions and improvements (in efficiency, lifetime or process integration) of cross-cutting technologies such as electrolysers, fuel cells and CCUS-equipped hydrogen production. 

Oil refining is the largest consumer of hydrogen today (close to 40 Mt in 2020), and will remain so in the short to medium term. Hydrogen used in this sector is normally produced onsite by steam methane reforming, separated from by-product gases from petrochemical processes or sourced externally as merchant hydrogen (typically produced in dedicated plants for hydrogen production using steam methane reforming).

The use of low-carbon hydrogen in refining faces an economic barrier due to its higher cost compared with unabated fossil-based hydrogen. However, replacing this hydrogen production capacity with low-carbon technologies would not be as technically challenging as adopting hydrogen for new applications. Therefore, this is an ideal opportunity to easily ramp up low-carbon hydrogen demand while decreasing the CO2 emissions from refining processes.

Regarding using fossil fuels with CCUS for hydrogen production, Shell was the first mover with its 2005 project at Pernis refinery (in the Netherlands) to capture CO2 from heavy-residue gasification units. Others have followed since, and there are already six facilities producing hydrogen from fossil fuels coupled with CCUS, the last one entering into operation in 2020 at the North West Sturgeon refinery (Canada). These facilities have a production capacity of 320 kt of low-carbon hydrogen (25% higher than in 2019), but production could rise to 380 t in 2021 if two projects currently under development in China become operational.

In addition, two projects (both in Germany) currently use electrolytic hydrogen in refining operations: a 5‑MW (~0.7 kt of production capacity) polymer electrolyte membrane (PEM) electrolyser at H&R Ölwerke Schindler refinery in Hamburg (since 2018) and the Refhyne project at the Shell Rhineland Refinery, a 10‑MW (~1.5 kt of production capacity) PEM electrolyser that became operational in July 2021. Furthermore, the first phase of the HySynergy project at the Shell Fredericia refinery (20 MW, ~3 kt of production capacity) is expected to become operative in 2022, and construction recently began on the Multiphly project in the Netherlands to demonstrate a 2.4 ‑MW (~0.5 kt of production capacity) solid oxide electrolyser cell electrolyser in refinery operations.

Europe is particularly active on this front, with more than 1.3GW of electrolysis capacity (~230 kt of production capacity) under development in refineries, the majority still at early stages targeting deployment by 2025. Close to another 700 MW (more than 110 kt of production capacity) of projects aim to produce merchant hydrogen linked to refining operations, along with other applications.

The IEA estimates that the amount of low-carbon hydrogen used in refining rose from 250 kt in 2019 to more than 300 kt in 2020, and based on the current pipeline of projects, 1.2-1.4 Mt of low-carbon hydrogen could be used in 2030. Nevertheless, this is well below the expansion required to stay on track with the Net Zero Emissions by 2050 Scenario, which prescribes 5 Mt by 2030.

Industry sector demand for hydrogen was 51 Mt in 2020, with chemical production consuming ~46 Mt. Roughly three-quarters was used for ammonia production and one-quarter for methanol. The remaining 5 Mt was consumed in the direct reduced iron process for steelmaking. Only 0.3 Mt of 2020 demand was met with low-carbon hydrogen (close to 20% more than in 2019), mostly from a handful of large-scale CCUS plants, small electrolysis units in the chemical subsector, and one CCUS project in the iron and steel subsector.

Hydrogen demand in industry, 2020

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In the Net Zero Emissions by 2050 Scenario, total hydrogen demand from industry is expected to expand 44% by 2030, with low-carbon hydrogen becoming increasingly important (amounting to 21 Mt in 2030). Analysis of the current project pipeline suggests that only ~18% of this demand would be met: CCUS-equipped projects supply 1 Mt of total low-carbon hydrogen demand in 2030, and electrolytic projects 3 Mt. Rapid action is clearly needed in the next ten years to meet projected Net Zero Emissions by 2050 Scenario industry sector hydrogen demand.

Low-carbon hydrogen project pipeline and demand in industry by 2030 in the Net Zero Scenario

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In the chemical subsector, total hydrogen demand in traditional applications (ammonia and methanol production) reaches 54 Mt by 2030 in the Net Zero Emissions by 2050 Scenario. New hydrogen applications, like high-value chemicals and high-temperature process heat, are expected to trigger 2 Mt of additional hydrogen demand for the subsector. Of total demand in 2030, 9 Mt should be met with low-carbon hydrogen.

However, projects currently in the pipeline will be able to supply only 2.3‑3.1 Mt/yr of low-carbon hydrogen by 2030, representing ~33% of Net Zero Emissions by 2050 Scenario requirements.

Demonstration projects using electrolytic hydrogen (1-4 kt H2/yr) for ammonia production are currently advancing, including a project by Fertiberia and Iberdrola (Spain) to blend hydrogen from solar PV-powered electrolysis (expected to come online at the end of 2021).  Several projects are also aiming to scale up this concept to 30-140 kt/yr in the coming years. Producing ammonia with CCUS (with the captured CO2 usually used for enhanced oil recovery) is already well established and today provides ~0.2 Mt of low-carbon hydrogen for ammonia production.

With pre-commercial plants in Iceland and China, methanol production using electrolytic hydrogen amounts to ~2 kt/yr of low-carbon hydrogen. Several projects aim to scale this concept up to 10 kt/yr, including e-Thor and Djewels (the Netherlands), North-C-Methanol (Belgium), and LiquidWind (Sweden). In addition, two demonstration projects capturing CO2 for enhanced oil recovery are under way in China, another is to start in the United States in 2025, and one for Canada by 2025 is under consideration. Together, they can add more than 0.3 Mt/yr of low-carbon hydrogen. 

In the iron and steel subsector, hydrogen demand is expected to triple to 18 Mt by 2030 in the Net Zero Emissions by 2050 Scenario. New hydrogen uses are central to the subsector’s decarbonisation strategy. While commercial-scale 100% hydrogen-based direct reduced iron (DRI) is not expected until the early 2030s, hydrogen can be substituted for a portion of natural gas and coal in DRI and blast furnaces, or it can be used to generate heat for ancillary units.

Projects currently in the pipeline amount to 0.5-0.8 Mt of low-carbon hydrogen through 2030, representing only ~7% of the Net Zero Emissions by 2050 Scenario 12‑Mt target. Today, only a handful of plants use low-carbon hydrogen in iron- and steelmaking. These include a DRI plant equipped with CCUS in the United Arab Emirates, which captures CO2 for enhanced oil recovery nearby and for some demonstration projects that use electrolytic hydrogen in steel-related projects.

In Germany, the Carbon2Chem project uses CO2 captured from blast furnace gas for methanol production, and multiple EU projects are trialling hydrogen injection into DRI and blast furnaces. The SALCOS (Germany) and H2FUTURE (Austria) projects together amount to over 1 kt/yr, and Thyssenkrupp has successfully trialled the substitution of hydrogen for coal in one tuyere of one of its blast furnaces in Germany and is currently testing higher blending rates. ArcelorMittal (Spain) has also committed to build a DRI unit using hydrogen produced directly from renewable sources.

Aside from blending hydrogen in existing DRI and blast furnaces, high blending shares (up to 100%) in hydrogen-based DRI facilities offer an opportunity to produce steel with very limited fossil fuel use. As early as the 1990s, a 0.5 ‑Mt fully hydrogen-based plant was already operational in Trinidad and Tobago (it is no longer active). The HYBRIT project in Sweden, developed by SSAB, LKAB and Vattenfall to produce sponge iron using 100% hydrogen in combination with biomass, is working towards transitioning from a pilot to large-scale operation (~1 Mt of DRI) by 2025.

Hydrogen has long been known as a potential low-carbon transport fuel, but establishing it in the transport fuel mix has been difficult. To date, hydrogen use in the sector has been limited to less than 0.01% of energy consumed, and in 2020 fuel cell electric vehicles (FCEVs) made up a very small share of the global stock of total vehicles (<0.01%) and of electric vehicles (0.3%). However, the FCEV market is beginning to take off, catalysed by developments in Asia and the United States.

More than 40 000 FCEVs were on the road globally by the end of June 2021. Stocks grew an average 70% annually from 2017 to 2020, but in 2020 stock growth fell to only 40% and new fuel cell car registrations decreased 15%, mirroring the contraction of the car market overall due to the Covid-19 pandemic. However, 2021 is expected to be a new record year, with more than 8 000 FCEVs sold in the first half of 2021, and record-high monthly sales recorded in California (759 in March) and Korea (1 265 in April).

Since the IEA began tracking FCEV stock in 2017 the United States had been the largest stockholder, but Korea took over this top spot in 2020 thanks to its aggressive policies for FCEV adoption -- subsidies of up to USD 30 000 were offered with the combined support of national and local governments.

Fuel cell electric vehicle stock by segment, 2017-2020

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Fuel cell electric vehicle stock by region, 2017-2020

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Global FCEV deployment has been concentrated largely on passenger light-duty vehicles, which accounted for three-quarters of FCEV stock at the end of 2020, with buses making up ~15% and commercial vehicles meeting the remaining 10%. There are, however, some notable differences in the geographical distribution of the various types of FCEVs. As Korea, the United States and Japan have focused their efforts on deploying passenger cars, they hold 90% of the stock in this segment but have a very small number of buses and commercial vehicles. Meanwhile, China adopted policies for fuel cell bus and commercial vehicle uptake, and now dominates global stocks in these segments (93% of buses and 99% of commercial vehicles in 2020).

This trend is likely to continue, as the new Chinese fuel cell vehicle subsidy policy adopted in 2020 aims to enhance the manufacturing capacities of China’s FCEV industry and focuses on using fuel cells in medium- and heavy-duty commercial vehicles.

In Europe, numerous announcements in 2020 signal stronger efforts to deploy fuel cell buses and trucks. Several manufacturers and projects aim to deploy thousands of buses in the next decade. Hyundai has already delivered 46 heavy-duty trucks to Switzerland as of July 2021 and plans to deploy 1 600 vehicles in the country by 2025, while the Port of Rotterdam and Air Liquide have created an initiative to deploy 1 000 fuel cell trucks by 2025 and a joint call signed by over 60 industrial partners aims for up to 100 000 trucks by 2030. Based on current and announced capacity, the IEA estimates that fuel cell manufacturing could enable a stock of 6 million FCEVs by 2030, satisfying around 40% of Net Zero Emissions by 2050 Scenario needs.

Fuel cell vehicle deployment should be accompanied by the simultaneous establishment of enabling infrastructure. At the end of 2020, more than 540 hydrogen refuelling stations were in operation worldwide, an increase of more than 15% from 2019. Japan remained the leader with close to 140 stations, followed by Germany (90) and China (85). The number of stations in operation expanded considerably in Japan (+24), China (+24) and Korea (+18), whereas Germany added only 9 new stations in 2020 and did not reach the NOW target of 100 by 2020.

In non-road vehicles, new applications are gaining popularity. In rail, Alstom has led the way in Europe, completing a successful 18-month trial of two trains in Germany in 2020, followed by further tests in the Netherlands, Austria and Italy. This has resulted in orders for at least 41 units in Germany and 6 in Italy that will be put into service between 2021 and 2022, with the first being delivered in March 2021.

Other European companies in France, Germany, Spain and the United Kingdom have started working with Alstom or are developing and testing their own fuel cell train models, with the objective of replacing diesel trains on non-electrified routes. Outside Europe, countries such as China, Korea, Japan, Canada and the United States are also showing interest in hydrogen fuel cell trains.

In addition to passenger trains, hydrogen trams and line-haul and switching locomotives are in various stages of development and deployment. Hydrogen trains are mainly expected to replace diesel lines that are expensive to electrify due to relatively low utilisation, constituting 2% of rail energy consumption by 2030 in the Net Zero Emissions by 2050 Scenario.

In the maritime subsector, the International Maritime Organization is targeting the decarbonisation of maritime fuels, with hydrogen and ammonia expected to become more important. Although hydrogen fuel cells have been demonstrated on several coastal and short-distance vessels since the early 2000s, none are yet commercially available. However the commercial operation of fuel cell ferries is expected to begin in 2021 in the United States and Norway.

Hydrogen-based fuels, particularly ammonia, are also attracting attention for use in large oceangoing vessels. Major industry stakeholders have announced plans to make 100% ammonia-fuelled maritime engines available as early as 2023 and to offer ammonia retrofit packages for existing vessels from 2025. In the Net Zero Emissions by 2050 Scenario, ammonia meets 8% of total shipping fuel demand and hydrogen meets 2%.

Finally, interest in hydrogen for aviation applications has been reawakened after many years of being ignored due to technical challenges. In 2020, Airbus took the first major step in this direction, releasing an ambitious plan for developing novel hydrogen aircraft concepts for up to 200 passengers and a 3 700-km range, with the goal of having a commercial aircraft available by 2035. In addition, Boeing recently partnered with Australia’s Commonwealth Scientific and Industrial Research Organisation to publish a roadmap for hydrogen in the aviation industry that considers opportunities for hydrogen use in aircrafts and airport applications.

Smaller companies, such as ZeroAvia and Universal Hydrogen, are also working on hydrogen aircraft solutions for short-distance flights. While the direct use of hydrogen in commercial aviation is not expected to be commercially viable until the mid-2030s or later, using hydrogen-based synthetic kerosene as a drop-in fuel with existing aircraft could make inroads by 2030. In fact, KLM carried out the first flight using synthetic kerosene in the Netherlands in February 2021. In the Net Zero Emissions by 2050 Scenario, synthetic kerosene meets more than 1.6% of aviation fuel demand in 2030.

Hydrogen has only a negligible presence in the power sector today, accounting for less than 0.2% of electricity generation globally. This is linked mostly to the use of hydrogen-containing mixed gases from the steel industry, petrochemical plants and refineries. In addition, more than 2 100 MW of stationary fuel cells had been installed by the end of 2020, although practically all of them run on natural gas.

Very few countries have stated explicit targets for using hydrogen or hydrogen-based fuels in the power sector. Japan is one of the few exceptions: it aims to reach 1 GW of power capacity based on hydrogen by 2030, corresponding to annual hydrogen consumption of 0.3 Mt, rising to 1 5‑30 GW (5‑10 Mt) in the longer term. In its hydrogen roadmap, Korea has set a target of 1.5 GW of installed fuel cell capacity in the power sector by 2022, and 15 GW by 2040. A number of countries have, however, recognised hydrogen’s potential as a low-carbon option for power and heat generation, e.g. to provide flexibility in energy systems with high shares of variable renewable energy.

Today, reciprocating gas engines can handle gases with a hydrogen content of up to 70% (on a volumetric basis), while testing of engines running on pure hydrogen has been successfully completed. Gas turbine suppliers already have significant experience combusting hydrogen-containing fuels, with some smaller units operating on >90% shares of hydrogen in refineries and for chemical and petrochemical applications. R&D activities are in progress to develop dry low NOx (DLN) gas turbines that are able to handle 0-100% fixed hydrogen blended with natural gas. Successful verification of 100% hydrogen-fuelled DLN combustion technology was recently achieved in Japan at 1‑MWe scale.

By 2030, thermal power plants using low-carbon fuels could be an important dispatchable resource to cover peak demand periods when the value of electricity is high and to provide a range of system services to ensure energy security and capacity adequacy, avoiding costly energy supply disruptions. In the Net Zero Emissions by 2050 Scenario, demand for hydrogen and hydrogen-based fuels in electricity generation reaches 17 Mt H2-eq by 2025 and 51 Mt H2-eq by 2030. While electricity generation capacity linked to hydrogen-based fuels is currently very limited, it reaches 140 GW by 2030 in this scenario.

Global power sector demand for hydrogen and hydrogen-based fuels in the Net Zero Scenario

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Close to 80% of hydrogen is currently produced through emissions-intensive natural gas reforming and coal gasification, with almost all the remainder being by-product hydrogen produced in facilities designed for other products – mainly refineries in which the reformation of naphtha into gasoline produces some hydrogen as a by-product. Using hydrogen produced from unabated fossil fuels as an alternative to the fossil fuels themselves offers very limited environmental benefits, and can even lead to higher global emissions in most applications.

For this reason, for hydrogen to contribute significantly to the clean energy transition, it is critical to develop low-carbon hydrogen production routes that can replace current production and at the same time expand production capacity to meet new demands. The two main low-carbon production routes use fossil fuels coupled with CCUS1 or water electrolysis.

Coupling conventional technologies with CCUS is still the main low-carbon hydrogen production method and will likely remain so in the short to medium term because production costs are lower than for other low-carbon technologies such as water electrolysis. CCUS is attractive because it can reduce emissions from existing production capacity quickly through retrofits and can enable large-scale dispatchable hydrogen production.

Nevertheless, it restricts the extent to which carbon emissions can be reduced, since high capture rates have associated economic penalties. Moreover, it is impossible to eliminate 100% of the CO2 emissions generated in the process, as the best technologies available (still to be demonstrated at scale) are limited to up to 97-98% emissions reductions. In addition, upstream emissions also impact the lifecycle footprint of hydrogen produced from fossil fuels and CCUS.

Interest in projects that combine conventional technologies with CCUS is growing. In 2020, two new projects for producing hydrogen from fossil fuels with CCUS became operational, both in Canada (at the North West Sturgeon refinery and at a Nutrien Fertiliser Plant). This has elevated the number of projects operating around the world to 16 (four of which produce hydrogen from fossil fuels with CCU). Together, these projects have a total production capacity of just over 0.7 Mt of low-carbon hydrogen.

In addition, close to 60 projects around the world are planned or in development, and four of them (two in China and two in the United States) are under construction and expected to be operational within the next couple of years. These projects could boost annual CCUS-equipped fossil fuel hydrogen production capacity close to 1 Mt. If all projects currently in the pipeline are realised, 8.0-8.7 Mt of low-carbon hydrogen could be produced using fossil fuels with CCUS by 2030, compared with the 58 Mt modelled in the Net Zero Emissions by 2050 Scenario.

Recently, methane pyrolysis has emerged as a potential alternative to methane reforming with CCUS. This technology produces hydrogen from natural gas and generates a solid carbon as the only by-product, which facilitates separation and collection of the fossil fuel’s carbon component after the process. This technology has yet to be demonstrated at scale (it is at technology readiness level 6) and still requires innovation to solve technical problems such as the reactor clogging from carbon deposits and to reduce CO2 emissions from generation of the thermal energy required for the process. However, a large-scale Monolith Materials project in the United States (in its first phase and expected to be operational at the end of 2021) will produce hydrogen and, if successfully demonstrated, expand to produce ammonia.

Electrolysis, which produces hydrogen from electricity and water, has the potential to generate carbon-free hydrogen if renewable or nuclear electricity is used, but the process can also result in very high emissions if the electricity source is of high carbon intensity. An electrolyser operating at the average grid intensity of France (50-70 gCO2/kWh according to the European Environmental Agency) produces hydrogen with a carbon footprint of 2.6-3.6 gCO2/gH2, equivalent to a natural gas reformer with a carbon capture rate of 60-70%. However, an electrolyser using electricity at the global average carbon intensity (475 gCO2/kWh according to the IEA) would produce hydrogen with a carbon footprint nearly three times higher than that of an unabated natural gas reformer.

Electrolysers are a relatively mature technology that has been long used in certain industrial processes, such as the production of chlorine in the chlor-alkali process (in which hydrogen is produced as a by-product). However, its use for dedicated hydrogen production has not yet been widely adopted. Current dedicated production of hydrogen from electrolysis is 30 kt per year, accounting for ~0.03% of all hydrogen produced. The level is low because the production cost of electrolytic hydrogen (USD 3-8/kg H2) is high compared with from unabated fossil fuels (USD 0.5-1.7/kg H2). Closing this gap will require a drop in electrolyser costs and ­­– more importantly – in the price of low-carbon electricity, as well as an increase in load factors.

Electrolysers have reached enough maturity to scale up manufacturing and deployment to significantly reduce costs, which is reflected in three consecutive years of record capacity deployment in 2018, 2019 and 2020. Despite the impact of the Covid‑19 pandemic, which has delayed a significant number of projects, close to 70 MW of electrolysis became operational in 2020, bringing total installed capacity to almost 300 MW. Europe has 40% of global installed capacity and will remain the dominant region thanks to the stimulus of policy support from numerous hydrogen strategies adopted in the last year and the prominence of electrolytic hydrogen in the Covid‑19 recovery packages of countries such as Germany, France and Spain.

Furthermore, project size has increased significantly: most projects in the early 2010s were at the kilowatt scale, while the largest in 2017-2019 were 6 MW and a significant number fell into the 1 MW to 5 MW range. In this sense, 2020 has also been a record year because the world’s second and third largest electrolyser projects became operational (the largest project is the 25-MW Industrial Cachimayo plant in Peru). In March, a 10‑MW single-stack alkaline electrolyser entered into operations in Japan (powered by solar PV), and in December a 20‑MW multi-stack PEM electrolyser in Canada (powered by hydropower) finished testing and started operating in January 2021. In addition, there were significantly more announcements for projects in the order of hundreds of megawatts in 2020, some of which have reached the final investment decision phase and are expected to begin operating in the early 2020s (see the IEA Hydrogen Projects Database).

Electrolysis capacity deployment is expected to accelerate in upcoming years thanks to the high number of projects currently under development, which could break the barrier of 1 GW (equivalent to ~170 kt of hydrogen) already in 2022. With all the projects currently in the pipeline, total installed electrolysis capacity could reach 5 4‑91 GW by 2030, with electrolytic hydrogen production ranging from 4.9 Mt to 8.3 Mt. Although encouraging, this rate of growth still falls far short of Net Zero Emissions by 2050 Scenario projections of 850 GW of installed electrolysis capacity and 80 Mt of electrolytic hydrogen by 2030.

Global installed electrolysis capacity by technology, 2015-2020

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Global installed electrolysis capacity by region , 2015-2020

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There are various electrolyser designs. Alkaline and polymer electrolyte membrance (PEM) electrolysers are already commercial, whereas solid oxide electrolyser cells (SOECs) are at the precommercial stage and anion exchange membranes (AEMs) are at very early stages of development (technology readiness level 4).

Alkaline electrolysers, the most mature electrolysis technology, have traditionally dominated the market because they have been widely deployed in the chlor-alkali industry. For the dedicated production of hydrogen, however, many new projects are now opting for PEM designs, so their deployment in the past three years has surpassed that of alkaline electrolysers.

Nevertheless, it is unclear which design will dominate the market as the technology scales up. Although alkaline technology has the advantages of maturity and lower cost, the price of PEM electrolysers is also falling rapidly, and they have a smaller footprint and can deliver hydrogen at high pressure (30‑60 bar, compared with 1-30 bar for alkaline). In addition, PEM electrolysers could benefits for spillover technological learning benefits from the development of PEM fuel cells.

Projects involving high-efficiency SOECs are also appearing, some aiming to scale up to 20 MW in the short term. Practically all these projects are in Europe and focus on producing synthetic hydrocarbons, encouraged by the potential adoption of quotas for synthetic fuels in aviation announced by the European Commission and the governments of Germany and the Netherlands. The production of synthetic fuels is an interesting niche market for SOECs, since heat released in the synthesis reaction could be used in the SOEC electrolyser, which operates at high temperatures, avoiding the need for an external heat source.

Large-scale hydrogen deployment will need to be underpinned by an effective and cost-efficient system for storage and transport, strategically designed to connect supply sources to demand centres and thereby establish a deep,highly liquid market.

Of the 5 000 km of hydrogen pipelines currently operational, more than 90% are located in Europe and the United States. Most are closed systems owned by large merchant hydrogen producers concentrated near industrial consumers (mainly refineries and chemical plants). The first steps to expand this hydrogen-specific infrastructure for delivery to end users (additional to industrial users) have already been taken. Most developments have involved repurposing natural gas pipelines, which can significantly reduce the cost of establishing national and regional hydrogen networks.

The first natural gas pipeline was converted and put into commercial service by Gasunie in the Netherlands in November 2018, with a length of 12 km and throughput capacity of 4 kt/yr. This prompted a consortium of gas grid operators in Europe to propose a European Hydrogen Backbone (EHB) initiative in 2020 (updated in 2021) that envisions 39 700 km of pipelines across 21 countries by 2040 – 69% being repurposed natural gas networks and 31% newly built hydrogen pipelines.

Nonetheless, attaining hydrogen strategy targets will necessitate much faster hydrogen transmission development. IEA Net Zero Emissions by 2050 Scenario analysis shows that by 2030, the total length of hydrogen pipelines globally will need to quadruple to >20 000 km.

Tapping into hydrogen’s full potential as a clean energy vector will also require the establishment of hydrogen storage infrastructure. It is difficult to estimate future hydrogen storage needs, but current natural gas usage and storage can be a good proxy. In 2020, global gas storage totalled more than 400 bcm (10% of total consumption), so assuming a similar storage-to-consumption ratio, hydrogen storage requirements in the Net Zero Emissions by 2050 Scenario could amount to ~50 Mt by 2050.

Storing hydrogen in underground salt caverns is a proven technology that has been used by the petrochemical industry since the early 1970s. Today, four hydrogen salt caverns sites are operational: three in the United States and one in the United Kingdom. Several pilot projects are under development in Europe, expected to become operational in the next two to three years, whereas the proposed large-scale Advanced Clean Energy Storage facility in the United States (Utah) is targeting startup in the mid-2020s.

Significant progress in demonstrating international hydrogen trade was made in 2020. The Advanced Hydrogen Energy Chain Association for Technology Development successfully demonstrated the first shipment of a liquid organic hydrogen carrier from Brunei to Japan, for its use as fuel for electricity generation. Meanwhile, Saudi Aramco and the Institute of Energy and Economy, Japan, collaborated to import 40 tonnes of ammonia produced from fossil fuels with CCUS into Japan, also for electricity generation. The first shipment of liquefied hydrogen from Australia to Japan, originally planned for 2021, was postponed due to the Covid-19 pandemic and it is expected to take place before March 2022.

Around 60 international hydrogen trade projects have been announced, with most announcements taking place in 2020 and the first half of 2021. If all these projects are realised, energy traded in the form of hydrogen-based fuels would amount to ~0.3 EJ by 2030, an order of magnitude lower than the more than 2 EJ traded in the Net Zero Emissions by 2050 Scenario.

Political momentum for hydrogen use continued to gather strength in 2020 and 2021. This is fundamental for the advancement of hydrogen technologies and markets, since climate change ambitions remain the main impetus for widespread low-carbon hydrogen use.

In 2020, ten governments adopted hydrogen strategies: Canada, Chile, France, Germany, the Netherlands, Norway, Portugal, Russia, Spain and the European Union (France had already adopted a Plan for Deploying Hydrogen for the Energy Transition in 2018). As of September 2021, four more strategies had been adopted (by the Czech Republic, Colombia, Hungary and the United Kingdom) and Norway released a roadmap to complete its strategy adopted in 2020. In addition, Poland and Italy have released strategies for public consultation and more than 20 other countries have announced they are actively developing theirs.

Annual announcements of government hydrogen strategies, 2018-September 2021

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Many strategies include targets for adopting hydrogen technologies, with most focusing on the deployment of low-carbon hydrogen production and only a few emphasising hydrogen end uses to stimulate demand (mainly in transport). Strategic action is therefore needed to avoid hydrogen adoption bottlenecks that can result in ineffective policy support.

If the use of hydrogen (and hydrogen-derived fuels) is not promoted for new applications (such as long-distance transport, shipping, aviation and new industrial applications), the deployment of low-carbon hydrogen production capacity may not be realised. In this situation, project developers will struggle to secure off-takers, which could render projects economically unviable.

Today, using low-carbon hydrogen is more costly than employing hydrogen produced from unabated fossil fuels in traditional applications or using fossil fuels directly for new applications in which hydrogen could replace them. In some countries, carbon prices are being imposed to close this gap and facilitate the adoption of low-carbon hydrogen, but this is not enough to drive the Net Zero Emissions by 2050 Scenario transformation.

Fortunately, governments are beginning to announce policies such as carbon contracts for difference, auctions, mandates, quotas and hydrogen requirements in public procurement with the aim of stimulating demand and de-risking investment, although most of these announcements have not yet been turned into action.

Selected examples of announced policies to stimulate hydrogen demand

Government Policy type Description Status
California Mandate A state government-issued executive order mandates that all vehicles sold in the state be zero-emissions by 2035. In force
China Financial rewards The FCEV pilot programme rewards clusters of cities that deploy more than 1 000 FCEVs that meet certain technical standards, achieve a maximum delivered hydrogen price of CNY 35/kg (~USD 5/kg) and establish at least 15 operational HRSs. In force
Germany Auctions The government’s H2 Global programme will tender ten-year purchase agreements on hydrogen-based products, providing investor certainty on project bankability. In force
Norway Public procurement requirement The government has announced that the country’s largest ferry connection will be hydrogen-fuelled. In force
Switzerland Tax The country adopted the LSVA road tax, which levies trucks weighing more than 3.5 tonnes but waives fees for ZEVs. In force
European Union Quota As part of Fit for 55, the European Commission has proposed a Renewable Energy Directive modification to mandate 50% renewable hydrogen consumption in industry by 2030. Proposed
European Union Quota In the ReFuel Aviation Initiative, the European Commission proposed a rising quota for synthetic aviation fuels (from a 0.7% share in 2030 to 28% in 2050). Proposed
Germany Carbon contracts for difference The National Hydrogen Strategy announced a new Carbon Contracts for Difference (CCfD) pilot programme for the steel and chemical industries. It will pay the difference between a project’s CO2 abatement costs and the CO2 price in the EU ETS. If the EU ETS price is higher than the project’s CO2 abatement costs, companies will have to repay the government the difference. Proposed
India Quota The government announced that, from 2023/24, 10% of refinery hydrogen demand (increasing to 25% in the following five years) and 5% of hydrogen demand for fertiliser production (increasing to 20% in the following five years) should be met with renewable hydrogen. Proposed
Portugal Quota The National Hydrogen Strategy targets blending 10-15 vol% of hydrogen in natural gas by 2030. Proposed

Source: IEA Global Hydrogen Review 2021.

Adopting hydrogen as a clean fuel is expected to stimulate the development of new markets and value chains, which will require that regulatory frameworks be adapted and certification schemes and standards be defined to reduce barriers for stakeholders. In the area of regulation, some governments took the first steps to adapt their regulatory frameworks in 2020 (China and Korea) and 2021 (Chile, Colombia and France).

There has also been significant progress in defining standards, particularly for a methodology to calculate the carbon footprint of hydrogen production. This has been widely recognised as a critical priority for the development of hydrogen markets, as it ensures that hydrogen production is truly low-carbon. In October 2021, the IPHE released a working paper, prepared by its Hydrogen Production Analysis Task Force, with a methodology to determine GHG emissions associated with different hydrogen production pathways. In addition, some countries (e.g. Australia, France and the United Kingdom) have begun to develop certification schemes for hydrogen’s carbon footprint.

National hydrogen strategies and roadmaps with concrete targets for deploying low-carbon production, and particularly for stimulating demand, are critical to build stakeholder confidence in the potential for a low-carbon hydrogen market. This is a vital first step, as it can create momentum and trigger more investments to scale up and accelerate deployment.

To tap into hydrogen’s full potential as a clean energy vector, measures are needed to facilitate the adoption of low-carbon hydrogen to replace unabated fossil-based alternatives.

Policies should aim to close the price gap between the cost of using low-carbon hydrogen and the use of unabated fossil-based hydrogen or the use of fossil fuels themselves in areas where hydrogen could eventually replace them. Some countries are already using carbon pricing to close this cost gap, but it is not effective enough. Wider adoption, combined with other policy instruments such as auctions, mandates, quotas and hydrogen requirements in public procurement, can help de-risk investment and make low-carbon hydrogen more economically feasible.

A policy framework that stimulates demand can, in turn, prompt investment in low-carbon production plants, infrastructure and manufacturing capacity. However, without stronger policy action, this process will not happen at the pace necessary to meet climate goals. Providing tailor-made support to selected shovel-ready flagship projects can kick-start the scaling up of low-carbon hydrogen and the development of infrastructure to connect supply sources to demand centres and manufacturing capacities, from which later projects can benefit.

Continuous innovation is essential to reduce costs and increase the competitiveness of hydrogen technologies. Unlocking the full potential demand for hydrogen will require strong demonstration efforts over the next decade. Larger R&D budgets and support for demonstration projects are urgently needed to ensure that key hydrogen technologies reach the commercialisation phase as soon as possible.

As hydrogen adoption spawns new value chains, current regulatory frameworks will have to be adapted and new standards and certification schemes be defined to remove remaining barriers. An international agreement on a methodology to calculate the carbon footprint of hydrogen production will be particularly important to ensure that hydrogen production is truly low-carbon and will also be fundamental to develop a global hydrogen market.

Resources
Notes and references
  1. In this report, CCUS includes CO2 captured for use (CCU) as well as for storage (CCS), including CO2 that is both used and stored (e.g. for EOR or for building materials) if some or all of the CO2 is permanently stored. When use of the CO2 ultimately leads to it being re-emitted to the atmosphere (e.g. urea production), CCU is specified.

Analysis