Global Hydrogen
Review 2023

INTERNATIONAL ENERGYAGENCYThe IEA examines thefull spectrumof energy issues
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electricity markets,energy efficiency,
access to energy,
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management andmuch more. Throughits work, the IEA
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city or area.

Revised version, September andDecember 2023
Information notice found at:
www.iea.org/corrections

Source: IEA.
International Energy Agency
Website: www.iea.org

IEA member
countries:

IEA association
countries:

Australia
Austria
Belgium
CanadaCzech Republic
Denmark
Estonia
FinlandFranceGermany
GreeceHungary
Ireland
Italy
Japan
Korea
Lithuania
Luxembourg
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The European
Commission also
participates in thework of the IEAGlobal Hydrogen Review 2023

Abstract

Abstract
The Global Hydrogen Review is an annual publication by the International Energy
Agency that tracks hydrogen production and demand worldwide, as well as
progress in critical areas such as infrastructure development, trade, policy,
regulation, investments and innovation.
The report is an output of the Clean Energy Ministerial Hydrogen Initiative and isintended to inform energy sector stakeholders on the status and future prospectsof hydrogen, while also informing discussions at the Hydrogen Energy Ministerial
Meeting organised by Japan. Focusing on hydrogen’s potentially major role inmeeting international energy and climate goals, the Review aims to help decision
makers fine-tune strategies to attract investment and facilitate deployment ofhydrogen technologies at the same time as creating demand for hydrogen andhydrogen-based fuels. It compares real-world developments with the statedambitions of government and industry.

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This year’s report includes a focus on demand creation for low-emission hydrogen.
Global hydrogen use is increasing, but demand remains so far concentrated in
traditional uses in refining and the chemical industry and mostly met by hydrogenproduced from unabated fossil fuels. To meet climate ambitions, there is an urgent
need to switch hydrogen use in existing applications to low-emission hydrogenand to expand use to new applications in heavy industry or long-distancetransport.

Global Hydrogen Review 2023

Acknowledgements, contributors and credits

Acknowledgements, contributors
and credits
The Global Hydrogen Review was prepared by the Energy Technology Policy(ETP) Division of the Directorate of Sustainability, Technology and Outlooks(STO) of the International Energy Agency (IEA). The study was designed anddirected by Timur Gül, Chief Energy Technology Officer and Head of the Energy
Technology Policy Division. Uwe Remme (Head of the Hydrogen and Alternative
Fuels Unit) and Jose Miguel Bermudez Menendez co-ordinated the analysis andproduction of the report. Laura Cozzi, Dennis Hesseling, Paolo Frankl, Tim Gould,
Keisuke Sadamori, Hiro Sakaguchi, and Araceli Fernandez Pales provided
valuable, strategic guidance during the report’s development process.
The principal IEA authors and contributors were (in alphabetical order): Praveen
Bains (hydrogen-based fuels), Simon Bennett (investment), Leonardo Collina(industry), Elizabeth Connelly (transport), Chiara Delmastro (buildings), Stavroula
Evangelopoulou (production and data management), Mathilde Fajardy (CCUS),
Alexandre Gouy (industry), Megumi Kotani (policy), Jean-Baptiste Le Marois(innovation), Peter Levi (industry), Rafael Martinez Gordon (buildings), Shane
McDonagh (transport), Francesco Pavan (production, trade and infrastructure),
Amalia Pizarro (trade, infrastructure and innovation), Noah Sloots (buildings) andChristoph Winkler (production).
The development of this report benefitted from contributions provided by thefollowing IEA colleagues: Ana Alcalde Bascones, Carl Greenfield, Ilkka Hannula,
Luca Lo Re, Jennifer Ortiz, and Nikoo Tajdolat. Lizzie Sayer edited the manuscript
while Liselott Fredriksson, Anna Kalista and Per-Anders Widell provided essential
support throughout the process.
Thanks also to the IEA Communications and Digital Office for their help in
producing the report, particularly to Curtis Brainard, Poeli Bojorquez, Jon Custer,Astrid Dumond, Merve Erdil, Grace Gordon, Jethro Mullen, Isabelle NonainSemelin, Julie Puech, Lucile Wall, Therese Walsh and Wonjik Yang.

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The work could not have been achieved without the financial support provided by
the Governments of Australia, Canada, Germany, and Japan. The following
governments have also contributed to the report through their voluntary
contribution to the CEM Hydrogen Initiative: Australia, Austria, Canada, Finland,
Germany, the European Commission, the Netherlands, Norway, the United
Kingdom and the United States.

Global Hydrogen Review 2023

Acknowledgements, contributors and credits

Special thanks go to the following organisations and initiatives for their valuable
contributions: Advanced Fuel Cells Technology Collaboration Programme (TCP),
European Patent Office, Hydrogen Council, Hydrogen TCP and the International
Partnership for Hydrogen and Fuel Cells in the Economy (IPHE).

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Peer reviewers provided essential feedback to improve the quality of the report.
They include: Nawal Al-Hanaee (Ministry of Energy and Infrastructure, United
Arab Emirates); Abdul'Aziz Aliyu (GHG TCP); Laurent Antoni and Noé van Hulst(IPHE); Florian Ausfelder (Dechema); Ruta Baltause, Tudor Constantinescu,
Ruud Kempener, Eirik V. W. Lønning and Matthijs Soede (European
Commission); Frederic Bauer (Lund University); Prerna Bhargava (Department of
Climate Change, Energy, the Environment and Water, Australia); Herib Blanco;
Joß Bracker (Federal Ministry for Economic Affairs and Climate Action, Germany);
Paula Brunetto (Enel); James Collins (ITM Power); Harriet Culver, Katherine
Davis, Lara Hirschhausen and Oliviero Iurkovich (Department for Energy Security
and Net Zero, United Kingdom); Caroline Czach, Isabel Murray and Claudie Roy(Natural Resources Canada); Lucie Ducloue (Air Liquide); Alexandru Floristean(Hy24); Daniel Fraile (Hydrogen Europe); Marta Gandiglio (Politecnico di Torino);
Dolf Gielen (World Bank); Celine Le Goazigo (WBCSD); Stefan Gossens(Schaeffler AG); Emile Herben (Yara); Marina Holgado (Hydrogen TCP); Marius
Hörnschemeyer (DENA); Ruben Hortensius, Sanne van Santen and Anouk
Zandbergen (Ministry of Economic Affairs and Climate Policy, the Netherlands);
Shunsuke Inui and Wataru Kaneko (Ministry of Economy, Trade and Industry,
Japan); Leandro Janke (Agora Energiewende); Adam Karl (AECOM); Ilhan Kim(Ministry of Trade, Industry and Energy, Korea); Marcos Kulka (Chile Hydrogen
Association); Subhash Kumar (ACME); Leif Christian Kröger (thyssenkrupp
nucera); Martin Lambert (Oxford Institute for Energy Studies); Wilco van der Lans
(Port of Rotterdam Authority); Kirsten McNeill (Sunfire); Jonas Moberg (Green
Hydrogen Organisation); Susana Moreira (H2Global); Pietro Moretto (JRC);
Motohiko Nishimura, Taku Hasegawa, Aya Saito and Tomoki Tominaga(Kawasaki Heavy Industries, Ltd.); Daria Nochevnik (Hydrogen Council); Maria
Teresa Nonay Domingo (Enagás); Koichi Numata (Toyota); Cédric Philibert(Independent consultant); Mark Pickup (Ministry of Business, Innovation &Employment, New Zealand); Nicolas Pocard (Ballard); Joris Proost (UCLouvain
Belgium); Andrew Purvis (World Steel Association); Noma Qase (Department ofMineral Resources, South Africa); Agustín Rodriguez (Topsoe); Xavier Rousseau(Snam); Sunita Satyapal and Neha Rustagi (Department of Energy, UnitedStates); Julian Schorpp (Thyssenkrupp Steel Europe); Ángel Landa Ugarte(Iberdrola); Derek Wissmiller (GTI Energy); and Marcel Weeda (TNO).

Global Hydrogen Review 2023

Table of contents

Table of contents
Executive summary ................................................................................................................ 11
Recommendations ................................................................................................................ 15
Chapter 1. Introduction .......................................................................................................... 18
Overview ............................................................................................................................... 18
The Hydrogen Initiative ......................................................................................................... 19
Chapter 2. Hydrogen use ....................................................................................................... 20
Overview and outlook ........................................................................................................... 20
Refining ................................................................................................................................. 22
Industry.................................................................................................................................. 25
Transport ............................................................................................................................... 29
Buildings ................................................................................................................................ 39
Electricity generation ............................................................................................................. 41
Creating demand for low-emission hydrogen ....................................................................... 45
Chapter 3. Hydrogen production .......................................................................................... 64
Overview and outlook ........................................................................................................... 64
Electrolysis ............................................................................................................................ 68
Fossil fuels with CCUS ......................................................................................................... 77
Comparison of different production routes ........................................................................... 80
Emerging production routes .................................................................................................. 91
Production of hydrogen-based fuels and feedstocks ........................................................... 95
Chapter 4. Trade and infrastructure ..................................................................................... 99
Status and outlook of hydrogen trade ................................................................................... 99
Status and outlook of hydrogen infrastructure .................................................................... 109
Chapter 5. Investment, finance and innovation ................................................................ 129
Investments in the hydrogen sector .................................................................................... 129
Innovation in hydrogen technologies .................................................................................. 140
Chapter 6. Policies ............................................................................................................... 148
Strategies and targets ......................................................................................................... 148
Demand creation ................................................................................................................. 150
Mitigating investment risks .................................................................................................. 152
Promotion of RD&D and knowledge-sharing ...................................................................... 159

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Standards, certification and regulations ............................................................................. 163

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Table of contents

Annex ..................................................................................................................................... 169
Explanatory notes ............................................................................................................... 169
Abbreviations and acronyms............................................................................................... 171

Figure ES.1

Map of announced low-emission hydrogen production projects .............................. 11
Hydrogen use by sector and by region, historical and in the Net Zero Emissions by
2050 Scenario, 2020-2030 ....................................................................................... 20
Hydrogen use by region and source of hydrogen for refining, historical and in the
Net Zero Emissions by 2050 Scenario, 2019-2030 ................................................. 23
Onsite production of low-emission hydrogen for refining by technology, region andstatus, historical and from announced projects, 2020-2030 .................................... 25
Hydrogen use in industry by subsector and by region and source of hydrogen,historical and in the Net Zero Emissions by 2050 Scenario, 2019-2030 ................. 26
Onsite production of low-emission hydrogen for industry applications by technology
and status, historical and from announced projects, 2020-2030 ............................. 28
Hydrogen consumption in road transport by vehicle segment and region, 2020-2022.................................................................................................................................. 30
Fuel cell electric vehicle stock by segment and region, 2019-2023 ......................... 31
Hydrogen refuelling stations by region and ratio of fuel cell electric vehicles torefuelling stations, 2019-June 2023 ......................................................................... 34
Mobile fuel cell manufacturing capacity by country/region according to announced
projects and in the Net Zero Emissions by 2050 Scenario, 2022-2030 ................... 36
Fuel cell stock by region, 2021-2022, and hydrogen use in buildings in the Net Zero
Emissions by 2050 Scenario, 2021-2050................................................................. 40
Capacity in power generation using hydrogen and ammonia by region, historical andfrom announced projects, 2019-2030 ...................................................................... 42
Potential demand for low-emission hydrogen created by implemented policies andgovernment targets, and production targeted by governments, 2030 ..................... 51
Potential demand for low-emission hydrogen that can be achieved with announced
private off-take agreements by 2030 ........................................................................ 54
Potential demand for low-emission hydrogen that can be achieved with thecommitments of international initiatives, 2030 ......................................................... 58
Potential demand for low-emission hydrogen from announced policies and targets,
private off-take agreements, commitments of international co-operation initiatives
and the Net Zero Emissions by 2050 Scenario, 2030 .............................................. 60
Domestic production cost of ammonia in Europe considering different shares ofrenewable hydrogen compared with the cost of delivered ammonia from the Middle
East .......................................................................................................................... 61

Figure 3.1
Figure 3.2

Hydrogen production by technology, 2020-2022 ..................................................... 64
Low-emission hydrogen production by technology route, maturity and region basedon announced projects and in the Net Zero Emissions by 2050 Scenario, 2030 .... 66
Low-emission hydrogen production by status and by sector based on announced
projects, 2030 ........................................................................................................... 67
Map of announced low-emission hydrogen production projects .............................. 68
Global electrolyser capacity by technology, 2019 – 2023, and by region, size andstatus based on announced projects by 2030 ......................................................... 69
Electrolyser capacity in 2030 based on current announcements by status, andprogress since the Global Hydrogen Review 2022 .................................................. 70

Figure 3.3
Figure 3.4
Figure 3.5
Figure 3.6

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List of figures

Global Hydrogen Review 2023

Figure 3.8
Figure 3.9
Figure 3.10
Figure 3.11
Figure 3.12
Figure 3.13
Figure 3.14
Figure 3.15
Figure 3.16
Figure 3.17
Figure 4.1
Figure 4.2
Figure 4.3
Figure 4.4
Figure 4.5
Figure 4.6
Figure 4.7
Figure 4.8
Figure 4.9

Figure 5.1.
Figure 5.2.
Figure 5.3.
Figure 5.4.

Electrolyser manufacturing capacity by region and technology according toannounced projects and in the Net Zero Emissions by 2050 Scenario, 2021-2030 72
Global electrolyser capacity from announced projects, and cumulative output fromannounced manufacturing capacity compared to the Net Zero Emissions by 2050
Scenario, 2025-2030 ................................................................................................ 73
Evolution of electrolyser installed capital costs based on deployment fromannounced projects and in the Net Zero Emissions by 2050 Scenario, 2021-2030,
and the share of capital cost in the levelised cost of hydrogen production .............. 75
Production of low-emission hydrogen from fossil fuels with carbon capture utilisationand storage, historical and from announced projects, 2018-2030 ........................... 78
Levelised cost of hydrogen production by technology in 2021, 2022 and in the Net
Zero Emissions by 2050 Scenario in 2030............................................................... 81
Levelised cost of hydrogen production based on different renewable electricity
prices and on different costs of capital in the Net Zero Emissions by 2050 Scenario,
2030.......................................................................................................................... 82
Hydrogen production costs and share of solar PV from hybrid solar PV and onshore
wind systems, 2030 .................................................................................................. 85
Levelised cost of hydrogen production with carbon capture, based on different
natural gas prices and on different costs of capital in the Net Zero Emissions by
2050 Scenario, 2030 ................................................................................................ 86
Comparison of the emissions intensity of different hydrogen production routes, 2021.................................................................................................................................. 89
Global hydrogen-based fuel production by fuel, region and status, historical andbased on announced projects .................................................................................. 96
Levelised costs of ammonia and synthetic kerosene for electricity-based pathways
in 2022 and in the Net Zero Emissions by 2050 Scenario in 2030 .......................... 97
Low-emission hydrogen trade by status and by carrier based on announced
projects, 2030-2040................................................................................................ 102
Low-emission hydrogen trade by exporting and importing region based on
announced projects, 2030-2040 ............................................................................. 105
Potential low-emission hydrogen trade flows based on announcements, 2030 .... 106
Low-emission hydrogen trade by importing region based on announced projects,
policy targets and in the Net Zero Emissions by 2050 Scenario, 2030 ................. 107
Global annual investment in gas infrastructure in the Net Zero Emissions by 2050
Scenario, 2016-2030 .............................................................................................. 109
Global hydrogen transmission pipeline length in the Net Zero Emissions by 2050
Scenario and announced projects, 2020-2050 ...................................................... 113
Global underground geological storage capacity for hydrogen in the Net Zero
Emissions by 2050 Scenario and announced projects, 2020-2050 ....................... 120
Existing and announced port infrastructure projects for hydrogen and hydrogenbased fuels trade .................................................................................................... 121
Emissions of hydrogen transport by pipeline and tanker depending on the distanceand the grid emission factor of the importing region .............................................. 126
Investment in electrolyser installations by region (left) and intended use (right), andNet Zero Emissions by 2050 Scenario requirements, 2019-2030 ......................... 130
Factors that could contribute to cost inflation for an electrolyser installation since2021........................................................................................................................ 135
Financial commitments to hydrogen by multilateral development banks, by sourceand partner country, by year of announcement, 2021-2023*................................. 136
Monthly returns (left) and market capitalisation (right) of hydrogen companies,hydrogen funds and relevant benchmarks, 2017-2023 .......................................... 137

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Figure 3.7

Table of contents

Global Hydrogen Review 2023

Figure 5.5.
Figure 5.6.
Figure 5.7.
Figure 5.8.
Figure 5.9.
Figure 5.10.
Figure 5.11.
Figure 6.1
Figure 6.2
Figure 6.3
Figure 6.4

Table of contents

Venture capital investment in energy start-ups in hydrogen-related areas, for earlystage and growth-stage deals, 2010-2023 ............................................................. 138
Early- and growth-stage equity investment in energy start-ups in hydrogen-relatedareas by region, 2018-2022 ................................................................................... 139
Technology readiness levels of production of low-emission hydrogen and synthetic
fuels, and infrastructure .......................................................................................... 142
Technology readiness levels of hydrogen end uses by sector .............................. 143
Patenting trends on hydrogen technologies in the main world regions, 2001-2021................................................................................................................................ 144
Patenting trends in hydrogen production by technologies, 2001-2021 .................. 145
Patenting trends in technologies that consume hydrogen, 2001-2021 .................. 146
Global targets for low-emission hydrogen production, use in industry and fuel cellelectric vehicles by 2030 ........................................................................................ 150
Number of policies to support hydrogen demand creation announced and enteringin force by sector, 2021-2023 ................................................................................. 152
Government RD&D spending for hydrogen technologies by region, 2018-2022 ... 160
Co-operation agreements between governments on hydrogen since August 2022.
................................................................................................................................ 162

List of boxes
Box 2.1
Box 2.2

Traditional and new applications for hydrogen ........................................................ 21
The role of voluntary carbon credit markets in scaling up low-emission hydrogen.. 48

Box 3.1
Box 3.2
Box 3.3
Box 3.4

Electrolysis development in China ........................................................................... 75
Can high plant capture rates be achieved?.............................................................. 78
Sizing renewable electricity for electrolytic hydrogen production............................. 83
Using emissions intensity levels for non-expert users ............................................. 90

Box 4.1
Box 4.2
Box 4.3

Domestic production versus imports – the case of north-west Europe .................. 103
Offshore hydrogen networks or power transmission to shore to deliver hydrogen?
................................................................................................................................ 115
Hydrogen leakage monitoring ................................................................................ 127

Box 5.1

Sizing the global market for low-emission hydrogen .............................................. 131

Box 6.1

Financial incentives in the Inflation Reduction Act ................................................. 153

List of tables
Examples of policies to stimulate demand for low-emission hydrogen .................... 52
Selected international initiatives for the deployment of low-emission technologies. 57
Low-emission hydrogen demand and share of sectoral hydrogen demand inrefining, ammonia production and methanol production in the Net Zero Emissions by
2050 Scenario, 2030 ................................................................................................ 62
Selected developments for natural hydrogen production......................................... 94

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Planned and completed trade pilot projects for low-emission hydrogen andhydrogen-based fuels, 2020-2023 ......................................................................... 100

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Table of contents

Progress between Q3 2022 and Q2 2023 on hydrogen transmission projects in new
and repurposed pipelines ....................................................................................... 114
Hydrogen blending projects in gas distribution pipelines entering operation between
Q3 2022 and Q2 2023 ............................................................................................ 117
Calls for interest for underground hydrogen storage projects ................................ 118
Announced designs for liquefied hydrogen tankers expected to be commercial
before 2030 ............................................................................................................ 124

Table 6.3
Table 6.4

National hydrogen roadmaps and strategies since September 2022 .................... 148
Policy measures to mitigate investment risks in hydrogen projects in force orannounced since August 2022 ............................................................................... 156
Selected government programmes which include support for hydrogen technology
demonstration projects since August 2022 ............................................................ 161
Overview of existing and planned regulatory frameworks and certification systems
for hydrogen and hydrogen-based fuels ................................................................ 165

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Table 6.1
Table 6.2

Global Hydrogen Review 2023

Executive summary

Executive summary
Low-emission hydrogen production can grow massively
by 2030 but cost challenges are hampering deployment
The number of announced projects for low-emission hydrogen production
is rapidly expanding. Annual production of low-emission hydrogen could reach
38 Mt in 2030, if all announced projects are realised, although 17 Mt come fromprojects at early stages of development. The potential production by 2030 fromannounced projects to date is 50% larger than it was at the time of the release of
the IEA’s Global Hydrogen Review 2022. Only 4% of this potential production has
at least taken a final investment decision (FID), a doubling since last year inabsolute terms (reaching nearly 2 Mt). Of the total, 27 Mt are based on electrolysis
and low-emission electricity and 10 Mt on fossil fuels with carbon capture,utilisation and storage.
Figure ES.1 Map of announced low-emission hydrogen production projects

IEA. CC BY 4.0.

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Note: Map includes also announced projects starting after 2030.
Source: IEA Hydrogen Projects database.

Global Hydrogen Review 2023

Executive summary

After a slow start, China has taken the lead on electrolyser deployment. In
2020, China accounted for less than 10% of global electrolyser capacity installed
for dedicated hydrogen production, concentrated in small demonstration projects.
In 2022, installed capacity in China grew to more than 200 MW, representing 30%
of global capacity, including the world’s largest electrolysis project (150 MW). By
the end of 2023, China’s installed electrolyser capacity is expected to reach
1.2 GW – 50% of global capacity – with another new world record-size electrolysis
project (260 MW), which started operation this year. China is poised to further
cement its leading position in electrolyser deployment: the country accounts formore than 40% of the electrolysis projects that have reached FID globally.
Equipment and financial costs are increasing, putting projects at risk andreducing the impact of government support for deployment. Inflation isincreasing capital and financial costs, threatening the bankability of projects
across the entire hydrogen value chain, which are highly capital intensive. For
hydrogen produced from renewable electricity, for example, an increase of 3
percentage points in the cost of capital could raise total project cost by nearly onethird. Several projects have revised their initial cost estimates upwards by up to
50%. Inflationary pressures have coincided with a recent fall in natural gas prices,
particularly in Europe, and with supply chain disruptions that affected project
timelines. This means that announced government funding will support a smaller
number of projects than could be expected previously, as greater investment isneeded to close the cost gap between low-emission hydrogen and unabated fossil
fuels-based hydrogen.
Governments have started to make funding available to support the firstlarge-scale projects, but slow implementation of support schemes isdelaying investment decisions. North America and Europe have taken the leadin implementing initiatives to encourage low-emission hydrogen production. Largeamounts of government funding are being made available through schemes suchas the US Hydrogen Production Tax Credit, the EU Important Projects of Common
European Interest and the UK Low Carbon Hydrogen Business Model. However,the lengthy time lags between the announcement of the schemes and the moment
at which funds are made available to project developers is delaying project
execution, and even putting projects at risk. This has been aggravated by the lackof clarity about regulation, which has only very recently been resolved in somejurisdictions.

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Electrolyser manufacturers have announced ambitious expansion plans.
Manufacturers have announced that around 14 GW of manufacturing capacity areavailable today, half of which is in China. Electrolyser production in 2022 isestimated to be just over 1 GW. Manufacturers have announced plans for further
expansion, aiming to reach 155 GW/year of manufacturing capacity by 2030, but
only 8% of this capacity has at least reached FID. Realising manufacturers’Global Hydrogen Review 2023

Executive summary

ambitious plans will depend on solid demand for electrolysers, which today ishighly uncertain. Such uncertainty is already resulting in delays to these expansion
plans, some of which are being put on hold.

Efforts to stimulate low-emission hydrogen demand are
lagging behind what is needed to meet climate ambitions
Hydrogen demand reached a historical high in 2022, but it remains
concentrated in traditional applications. Global hydrogen use reached 95 Mt in
2022, a nearly 3% increase year-on-year, with strong growth in all major
consuming regions except Europe, which suffered a hit to industrial activity due tothe sharp increase in natural gas prices. This global growth does not reflect a
success of policy efforts to expand the use of hydrogen, but rather is linked togeneral global energy trends. Demand remains concentrated in industry andrefining, with less than 0.1% coming from new applications in heavy industry,transport or power generation. Low-emission hydrogen is being taken up very
slowly in existing applications, accounting for just 0.7% of total hydrogen demand,
implying that hydrogen production and use in 2022 was linked to more than 900 Mt
of CO2 emissions. Prospects are better in industry, particularly for ammonia
production, with refining lagging behind.
Measures to stimulate low-emission hydrogen use have only recently
started to attract policy attention and are still not sufficient to meet climate
ambitions. Government action has been focused on supporting low-emissionhydrogen production, with less attention to the demand side. The sum of all
government targets for low-emission hydrogen production accounts for 27-35 Mt
today, but targets for creating demand account for just 14 Mt, less than half ofwhich is focused on existing hydrogen uses. Even if these targets are met, they
represent only one-fifth of the low-emission hydrogen use in the Net Zero
Emissions by 2050 Scenario (NZE Scenario) by 2030. Without robust demand,
producers of low-emission hydrogen will not secure sufficient off-takers tounderpin large-scale investments, jeopardising the viability of the entire lowemission hydrogen industry.

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The private sector has started moving to adopt low-emission hydrogenthrough off-take agreements, but efforts remain at very small scale.
Companies have signed off-take agreements for up to 2 Mt of low-emissionhydrogen, although more than half are preliminary agreements with non-binding
conditions. Some companies are developing projects for an additional 3 Mt of lowemission hydrogen production for their own use, without the need for off-takeagreements. But even with the addition of these quantities, low-emission hydrogenuse is still far from what is needed to meet climate goals.

Global Hydrogen Review 2023

Executive summary

International co-operation initiatives can help to aggregate demand for lowemission hydrogen, but demand signals from these initiatives are unclear.
Governments and companies have launched a series of co-operation initiatives tofoster deployment of low-emission technologies, including hydrogen. Based on thecommitments made by these initiatives, they could create 0.8-3 Mt of low-emissionhydrogen demand by 2030. However, the real impact of their pledges remains tobe seen. These initiatives predominantly target new applications of hydrogen, andthere is no dedicated coalition targeting the chemical and refining sectors, which
are better placed to adopt low-emission hydrogen at scale in the short term.
Scaling up low-emission hydrogen use is also key to enabling the nascenthydrogen trade. International trade of hydrogen and hydrogen-based fuels is
expected to be an important feature of a net zero future. In the NZE Scenario,
more than 20% of demand for merchant hydrogen and hydrogen-based fuels isinternationally traded by 2030. Based on announced export-oriented projects,
16 Mt of hydrogen equivalent could be exported all around the world by 2030, but
only three projects have reached FID. The realisation of these announced trade
projects will depend on securing off-takers for the long run, as well as theimplementation of certification schemes and deployment of the necessary
infrastructure. Progress on infrastructure is moving slowly. There have beenannouncements for around 50 terminals and port infrastructure for hydrogen andhydrogen-based fuels, and for up to 5 TWh of underground storage capacity
aiming to be operative by 2030, but none of them has reached FID. Infrastructure
projects typically have very long lead times, so it is critical to start developing them
now to have a chance of them being available by 2030.

Transforming momentum around hydrogen into
deployment remains a struggle

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Political momentum behind low-emission hydrogen remains strong but
deployment is not taking off. A total of 41 governments now have a hydrogenstrategy in place and some of the early movers are updating their original
strategies, raising ambitions. There is consensus that low-emission hydrogen is a
key opportunity for decarbonising sectors where emissions are hard to abate. Theenergy crisis arising from Russia’s invasion of Ukraine has also turned a spotlighton the role that low-emission hydrogen can play in enhancing energy security. In
addition, several major economies have recently adopted new industrial
strategies, in which hydrogen technologies play a key part. Government policies
and private sector plans are translating into an expanding flow of capital into thelow-emission hydrogen sector. However, despite this momentum, low-emissionhydrogen still accounts for less than 1% of global hydrogen production and use,
and will need to grow more than 100-fold by 2030 to get in line with the NZE
Scenario.

Global Hydrogen Review 2023

Executive summary

Regulation and certification remain key barriers to adoption, but strong
international co-operation can be crucial to finding solutions. Several
countries have started putting in place regulations on hydrogen’s environmental
attributes and developing associated certification schemes. These have somecommonalities, but also significant divergences, which may lead to market
fragmentation. Intergovernmental forums like the G7 and the G20 haverecognised this risk and committed to work towards mutual recognition ofcertificates, which can facilitate market and regulatory interoperability. Referringto the emissions intensity of hydrogen production in regulation and certification –based on agreed methodology – can enable mutual recognition. 1
Governments need stronger policy action on multiple fronts to tap into theopportunity that low-emission hydrogen offers. Low-emission hydrogen canbe an opportunity for countries to boost their economies for the future by creating
industries along the supply chains of hydrogen technologies. In the Stated Policies
Scenario, the market size of the low-emission hydrogen sector rises from
USD 1.4 billion today to USD 12 billion by 2030, equivalent to the spending on
offshore wind in Europe in 2022. Increasing ambitions in line with the NZE
Scenario could expand the market size up to USD 112 billion, roughly the size ofthe market for rooftop solar PV installations in the Asia Pacific region in 2022.
However, there are challenges around the expansion of technology
manufacturing, as well as for creating demand and securing off-takers for lowemission hydrogen production. These challenges are to be expected in a sector
that needs to build up complex value chains, but have been exacerbated byinflation, the fall in fossil fuel prices and sluggish policy implementation.
Overcoming these challenges requires governments to act across the whole value
chain, or progress will be disjointed and lead to cancellations and setbacks.

Recommendations
Urgently implement support schemes for low-emissionhydrogen production and use
Governments have announced numerous programmes to support first movers, but
in most cases, these programmes are not yet implemented, or the funds have notyet been made available. This is hindering investment decisions for planned
projects whose economic feasibility depends on public support, a situation thathas worsened due to the impacts of inflation. Governments need to urgently
implement these programmes and make funding available to enable a scale-up
compatible with their decarbonisation ambitions.

See the report Towards hydrogen definitions based on their emissions intensity for more analysis on how emissions intensity
can facilitate mutual recognition of certificates.

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Global Hydrogen Review 2023

Executive summary

Take bolder action to stimulate demand creation for lowemission hydrogen, particularly in existing hydrogen uses
Governments must take the lead and implement policies that encourage action in
the private sector, combining support measures with regulations (such as quotas
or mandates) to require the adoption of low-emission hydrogen in existing
applications. These measures can be complemented with technology-neutral
regulations in priority sectors where alternative mitigation options exist (such as
steel, shipping, aviation, and long-distance road transport), and with public
procurement for low-emission and near-zero emission materials and products. Coordinated action is needed to unlock the necessary level of demand while
facilitating a level playing field, avoiding industry relocation and carbon leakage.
The private sector can also contribute by establishing an international cooperation initiative focused on demand aggregation in chemicals or refining, which
are best suited to scale up demand in the short term.

Foster international co-operation to accelerate solutions forhydrogen certification and mutual recognition of certificates
Governments should keep moving forward with the implementation of clear
regulations and associated certification schemes for hydrogen’s environmental
attributes. International co-operation needs to be reinforced to prevent lack ofalignment between these efforts, which could lead to market fragmentation. Fullharmonisation seems impossible in the near term, but governments should work
together to enable mutual recognition of certificates, which would allow a certain
level of market interoperability. Referring to the emissions intensity of hydrogenproduction in regulations and certifications, based on a common methodology for
determining the emissions, in line with the recommendations of the IEA’s reportfor the 2023 G7 Climate, Energy and Environment Ministerial meeting, Towardshydrogen definitions based on their emissions intensity, can facilitate the mutual
recognition of certificates.

Quickly address regulatory barriers, particularly for project
licensing and permitting

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The presence of a clear and stable regulatory framework must be balanced witha dynamic approach, calibrated to regular market monitoring, trying to makeregulatory principles workable to not discourage investments. Governments
should work to make licensing and permitting processes as efficient as possible
and to improve co-ordination among different authorities involved in the process,to minimise their significant impact on project lead times, particularly for certain
infrastructure developments, such as new pipelines, underground storage andimport/export terminals.

Global Hydrogen Review 2023

Executive summary

Support project developers to maintain momentum during the
inflationary period and to extend regional reach

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Governments can take action with interventions that respond to near-term
financial risks including loan guarantees, export credit facilities or public equity
investment in projects, to help project developers that are struggling with increases
in costs for equipment and capital. In addition, advanced economies need to raise
concessional finance - beyond their recent commitments - and boost co-operation
to facilitate the development of first-of-a-kind projects in emerging markets anddeveloping economies, including through rapid standardisation of contract
templates to overcome the unfamiliarity of parties with this new sector.

Global Hydrogen Review 2023

Chapter1. Introduction

Chapter 1. Introduction
Overview
The global energy landscape is undergoing a remarkable shift as the world
endeavours to combat climate change and enhance energy security bytransitioning to cleaner, more sustainable energy sources. In this context, lowemission hydrogen 2 has emerged as an important tool for decarbonising sectors
in which emissions are hard to abate. The recent global energy crisis has also
given more impetus to low-emission hydrogen as a means to bolster energy
security. As a result, governments have strengthened their commitments toachieve net zero emissions, and low-emission hydrogen has become an integral
part of their plans. In addition, some major economies have recently adopted newindustrial strategies, with hydrogen technologies as a key element. Yet despite
this momentum, there are still significant challenges that must be addressed to
unlock the potential of low-emission hydrogen.
This edition of the IEA Global Hydrogen Review tracks progress in the hydrogensector, focusing on the role of low-emission hydrogen as a vital driver of the clean
energy transition. By analysing recent developments and identifying areas
requiring attention, the report seeks to inform governments, industries and otherstakeholders on the path needed to ensure hydrogen can play its role in thetransition to a sustainable energy system.
First, we consider the status of hydrogen use and production today. Globalhydrogen use is increasing, but demand remains concentrated in traditional uses
in refining and the chemical industry and most production is still based on
unabated fossil fuels. Low-emission hydrogen production is yet to take off as amainstream industry.
Nonetheless, the chapter on trade and infrastructure reports some encouraging
signs. The number of announced projects keeps growing, and hydrogen trade isgaining momentum. However, progress is still lagging in some areas, notably inhydrogen infrastructure and technology innovation. We then go on to consider thelandscape for investment and innovation, assessing the impact of inflation on
low-emission hydrogen projects. Together with supply chain disruptions, inflation
has put some initiatives at risk.
Finally, a chapter on policy trends highlights the increasing number of policies
and strategies being announced to support scale-up of low-emission hydrogen.
See the Explanatory notes annex for the definition of low-emission hydrogen used in this report.

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Global Hydrogen Review 2023

Chapter1. Introduction

We also consider new regulations relating to hydrogen’s environmental attributes,
and the need for international co-operation to ensure certificates are mutually
recognised and prevent potential market fragmentation.
As this review demonstrates, scaling up low-emission hydrogen production anduse will require co-ordinated action by market players and strong government
support across multiple fronts. We examine the instruments and policies needed
to create favourable conditions for private sector investment and deployment, andhow to address barriers currently hindering project development.

The Hydrogen Initiative
Developed under the Clean Energy Ministerial framework, the Hydrogen Initiative(H2I) is a voluntary multi-governmental initiative that aims to advance policies,
programmes and projects that accelerate the commercialisation and deploymentof hydrogen and fuel cell technologies across all areas of the economy.
The IEA serves as the H2I co-ordinator to support member governments as they
develop activities aligned with the initiative. H2I currently comprises the following
participating governments and intergovernmental entities: Australia, Austria,
Brazil, Canada, Chile, the People’s Republic of China (hereafter “China”), Costa
Rica, the European Commission, Finland, Germany, India, Italy, Japan,
the Netherlands, New Zealand, Norway, Portugal, Republic of Korea (hereafter“Korea”), Saudi Arabia, South Africa, the United Arab Emirates, theUnited Kingdom and the United States. Canada, the European Commission,
Japan, the Netherlands and the United States co-lead the initiative, while China
and Italy are observers.

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H2I is also a platform to co-ordinate and facilitate co-operation among
governments, other international initiatives and the industry sector. H2I has active
partnerships with the Breakthrough Agenda, the Hydrogen Council, theInternational Partnership for Hydrogen and Fuel Cells in the Economy (IPHE), theInternational Renewable Energy Agency (IRENA), the Mission Innovation Clean
Hydrogen Mission, the World Economic Forum, the United Nations Industrial
Development Organization (UNIDO), and the IEA Advanced Fuel Cells andHydrogen Technology Collaboration Programmes (TCPs), all of which are part of
the H2I Advisory Group and participate in various activities of the H2I. In addition,
several industrial partners actively participate in the H2I Advisory Group’s biannual
meetings, including Ballard, Enel, Engie, Nel Hydrogen, the Port of Rotterdam
Authority and thyssenkrupp nucera.

Global Hydrogen Review 2023

Chapter 2. Hydrogen use

Chapter 2. Hydrogen use
Overview and outlook
Global hydrogen use reached 95 Mt in 2022, a nearly 3% increase from ourrevised estimate for 2021 3, continuing the growing trend that was only interrupted
in 2020 as a consequence of the Covid-19 pandemic and the economic slowdown.

Mt hydrogen

Hydrogen use by sector and by region, historical and in the Net Zero
Emissions by 2050 Scenario, 2020-2030
160

Hydrogen use by region, 2022

Hydrogen use by sector, 2020-2030
Other

140

Power

120

Synfuels

100

Transport

80

Refining

60

Industry

40

China
29%

Rest ofworld
24%

Europe8%

New

20

Traditional

0
2020

2021

2022

2030 NZE

India
9%

Middle East
13%

North
America
17%

IEA. CC BY 4.0.
Notes: NZE = Net Zero Emissions by 2050 Scenario. “Other” includes buildings and biofuels upgrading.

Hydrogen use continues to grow, but remains concentrated in traditional applications, suchas industry and refining.

Hydrogen use has grown strongly in all major consuming regions except Europe.
In Europe, hydrogen use suffered a big hit due to reduced activity – particularly inthe chemical industry – as a consequence of the sharp increase in natural gas
prices resulting from the energy crisis sparked by the Russian Federation’s(hereafter “Russia”) invasion of Ukraine. Several fertiliser plants reduced theirproduction output or even stopped operations for prolonged periods of the year,
reducing hydrogen use by nearly 6% in the region. In contrast, North America andthe Middle East observed strong growth (around 7% in both cases), which morethan compensated the drop in Europe. In China, use grew more modestly (aroundThe estimate of hydrogen demand for 2021 has been revised to 93 Mt from the Global Hydrogen Review 2022 (94 Mt), due
to adjustments to historic values in underlying datasets. In addition, in this report we are not including estimations of historicaluse of hydrogen small demands in glassmaking, electronics and metal processing (which accounted for around 1 Mt for 2021
in the estimate of the Global Hydrogen Review 2022).

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Global Hydrogen Review 2023

Chapter 2. Hydrogen use

0.5%), but the country remains the largest single consumer of hydrogen by far,accounting for nearly 30% of global hydrogen use (more than double that of thesecond largest consumer, the United States).
As in previous years, the growth in global hydrogen use is not a result of hydrogen
policies, but rather of global energy trends. Practically all of the increase took placein traditional applications (Box 2.1), mainly refining and the chemical sector, andhas been met by increasing production based on unabated fossil fuels (seeChapter 3 Hydrogen production). This means that growth has had no benefit forclimate change mitigation purposes. The uptake of hydrogen in new applicationsin heavy industry, transport, the production of hydrogen-based fuels or electricity
generation and storage – which is key for the clean energy transition – remains
minimal, accounting for less than 0.1% of global demand. In the updated 2023
edition of the IEA’s Net Zero Emissions by 2050 Scenario (NZE Scenario),hydrogen use grows by 6% annually until the end of this decade. This implies
reaching more than 150 Mt of hydrogen use by 2030, with nearly 40% comingfrom new applications. 4This chapter presents an overview of progress in the uptake of hydrogen indifferent sectors (including traditional and new applications) and assesses options
to increase ambition in demand creation for low-emission hydrogen 5 in the shortterm.

Box 2.1

Traditional and new applications for hydrogen

Hydrogen is widely used today in refining, the chemical industry (as a feedstock),the steel industry (as a reducing agent) and for special applications in otherindustries. The evolution of hydrogen use in these applications will be determinedby market dynamics in these sectors.
In theory, hydrogen can also be used in a wide range of other applications, as afeedstock or reducing agent, and also as a fuel. Hydrogen has not been used atscale in these applications, either due to its lack of competitiveness with incumbent
fossil fuels and with other low-emission technology alternatives, or because enduse technologies have not reached commercial maturity. However,decarbonisation efforts are expected to prompt hydrogen use in some of these new
applications, particularly in sectors where emissions are hard to abate and other
low-emission technologies are unavailable or very difficult to implement.

The IEA’s forthcoming report Net Zero by 2050: A Roadmap for the Global Energy Sector - 2023 Update will present a
redesigned NZE Scenario, based on an in-depth, sector-by-sector assessment of the progress and setbacks seen since therelease of its landmark report, Net Zero by 2050: A Roadmap for the Global Energy Sector, in May 2021.
5
See the Explanatory notes annex for the definition of low-emission hydrogen used in this report.

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4Global Hydrogen Review 2023

Chapter 2. Hydrogen use

Tracking hydrogen use alone is not sufficient to assess progress on hydrogen
adoption, and particularly whether it is happening in the direction and at the pacerequired for hydrogen to play its role in the clean energy transition. It is importantto also track the use of hydrogen by application, with a view to assessing theuptake in new applications. For reporting purposes in the IEA’s Global Hydrogen
Review, we have defined two categories of applications for hydrogen:Traditional applications, including refining; feedstock to produce ammonia,
methanol and other chemicals; and as a reducing agent to produce direct
reduced iron (DRI) using fossil-based synthetic gas. This category also
includes the use of hydrogen in electronics, glassmaking or metal processing,but these sectors use very small quantities of hydrogen (around 1 Mt per year)
and are not included in our tracking.

Potential new applications, such as the use of hydrogen as a reducing agent
in 100%-hydrogen DRI, transport, production of hydrogen-based fuels (suchas ammonia or synthetic hydrocarbons), biofuels upgrading, high-temperature
heating in industry, and electricity storage and generation, as well as otherapplications in which hydrogen use is expected to be very small due to theexistence of more efficient low-emission alternatives.

Refining
Hydrogen use in refining reached more than 41 Mt in 2022, surpassing its
historical maximum from 2018. The largest increase in year-on-year demandcame from North America and the Middle East, together accounting for more than
1 Mt, or around three-quarters of global growth in 2022 (Figure 2.2). China was
the only major refining region that reduced its demand for hydrogen (around
0.5 Mt) due to a decrease in refinery throughput as a consequence of extensive
pandemic-related mobility restrictions.
About 80% of the hydrogen used in refineries was produced onsite at the refineries
themselves, with around 55% resulting from dedicated hydrogen production andthe rest being produced as a by-product from different operations, such as
naphtha crackers. Less than 1% of the hydrogen used in refineries in 2022 wasproduced using low-emission technologies. The remaining 20% of hydrogen used
was sourced as merchant hydrogen, 6 produced externally, and mostly fromPAGE | 22

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6
Merchant hydrogen sourced by refineries is typically produced in plants very close to the refinery, and sometimes even in
the same location, but in plants operated by another company, given that hydrogen is not a global commodity today.

Global Hydrogen Review 2023

Chapter 2. Hydrogen use

unabated fossil fuels. The production of hydrogen for use in refining resulted in
240-380 Mt CO2 emitted to the atmosphere in 2022. 7
Hydrogen use by region and source of hydrogen for refining, historicaland in the Net Zero Emissions by 2050 Scenario, 2019-2030
Mt hydrogen

Use by region
45

45

40

40

35

35

30

30

25

25

20

20

15

15

10

10

5

5

0

2019

North America
EuropeRest of world

2020

2021

2022

China
India
Global 2030 NZE

2030
NZE
Middle East
Other Asia

0

Source of hydrogen

2019

2020

2021

Onsite - by-productOnsite - fossil w CCUS
Merchant

2022

2030
NZE
Onsite - fossil w/o CCUS
Onsite - electricity

IEA. CC BY 4.0.
Notes: NZE = Net Zero Emissions by 2050 Scenario. Fossil w/o CCUS = fossil fuels without carbon capture, utilisation andstorage; Fossil w CCUS = fossil fuels with carbon capture, utilisation and storage. Onsite refers to the production ofhydrogen inside refineries, including dedicated captive production and as a by-product of catalytic reformers.

Hydrogen use in refining reached a new record in 2022, but the fall in demand for oil
products required to align with the NZE 2050 Scenario would reverse this trend.

Meeting the requirements of the NZE Scenario necessitates a reversal in the trend
towards increasing demand for oil products, which will in turn result in lower
hydrogen use in refining. Consequently, the use of hydrogen in refining is lessthan 35 Mt by 2030 in the NZE Scenario. In addition, a larger share of thehydrogen used in refining is met by low-emission hydrogen, which accounts formore than 15% of hydrogen use in 2030 in the NZE Scenario.
The use of low-emission hydrogen in refining can offer an accessible route tocreate large demand for low-emission hydrogen and facilitate the scale-up of
production, given that it involves a like-for-like substitution rather than a fuelswitch. However, use of low-emission hydrogen in refineries has been limited todate, and is progressing slowly as a consequence of its higher production costs
when compared with hydrogen produced from unabated fossil fuels (see Chapter
3 Hydrogen production) and the lack of policy action to promote its adoption (seeCreating demand for low-emission hydrogen). In 2022, around 250 kt of lowemission hydrogen were used in refineries, practically the same amount as in
2021, given that only a couple of small electrolysis pilot projects (2.4 MW and

The range reflects different emission allocation of by-product hydrogen production. This excludes upstream and midstream
emissions for fossil fuel supply.

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Global Hydrogen Review 2023

Chapter 2. Hydrogen use

50 kW of installed capacity) started operating in the year (Figure 2.3). Almost all
the low-emission hydrogen used in refining in 2022 was produced in four facilities
using fossil fuels with CCUS that were already in operation in refineries in Canada
and the United States 8.
An increase in the use of low-emission hydrogen in refining can be expected in
2023. In July, Sinopec put into operation the world’s largest electrolysis plant in
Kuqa, China, (260 MW), which will produce 20 kt of low-emission hydrogen to
supply Tahe refinery. However, there are only a limited number of announced
projects aiming to produce low-emission hydrogen in refineries to replacehydrogen produced from unabated fossil fuels. If all the announced projects are
realised on time, 1.3 Mt of low-emission hydrogen will be produced and used inrefineries by 2030, with around 1.1 Mt being produced from fossil fuels with CCUS
and 0.2 Mt from electrolysis. 9 This represents an increase of around 6% comparedto the potential production coming from projects announced when the Global
Hydrogen Review 2022 was released. Most of this increase is from projects aiming
to produce hydrogen from fossil fuels with CCUS. The increase from the very few
new announcements by projects aiming to produce hydrogen through electrolysis
was nearly cancelled out entirely by pauses in projects that had previously beenannounced. 10
As noted above, the use of merchant hydrogen in refineries is a common practice
today and could provide an alternative route to increase the supply of low-emissionhydrogen in refineries. This option is being explored by refinery operators andsome off-take agreements have already been signed, such as between Vertex
Hydrogen and Essar Oil to use hydrogen produced from fossil fuels with CCUS in
the Stanlow refinery (United Kingdom). From an analysis of announced projects,
we estimate that an additional 0.7 Mt of low-emission hydrogen could be supplied
to refineries by 2030. 11
In the NZE Scenario, more than 4 Mt of low-emission hydrogen are produced andused in refineries by 2030, with around two-thirds produced from electrolysis andlow-emission electricity, and one-third from fossil fuels with CCUS. Announced
projects therefore meet only around 25% of the NZE Scenario’s requirements. The
gap with the NZE Scenario is significantly larger in the case of announced projects
to produce hydrogen from electrolysis, which meet less than 10% of the NZE
requirements. In the case of fossil fuels with CCUS, announced projects account

There are two more facilities in operation in France and the Netherlands, but these produce hydrogen from fossil fuels with
CCU, which is not considered as low-emission hydrogen for the purpose of this report.
9This could increase to 1.4 Mt (1.15 Mt from fossil fuels and CCUS and 0.25 Mt from electrolysis) with the inclusion of projects
at a very early stage of development, e.g. only a co-operation agreement among stakeholders has been announced.
10
Argus direct (2023), Phillips 66, Orsted pause UK green hydrogen plan.
11
This could increase to 1 Mt with the inclusion of projects at a very early stage of development, e.g. only a co-operationagreement among stakeholders has been announced.

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Global Hydrogen Review 2023

Chapter 2. Hydrogen use

for around three-quarters of the NZE needs. Moreover, the use of fossil fuels with
CCUS in refineries can count on an important head start since projects operating
today are already able to meet 15% of the onsite production from fossils with
CCUS in the NZE Scenario requirements.

Mt hydrogen

Onsite production of low-emission hydrogen for refining by technology,
region and status, historical and from announced projects, 2020-2030
Electrolysis

3.5
3.0

3.0

2.5

2.5

2.0

2.0

1.5

1.5

1.0

1.0

0.5

0.5

0.0

By
By
NZE
region status
2020

2021

2022

By region: North America

Europe

0.0

2030
China

Fossil fuels with CCUS

3.5

Other

By
By
region status
2020

GHR22

2021

By status:

2022

2022

NZE

2030
FID

FeasibiliyConcept

IEA. CC BY 4.0.
Notes: CCUS = carbon capture, utilisation and storage; FID = projects that have at least taken a final investment decision;
GHR 2022 = Global Hydrogen Review 2022; NZE = Net Zero Emissions by 2050 Scenario. Only planned projects with adisclosed start year of operation are included. GHR 2022 shows the estimated production of low-emission hydrogen fromprojects that were included in IEA Hydrogen Projects Database as of August 2022.
Source: IEA Hydrogen Projects , (Database, October 2023 release).

Based on announced projects, 1.3 Mt of low-emission hydrogen could be produced inrefineries by 2030, meeting one-quarter of low-emission onsite production needs in the NZE
Scenario.

In terms of maturity, around 10% of the announced projects to produce hydrogenfrom electrolysis to be used in refining have at least taken a final investment
decision (FID), whereas no FIDs have been taken for projects to producehydrogen from fossil fuels with CCUS. As last year, Europe remains the region
with the most projects, followed by North America and China.

Industry

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Of the 53 Mt of hydrogen used in industry in 2022, about 60% was for ammonia
production, 30% for methanol and 10% for DRI in the iron and steel subsector(Figure 2.4). Virtually all hydrogen used in industry is produced from unabatedfossil fuels in the same facilities as where it is used. Carbon capture is a common
practice in some industry sub-sectors, although most of the 140 Mt of CO2
captured is used for other industrial applications (such as urea production) andends up being released, with only a handful of projects storing CO2 underground.

Global Hydrogen Review 2023

Chapter 2. Hydrogen use

As a result, industrial hydrogen production was responsible for 680 Mt of CO2
emissions in 2022, up 2% from 2021. 12
Hydrogen use in industry by subsector and by region and source ofhydrogen, historical and in the Net Zero Emissions by 2050 Scenario,
2019-2030
Source of hydrogen

Use by sector

80

100%

60

75%

40

50%

40

20

25%

20

0%
2030
NZE
Share of low emissions(right axis)

0

0

2019

2020

Ammonia

Methanol

2021
Steel

2022
Other

Mt hydrogen

80

60

2019

2020

2021

Onsite - fossil w/o CCUS
Onsite - fossil w CCS
Onsite - other

2022

2030
NZE
Onsite - fossil w CCU
Onsite - electricity
Merchant

IEA. CC BY 4.0.
Notes: DRI = Direct Reduced Iron; Fossil w/ CCS = fossil fuels with carbon capture and storage; Fossil w/ CCU = fossil
fuels with carbon capture and use; Fossil w/o CCUS = fossil fuels without carbon capture, utilisation and storage; NZE =Net Zero Emissions by 2050 Scenario. Ammonia and methanol exclude fuel applications. 'Other' includes dedicatedhydrogen production for high-temperature heat applications.
Sources: IEA analysis based on data from International Fertilizer Association, World Steel Association and Wood
Mackenzie.

Hydrogen use in industry increased 2% in 2022 to reach 53 Mt, mostly concentrated inammonia, methanol and steel production, but a 4% annual growth rate would be necessary
to align with the NZE Scenario.

Global hydrogen use in industry in 2022 increased by 2% compared with 2021,
driven by global demand for ammonia rising by 0.4%, for methanol by 5% and for
DRI by 4%, although growth rates were lower than the average of the previous
years. China remains the main consumer of hydrogen in industrial applications,with 35% of global industrial use, followed by the Middle East (14%), North
America (10%) and India (9%). Europe was the only major consuming region
where hydrogen use in industry fell in 2022, as a consequence of the energy crisis
sparked by Russia’s invasion of Ukraine. Hydrogen use in industry in Europe
decreased 18% in 2022, largely due to a 20% decrease in activity in the ammonia
sector, which was particularly impacted by the conflict. At their peak in mid-2022,

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12This includes direct emissions from hydrogen production and around 290 Mt of CO2 utilised in the synthesis of urea andmethanol, the majority of which is later emitted. This excludes upstream and midstream emissions for fossil fuel supply.

Global Hydrogen Review 2023

Chapter 2. Hydrogen use

global ammonia prices had increased six-fold compared to the 2020 average.
However, prices declined during the first half of 2023, and have now returned totheir pre-pandemic level.
In the NZE Scenario, hydrogen use in industry grows to 70 Mt by 2030. Meeting
this need would require a 4% annual increase in production, compared to just 2%
over the past 4 years. Furthermore, to meet emission reduction objectives, about
one-third of industrial hydrogen production capacity needs to be low-emission by
2030, which would require most of the new capacity to be low-emission, as well
as retrofits to some existing stock.
Beyond traditional applications in the chemical and steel sectors, hydrogen use
also increases in new industrial applications, particularly 100%-hydrogen DRI andhigh-temperature heating, which account for 16% of global demand in industry by
2030.
Low-emission hydrogen production in industrial plants in 2022 was about 285 kt,
up from 240 kt in 2021. More than 90% of this capacity relies on fossil fuels with
CCUS with installations spread across North America, the Middle East and China.
There has been no significant progress in production of hydrogen from electrolysis
since the publication of the GHR 2022, with only three relatively small projects
coming online in 2023, one in Spain (8 MW of electrolysis to replace natural gas
with hydrogen), one in Sweden (17 MW of electrolysis for heating steel prior torolling) and one in India (5 MW of electrolysis for methanol production 13).
However, the near-term outlook is positive, as projects able to produce more than
600 kt of low-emission hydrogen are already under construction or have taken an
FID. The vast majority are concentrated in Europe (40%), China (28%) and Middle
East (24%). The most noteworthy developments since the release of the
GHR 2022 are:
The Hydrogen Energy Metallurgical Demonstration (China) to produce 390 kt ofammonia using electrolysis and renewable electricity, which started constructionin April 2023 and aims to begin operation in 2025.

•

A project from OCI aiming to capture 450 kt of CO2 annually from its Iowa (UnitedStates) ammonia plant.

•

The first project of H2 Green Steel in Boden (Sweden) which will install between
700 and 800 MW of electrolysers to produce more than 100 kt of hydrogenrequired annually for its steel production.

•

The Hygenco JSL plant (India) which should open in late 2023 and will be the firststeel plant using hydrogen from electrolysis and renewable electricity for theannealing process in the country.

Platts Hydrogen Daily (2023), INTERVIEW: NTPC Renewables set to place 1 GW of electrolyzer orders by 2026-27.

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13•

Global Hydrogen Review 2023

Chapter 2. Hydrogen use

Over the past year, numerous additional projects were announced, increasing the
expected low-emission hydrogen production from fossil fuels with CCUS by 30%
and from electrolysis by 50% (Figure 2.5), thus reaching 1.3 Mt and 1.8 Mt ofhydrogen production by 2030, respectively 14. Some of the newly announced
projects include:•

Dow Stade (Germany), which plans to use around 40 kt of electrolytic hydrogento produce 200 kt of methanol annually.

•

Plug Power Kristinestad (Finland), which will install 1 GW of electrolyser capacity
to supply a steel DRI plant with about 85 kt of hydrogen per year.

•

Yara Sluiskil plant (Netherlands), which projects capturing 800 kt of CO2 per year
from ammonia production.

Electrolysis

9

Mt H₂

Mt H₂

Onsite production of low-emission hydrogen for industry applications bytechnology and status, historical and from announced projects, 2020-2030

8

8

7

7

6

6

5

5

4

4

3

3

2

2

1

1

0

By
By
sector status
2020

By sector:

2021

Ammonia

2022
Methanol

NZE

2030
Steel

Other

Fossil fuels with CCUS

9

0

By
By
NZE
sector status
2020

GHR-222021

2022

By status: Operational

2030
FID

Feasibility

Concept

IEA. CC BY 4.0.
Notes: CCUS = carbon capture, utilisation and storage; FID = final investment decision; GHR-22 = Global Hydrogen
Review 2022; NZE = Net Zero Emissions by 2050 Scenario. Projects explicitly using ammonia or methanol as energy
carriers are not included. Only projects with a disclosed start year are included. GHR 2022 shows the estimated productionof low-emission hydrogen from projects that were available in the IEA Hydrogen Projects Database as of August 2022.
Source: IEA analysis based on data from the International Fertilizer Association and IEA Hydrogen Projects , (Database,
October 2023 release).

Announced projects for the production of low-emission hydrogen in the industrial sector
can reach 3 Mt by 2030, roughly one-quarter of low-emission onsite production needs in the
NZE Scenario.

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14This could increase to a combined 6.7 Mt if projects at a very early stage of development are included, e.g. projects forwhich only a co-operation agreement among stakeholders has been announced.

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Chapter 2. Hydrogen use

Nonetheless, to align with the net zero emissions target, the production of lowemission hydrogen from electrolysis using renewable electricity and fossil fuelswith CCUS in the industry sector needs to reach 8.6 and 3.5 Mt of hydrogen,respectively, almost quadrupling the production potential of the current projectpipeline.
Besides onsite hydrogen production, a significant number of projects aim to
produce merchant hydrogen for delivery to industrial consumers. Merchanthydrogen projects can have certain advantages, such as partnering with multiple
industrial clients to spread risk, but transport infrastructure is required. We
estimate that these projects could supply an additional 0.7 Mt of hydrogen toindustrial consumers by 2030 if they can secure off-takers for all their potential
production. Some key merchant hydrogen projects include:•

A project in Ordos (China), where Sinopec is building solar, wind and electrolyser
capacity to supply 30 kt of hydrogen per year to nearby chemical industries.

•

The Catalina Project (Spain), which aims to install 1.1 GW of renewable capacityand 500 MW of electrolysers in 2027 to supply around 40 kt of hydrogen annuallyto an ammonia plant through a dedicated 221 km pipeline.

•

The HyDeal project (Spain), which is developing 4.8 GW of solar and 3.3 GW ofelectrolyser capacity by 2030 to supply hydrogen to steel and ammonia producers.

•

The NorthH2 Project (Netherlands), which targets an electrolyser capacity of 1 GW
in 2027 and 4 GW by 2030 to supply more than 300 kt of hydrogen to industries
across the region.

Transport

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Hydrogen use in road transport increased by around 45% in 2022 compared to2021 (Figure 2.6), albeit from a relatively low starting point. Fuel cell electricvehicles (FCEVs) saw the earliest successes in terms of vehicle sales, in the car
and bus segments, but as heavy-duty fuel cell truck sales increase, their share of
total consumption is increasing rapidly. China’s focus on heavy-duty vehicles, andoutsized role in the deployment of fuel cell trucks, means that although only 20%
of all FCEVs are in China, they consume more than half of the hydrogen used inroad transport.

Global Hydrogen Review 2023

Chapter 2. Hydrogen use

kt hydrogen

Hydrogen consumption in road transport by vehicle segment and region,
2020-2022
35
30
25
20
15
10
5
2020
Cars

Buses

2021

2020

2022

Commercial vehicles

China

Europe

2021
US

Japan

2022
Korea

RoW

Notes: RoW = Rest of World; US = United States. Commercial vehicles include light commercial vehicles and medium- andheavy-duty trucks. Assumptions on annual mileage and fuel economy have been updated to match the IEA Global Energy
and Climate Model.

Hydrogen use in road transport increased by around 45% in 2022, albeit from a low base,driven mainly by increased use from heavy-duty vehicles.

The vast majority of hydrogen use in transport will likely remain in the road sector
for years to come, but rail is also adding to hydrogen consumption as hydrogentrains are being trialled and adopted along more routes. In addition, several fuelcell ferries are beginning operation in 2023, which will further diversify hydrogenuse for transport applications. Orders for ammonia- and methanol 15-ready vessels
could also result in additional hydrogen use for shipping in the coming years if
these technologies reach commercial maturity.
In the NZE Scenario, the use of synthetic kerosene and even the direct use ofhydrogen as an aviation fuel in later years add to hydrogen use in transport. To
get on track with the NZE Scenario, it will be important to accelerate the adoptionof hydrogen and hydrogen-based fuels and advance technologies that are today
still pre-commercial. In the NZE Scenario in 2030, almost 8 Mt of hydrogen is useddirectly in transport, mostly in the road (50%) and shipping (45%) sectors. In
addition, around 8 Mt of hydrogen are used for the production of ammonia andsynthetic fuels for their use in shipping and aviation.

Low-emission methanol can be biomethanol or synthetic methanol (e-methanol), but only the latter contributes to hydrogen
demand.

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Thousand vehicles

Fuel cell electric vehicle stock by segment and region, 2019-2023
90
80
70
60
50
40
30
20
10
2019
Cars

2020

2021

Buses

2022

Jun-23

Commercial vehicles

2019
Korea

2020
US

China

2021

2022

Japan

Jun-23

EuropeRoW

IEA. CC BY 4.0.
Notes: RoW = Rest of World; US = United States. Includes data until June 2023 for the current year.
Sources: Advanced Fuel Cells Technology Collaboration Programme; Hydrogen Fuel Cell Partnership; Korea’s Ministry ofTrade, Industry and Energy monthly automobile updates; Chinese vehicle insurance registration data, International
Partnership for Hydrogen and Fuel Cells in the Economy and Clean Energy Ministerial Hydrogen Initiative country surveys.

The global fleet of FCEVs is closing in on 80 000, with Korea remaining the major market forcars and China for trucks.

Cars and vans
By the end of 2022, the stock of fuel cell cars and vans exceeded 58 000, an
almost 40% increase compared to the previous year, and has reached around
63 000 in the first half of 2023 (Figure 2.7). 16 About 15 000 fuel cell cars were soldin 2022, with Korea representing around two-thirds of that increase. The first halfof 2023 saw something of a slowdown in the country, with fewer than 3 000 units
sold, compared to almost 4 900 during the same timeframe the previous year,
despite government plans to subsidise 16 000 fuel cell cars in 2023. Nevertheless,
Korea remains the largest fuel cell car market in the world, with a stock of over
32 000 fuel cell cars as of the first half of 2023. The second largest market is theUnited States, with around 16 000 fuel cell cars on the road. While Japan is stillhome to the third largest stock of fuel cell cars, fewer than 1 000 units were soldin the country in 2022, meaning that Europe experienced higher growth withalmost 1 500 additions. China added more than 200 fuel cell cars in 2022, whichis remarkable given that the country has over the past few years only deployed
FCEVs in heavier segments. As of June 2023, China is home to the majority offuel cell light commercial vehicles, with over 800 units deployed.

The deployment of fuel cell cars remains significantly lower than that of battery electric cars, which reached a global stockof over 18 million in 2022.

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Reflecting Korea’s dominance in domestic fuel cell car sales, Hyundai’s Nexo
represented the best-selling fuel cell car (10 000) in 2022; Toyota’s Mirai came insecond (3 200). Both the SAIC EUNIQ7 and Honda Clarity sold around 200 fuelcell cars in 2022, despite Honda discontinuing production of their fuel cell car in
2021. BMW also began small-series production of the iX5 Hydrogen fuel cell car
in 2022, launching their pilot fleet internationally at the beginning of 2023.
More fuel cell light-duty vehicle models are expected to enter the market in the
future. Honda has announced a new fuel cell vehicle, based on their CR-V
crossover sports utility vehicle (SUV), which will begin production in 2024 in the
United States. NamX, a Moroccan start-up, has presented a prototype fuel cell
SUV that can be fuelled in part by replaceable hydrogen capsules, with plans tolaunch in 2026. Kia, Korea’s second largest carmaker, aims to release fuel cellcars starting from 2027. Additionally, both Porsche and Toyota have developed
prototype hydrogen cars using combustion engines, highlighting their multitechnology approaches. However, FCEVs are very much a minority technology
with companies such as Volkswagen focusing instead on battery electric vehicles.
The French start-up Hopium had plans to produce a luxury fuel cell sedan to enter
the market in 2025, but instead entered receivership in July 2023.
In the light-commercial segment, new entrants First Hydrogen began trialling their“Generation I” fuel cell van in 2023, with plans to launch a second generation
vehicle in the coming years. RONN Motor Group has also announced plans to
manufacture fuel cell delivery vans, as well as medium-duty trucks. In terms ofestablished names, Ford has announced a fuel cell van trial in the United
Kingdom.

Trucks
The stock of fuel cell trucks has grown faster than light-duty vehicles, increasingover 60% in 2022 to bring the total to more than 7 100 by the end of the year. In
the first half of 2023, the stock reached more than 8 000. 17 The vast majority ofsales took place in China, which now accounts for over 95% of fuel cell trucks
globally, driven largely by a more than fivefold increase in heavy-duty fuel cell
trucks from the end of 2021 to June 2023 thanks to favourable policy andsupporting infrastructure. Fuel cell trucks are also being proven in practical use
outside of China, with Hyundai’s Xcient accumulating 5 million km in Switzerland
since 2020, with operations now also in Germany, Korea and New Zealand.
According to CALSTART’s Zero-Emission Technology Inventory (ZETI) there
were around 20 medium- and heavy-duty fuel cell truck models available in 2022,with a handful additional models planned for 2023.

For comparison, there were around 300 000 battery electric medium- and heavy-duty trucks globally at the end of 2022.

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In Europe, there have been a number of announcements for orders of fuel cell
trucks, such as from German energy company GP Joule, which ordered
100 Nikola Tre FCEVs (30 to be delivered within 2024); a SINTEF-led
H2Accelerate project in which 150 trucks will be deployed in Europe; and H2X
Global winning the tender to provide trucks for waste management in Gothenburg,
Sweden. Additionally, smaller announcements have come from companies suchas Dura Vermeer, and from Scania, which will be delivering fuel cell trucks in
Switzerland. Shell have launched a “pay-as-you-go” scheme in Germany similar
to that offered by Hyundai in Switzerland. Progress appears slower in the UnitedStates, though Hyundai is starting operations in the United States and Israel in
2023.
Activity is also increasing with respect to hydrogen combustion, which allows for
retrofitting of diesel engines, as done by Technocarb and CMB.TECH. The latteranticipate converting up to 20 trucks per month. Cummins also revealed a concepthydrogen combustion truck, suggesting that India may be the market most suited
to this approach, which was later echoed in announcements by Tata Motors andJBC. New Zealand is also trialling hydrogen combustion, though in dual-fuelvehicles.

Buses
The stock of fuel cell buses grew similarly to that of light-duty vehicles, with arounda 40% increase in 2022 compared with the previous year. As of June 2023, there
are around 7 000 18 fuel cell buses worldwide, about 85% of which are located in
China, which added around 1 300 fuel cell buses in 2022. Europe has the second
largest stock, followed by Korea and then the United States.
Compared to trucks, there are fewer companies producing fuel cell buses, with
under 20 in CALSTART’s ZETI, though companies often produce a number ofvariations for different applications. Of those, just Foton (China) and Hyzon(United States) are producing coaches, and the others manufacturing transit
buses, with no new models slated for 2023.
Germany, in particular, has seen a number of stakeholders opt for FCEVs, suchas Deutsche Bahn, which approved the purchase of 60 fuel cell buses, as well as
the cities of Weimar and Frankfurt. Other projects are underway in Liverpool in the
United Kingdom, where the first of 20 planned fuel cell buses came into service in
2023, and in Brazil and Uruguay where the Chinese manufacturer Higer is trialling
fuel cell buses. The largest announcements come from Korea, where 700 fuel cell

For comparison, there were around 650 000 battery electric buses at the end of 2022.

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buses will be deployed in Incheon by the end of 2024, and 1 300 in Seoul by 2030,
partially funded through a subsidy scheme.

Hydrogen refuelling stations
Globally, there are around 1 100 hydrogen refuelling stations (HRS) 19 in operation
as of June 2023, with hundreds more stations planned. Of the existing stations,well over 300 are in China, with Europe having around 250 HRS and both Korea
and Japan having around 180 (Figure 2.8). In the United States, the stock of HRS
has increased by only 10% since 2019. Given that the fleet of FCEVs has
increased at a higher rate, the ratio of FCEVs to HRS has increased steadily overthis time frame, reaching almost 240 vehicles per station in June 2023. Since
2019, the ratio of FCEVs per station in Korea has remained between 140 and 200.
Other major markets (i.e. China, Japan and Europe) have fewer than 50 FCEVs
per HRS.

1 200

Ratio of FCEVs to refuelling stations

Number of hydrogen refuelling stations

Hydrogen refuelling stations by region and ratio of fuel cell electricvehicles to refuelling stations, 2019-June 2023

800

400

0

2019
China

2020

2021

Europe

2022

June
2023
Korea

Japan

300

200

100

0
2019

2020
US

2021
RoW

2022
GlobalJune
2023

IEA. CC BY 4.0.
Note: FCEV = fuel cell electric vehicle; RoW = rest of world; US = United States. The number of hydrogen refuelling
stations refers to both public (retail) and private stations. Includes data until June 2023 for the current year.
Sources: Advanced Fuel Cells Technology Collaboration Programme, H2stations.org by LBST, International Partnership for
Hydrogen and Fuel Cells in the Economy and Clean Energy Ministerial Hydrogen Initiative country surveys.

In 2022, the number of hydrogen refuelling stations surpassed 1 000 for the first time.

With policy support from the EU Alternative Fuels Infrastructure Regulation, which
mandates HRS every 200 km along major road networks and in all urban nodes
from 2030 onwards, there are plans to expand the hydrogen refuelling network inThis includes only HRS for road mobility applications and excludes refuelling points for non-road applications such as
forklifts.

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Europe, especially to serve the growing fuel cell truck fleet. TotalEnergies and Air
Liquide are forming a joint venture to develop heavy-duty HRS focusing on
Benelux, France and Germany, with the aim of deploying over 100 stations. H2
Mobility aims to more than double its network by 2030, adding 210 stations acrossGermany and Austria to the existing 90 today. Italy will fund the construction of
36 HRS. However, there have also been steps backwards in HRS deployment inEurope, with Shell closing their three HRS in the United Kingdom.
In the United States, hydrogen and electric truck-maker Nikola was awarded
almost USD 42 million to establish 6 HRS in California, each capable of refuelling80-100 trucks per day. In 2023, Nikola also launched a 700 bar mobile refueller
with almost 1 t of storage.
Despite fewer announcements, the expansion of the HRS network was strongest
in Asia in 2022, and this will likely be the case again in 2023. For example, SK
Plug Hyverse, a joint venture between SK E&S and Plug Power, will establish
around 40 HRS in Korea, while Shanghai, China intends to build 70 HRS by 2025.
Locating hydrogen refuelling infrastructure at ports opens up the opportunity toprovide hydrogen to a variety of potential users beyond trucks, such as forklifts
and container stackers. The Port of Valencia, supported by the H2Ports project,provides such an example; elsewhere the Port of Hamburg has contracted Linde
Engineering to build a compressed hydrogen refuelling station expected to begin
operations in 2023. Air Products will build a commercial-scale liquid hydrogen
refuelling station in the Port of Zeebrugge, Belgium. In the United States, ports are
bidding to receive support to become “clean” hydrogen hubs.

Manufacturing capacity is scaling up
To capitalise on growing demand for mobile fuel cells, Hyundai opened its firsthydrogen fuel cell production facility outside of Korea in 2023, in Guangzhou,
China. Developments are also being seen in manufacturing of components indifferent regions. For example, Germany-based EKPO will invest in a new
production site following a large order for bipolar plates. Other announcements
come from Hexagon Purus, which opened a new hydrogen storage cylinder
factory in the United States and broke ground on a new smaller factory in Canada.
Ballard are aiming to reduce the cost of their next generation bipolar plate by up
to 70% by investing in their Canadian facility, while also planning a membraneelectrode assembly plant in Shanghai, supplying customers such as Siemens
Mobility.

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Capacity additions in 2022, together with a revised outlook for FCEV deployment
in the NZE Scenario, mean that the gap to 2030 continues to close and mobile
fuel cell manufacturers could meet 70% of what is needed in the NZE Scenario in
2030 (Figure 2.9).

Global Hydrogen Review 2023

Chapter 2. Hydrogen use

GW/yearMobile fuel cell manufacturing capacity by country/region according toannounced projects and in the Net Zero Emissions by 2050 Scenario,
2022-2030

140
120
100
80
60
40
20
0

2022

China
Asia Pacific
NZE residual capacity

EuropeRoW

Announced

2030 NZE
North America
NZE demand
IEA. CC BY 4.0.

Notes: NZE = Net Zero Emissions by 2050 Scenario; RoW = rest of world. Announced capacity includes existing capacity.
The manufacturing capacity needed to meet projected demand in the NZE Scenario (NZE demand) is estimated assuming
a utilisation rate of 85%. NZE residual capacity represents the manufacturing capacity that would remain unused, on
average, which provides some flexibility to accommodate demand fluctuations. Capacities in 2022 and announced
capacities include material handling equipment and other transport applications; NZE demand for fuel cells is based on fuelcell vehicles only.
Sources: IEA analysis based on data from E4tech and company announcements.

Expansion projects indicate a fourfold increase in fuel cell manufacturing for mobility
applications, reaching 70% of what is needed in 2030 in the NZE Scenario.

Progress in non-road transport sectors
Rail

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One of the largest orders for fuel cell trains comes from Italy, which is allocating
EUR 24 million (~USD 25 million) for rolling stock, and EUR 276 million(~USD 290 million) for hydrogen production and supply, with specific lines
identified and projects to have been completed by June 2026. In Germany,
Alstom’s hydrogen trains have progressed from trials to deployment, with 36 fuelcell trains in operation as of June 2023. They can now travel 1 175 km on a single
refuel, with a line outside of Hamburg now set to be the first all-hydrogen service.
Siemens Mobility also received an order for seven hydrogen trains in 2022, withdeliveries expected by Q3/Q4 2024. Passenger hydrogen trains are also
beginning trials in Canada, Spain and Japan. Arriva Netherlands launched atender for four to six hydrogen trains, after successfully trialling them in 2020.

Global Hydrogen Review 2023

Chapter 2. Hydrogen use

Hydrogen is also progressing in freight: Canadian Pacific used a hydrogenpowered locomotive on a commercial run in November 2022, and China also saw
its first domestic use of hydrogen in rail starting with freight.
However, several stakeholders who previously committed to hydrogen haveinstead opted for electric trains, citing lower operating costs.

Shipping
The Global Maritime Forum has identified pilot and demonstration projects forzero-emission vessel technologies, of which over 50 each focus on ammonia
combustion and hydrogen fuel cells, 30 on methanol and 25 on hydrogen
combustion. In terms of numbers of Approvals in Principle 20, ammonia vessel
designs have seen the most progress over 2022 and 2023.
In July 2023, the European Union adopted a new regulation, FuelEU maritime, toincrease use of low-carbon fuels in shipping with special incentives for nonbiological fuels such as from low-carbon hydrogen.
In March 2023, the first liquid hydrogen ferry, the MF Hydra, began operation in
Norway, using zero-emission hydrogen, and PowerCell signed an agreement toprovide their fuel cell system to two additional ferries in Norway set to be deliveredin late 2024. In the same month, another hydrogen ferry, the Sea Change, became
the first commercial maritime boat in the United States to be powered by hydrogenfuel cells. A hydrogen-powered barge was launched in the Netherlands, with asecond retrofit underway. In addition, Damen Shipyards will produce twohydrogen-powered vessels for use in offshore wind farm construction, which are
set to be delivered in 2025.

Aviation
Sustainable aviation fuels (SAFs), including low-emission hydrogen-based fuelssuch as synthetic kerosene, are at the highest levels of technology readinesscompared with other potential solutions for aviation decarbonisation. Synthetic
kerosene is a drop-in fuel that can directly replace fossil jet fuel without any
technology switch. This can facilitate its uptake, since technology barriers are
small and there are already some off-take agreements in place by aviationcompanies (see Creating demand for low-emission hydrogen). However, its highproduction cost is still a very significant barrier, which limits the scale of uptake
and hinders project developers from taking FIDs (see the Chapter 3 Hydrogenproduction). In April 2023, the European Union provisionally agreed to implement
ReFuelEU, an initiative aimed at decarbonising the aviation sector. The proposal

As stated in the report by the Global Maritime Forum, ““Approval in Principle” refers to the evaluation and approval of aconcept in its initial design stages, confirming its technical feasibility and moving it into further development stages.”

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includes a sub-mandate on the use of synthetic fuels, including synthetic
kerosene.
Most announcements regarding the direct use of hydrogen come from newer
entrants, such as Universal Hydrogen, which successfully completed a hydrogen
powered flight in 2023, and ZeroAvia, which continues testing and advancing its
hydrogen powertrain, and is also partnering with Absolut Hydrogen to develop
liquid hydrogen refuelling infrastructure by 2027. Cranfield Aerospace Solutions
and aircraft manufacturer Britten-Norman have announced the intention to merge
their operations with the aim of creating the world's first fully integrated, zeroemission sub-regional aircraft for entry into service in 2026. Other companies
advancing this technology in 2022 were Avio Aero, and H2Fly.
More established players such as Airbus are developing innovative cryogenichydrogen tanks and, in a joint venture with Safran, are developing hydrogen
refuelling facilities at Toulouse for their ZEROe aircraft. Meanwhile, Rolls-Royce
has continued testing hydrogen jet engines.
With respect to commercial agreements, the establishment of a memorandum of
understanding (MoU) for a “hydrogen flight corridor” between Hamburg andRotterdam paves the way for hydrogen flights as early as 2026. Unmanned cargo
aircraft company Dymond Aerospace signed an MoU for 200 hydrogen-powered
motors from Duxion Motors; and ZeroAvia have received orders for
250 powertrains for US regional airline Air Cahana in California.

Other applications
The use of fuel cell material handling equipment (e.g. forklifts) has continued to
expand. For example, at the end of 2022 there were over 60 000 fuel cell forklifts
in operation in the United States, compared to around 50 000 the previous year.
Hydrogen applications in mining trucks are gaining momentum, with 120 kW
proton exchange membrane (PEM) fuel cells and hydrogen-electric conversion of
2 wheeled excavators by zepp.solutions being deployed in India. Ballard are also
supplying fuel cells for retrofitting mining trucks, receiving orders in March andJune of 2023. JCB has had its hydrogen-powered digger approved by the UK
government and it will be seen on construction sites in 2023.

More niche applications are also being investigated, as Kawasaki, Suzuki, Honda
and Yamaha have formed the Hydrogen Small mobility and Engine technology

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Hydrogen continues to be an attractive option for various port operations, withrecent examples including testing of a hydrogen fuel cell container stacker at thePort of Los Angeles in late 2022 and launch of the world’s first hydrogen dual-fuelstraddle carrier at the Port of Antwerp in March 2023. The Port of Aberdeen will
investigate liquid hydrogen-fuelled autonomous cargo ships in 2024.

Global Hydrogen Review 2023

Chapter 2. Hydrogen use(HySE) group to develop engines for motorcycles, construction equipment, drones
and other applications.

Buildings
The contribution of hydrogen to meeting energy demand in the buildings sector
remains negligible, with no significant development in 2022. As part of efforts tomeet climate goals, there is a need to shift the use of fossil fuels in buildings
towards low-carbon alternatives, but options such as electrification via heatpumps, district heating, and distributed renewables appear to be well ahead ofhydrogen technologies. The use of hydrogen for decarbonisation in the buildings
sector is therefore negligible in the NZE Scenario (hydrogen use reaches slightly
over 1 Mt by 2030, 0.14% of total energy demand in the sector). Under current
policies (in the IEA Stated Policies Scenario, [STEPS]) 21, global hydrogen use inbuildings reaches just 0.03 Mt by 2030.
Hydrogen use in buildings can contribute to some niche applications, such asheating old and poorly insulated buildings already connected to a natural gas gridin cold environments. However, due to the energy losses associated withhydrogen conversion, transport and use, hydrogen technologies for use inbuildings are much less efficient than other available options, and they require
new or repurposed infrastructure and devices. For instance, electric heat pumps
require five to six times less electricity than a boiler running on electrolytichydrogen to provide the same amount of heating.
There has been little progress in 2022 on the deployment of buildings technologies
that might run on hydrogen. Currently, fuel cells in the building sector experienced
modest market growth in the past few years, are installed for the most part inEurope, Japan, Korea and United States and predominantly run on fossil fuels(Figure 2.10). In Japan, thanks to the ENE-FARM project, the stock of deployedfuel cell micro-combined heat and power (CHP) units surpassed 450 000 at end2022. Across various system sizes of stationary fuel cells, in 2022 the UnitedStates had installed capacity of around 600 MW, Japan about 315 MW, Europe
around 230 MW and Korea about 20 MW.

Projections for the STEPS Scenario in this Global Hydrogen Review 2023 are based on modelling results derived from themost recent data and information available from governments, institutions, companies and other sources, as of July 2023.
Updates will be included in the World Energy Outlook 2023 to be published in October 2023.

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800

Fuel cell installed capacity
Mt hydrogen

MW

Fuel cell stock by region, 2021-2022, and hydrogen use in buildings in the
Net Zero Emissions by 2050 Scenario, 2021-2050

4

Hydrogen use

0.60%

3

0.45%

400

2

0.30%

200

1

0.15%

600

0

0

2021

2022

Europe

2021

2022

Japan

2021

2022

United States

2021 2022
H₂ buildings use

2030

2050

0.00%

Share in buildings space heating service demand (rightaxis)

IEA. CC BY 4.0.
Notes: H2 = Hydrogen. The average fuel cell in Japan is assumed to be around 700 Watts.
Sources: IEA analysis based on International Partnership for Hydrogen and Fuel Cells in the Economy and Clean Energy
Ministerial Hydrogen Initiative country surveys, Japan's Ministry of Economy, Trade and Industry, Fuel cells and Hydrogen
Observatory and Fuel Cell & Hydrogen Energy Association.

Fuel cell deployment in buildings showed very limited progress in 2022, with most fuel cells
still running on natural gas.

Advances in the use of pure hydrogen in buildings are limited to small pilots anddemonstration projects. For example, in Lochem, the Netherlands, a pilot wasstarted at the end of 2022 in which 12 historic homes were connected to ahydrogen supply and had hydrogen boilers installed to provide heating. In 2023,
in Stad aan’t Haringvliet, more than three-quarters of residents voted in favour ofswitching their heating systems from natural gas to “green” hydrogen 22. However,some of these pilots face low social acceptance. In July 2023, the UK government
abandoned plans for a trial to transition the natural gas network to hydrogen in
Whitby, Cheshire, citing a lack of community backing as the primary reason.
The potential use of hydrogen in buildings is vaguely mentioned in multiple
national hydrogen strategies or plans. Only Japan has set a concrete target, with
5.3 million micro-CHP fuel cells to be installed by 2030. However, micro-CHP fuelcells can use other fuels, and the target does not explicitly require the equipment
to run on hydrogen.

See Explanatory notes annex for the use of the term “green” hydrogen in this report.

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Electricity generation
Hydrogen as fuel in the power sector is virtually non-existent today, with a shareof less than 0.2% in the global electricity generation mix (and largely not from purehydrogen, but mixed gases containing hydrogen from steel production, refineries
or petrochemical plants).
Technologies to use pure hydrogen for electricity generation are commerciallyavailable today, with some designs of fuel cells, internal combustion engines (ICE)and gas turbines able to run on hydrogen-rich gases or even pure hydrogen. Usinghydrogen in the form of ammonia could be another option for electricity generation.
Co-firing of ammonia in coal-fired power plants has been successfully
demonstrated in trials in Japan and China. Ammonia could also become a fuel forgas turbines. The direct use of 100% ammonia was successfully demonstrated in
a 2 MW gas turbine in 2022 in Japan, with efforts underway to develop a 40 MW
turbine for pure ammonia use.
While the use of hydrogen and ammonia can reduce CO2 emissions in power
generation, nitrogen oxides (NOx) emissions are a concern. Modern gas turbines
today use dry low NOx technologies to manage NOx emissions, allowing hydrogenco-firing shares of 30-60% (in volumetric terms) 23 depending on the burner designand combustion strategies implemented. R&D activities are underway to develop
dry low NOx gas turbines that can handle the full hydrogen blending range of up
to 100%. For NOx emissions from ammonia, flue gas treatment technologies suchas selective catalytic reduction are available and already established for coal
power plants. Ammonia combustion can also lead to nitrous oxide (N2O)
emissions, a strong GHG, but in the 2 MW demonstration project in Japan it waspossible to reduce overall GHG emissions (CO2 and N2O combined) of theammonia-fired gas turbine by 99% compared to a gas turbine using natural gas.

Projects using hydrogen and ammonia in electricity
generation
Interest in using hydrogen or ammonia as a fuel in the power sector has been
growing over the past few years. Several utilities in North America, Europe andthe Asia-Pacific region are exploring the possibility to co-fire hydrogen with natural
gas in combined-cycle or open-cycle gas turbines. In Asia, several projects havebeen announced to explore the use of ammonia in coal-fired power plants. In thenear-term, the use of hydrogen and ammonia can reduce the emissions fromexisting plants, while in the longer term power plants running entirely on hydrogenor ammonia can provide flexibility to the electricity system, in combination with

Volumetric hydrogen co-firing share of 30% and 60% with natural gas corresponds in energy terms (lower heating values)
to shares of 11% and 31%, respectively. If not stated otherwise, hydrogen shares are on a volumetric basis.

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large-scale hydrogen storage. Projects to combine hydrogen production fromrenewable electricity with large-scale hydrogen storage for subsequent
reconversion of part of the electricity are under development. For example, in the
United States (Advanced Clean Energy Storage and IPP Renewed), gas turbines
were delivered in 2022 for a new 840 MW combined-cycle power plant with ahydrogen co-firing share of 30% at start-up in 2025. In the United Kingdom(Saltend), a project aims to refurbish an existing 1 200 MW natural gas-fired
combined heat and power plant for 30% hydrogen co-firing by 2027.
The announced projects using hydrogen and ammonia in the power sector could
result in an installed capacity of 5 800 MW by 2030, an increase of 65% comparedto the corresponding capacity identified in the GHR 2022 (Figure 2.11). 24 Around
70% of the projects are linked to hydrogen use in open-cycle or combined-cycle
gas turbines, while the use of hydrogen in fuel cells accounts for 10% and the cofiring of ammonia in coal-fired power plants for 3% of the capacity of announced
projects. Regionally, these projects are principally located in the Asia-Pacificregion (39%), Europe (36%) and North America (25%).
Capacity in power generation using hydrogen and ammonia by region,
historical and from announced projects, 2019-2030
6 000

Total installed capacity by technology

MWMW

Total installed capacity by region

5 000

6 000
5 000

4 000

4 000

3 000

3 000

2 000

2 000

1 000

1 000

0

0

North America

EuropeAsia-PacificUnknown
Internal combustion engine
Gas turbine

Fuel cell
Steam cycle
Combined-cycle gas turbine

IEA. CC BY 4.0.
Note: Values for 2023 are estimates, assuming plants with an announced start date in 2023 actually start operation in
2023.

Hydrogen and ammonia-fired power generation capacity could approach 5 800 MW by 2030
based on project announcements, principally from hydrogen co-fired in combined-cycle
gas turbines.

In the case of co-firing hydrogen or ammonia, the capacity corresponds to the total installed capacity multiplied by the cofiring share in energy terms.

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In addition, several utilities announced plans to build new gas power plants or to
upgrade existing gas power plants to be H2-ready, i.e. able to co-fire a certain
share of hydrogen. In most cases, concrete dates for starting co-firing have notbeen announced. The hydrogen share of this H2-ready announced capacity would
correspond to 3 400 MW, although this number most likely represents a lower
range, based on projects for which information on the hydrogen co-firing capability
has been released. Other new planned gas-fired power plants are also likely to beable to co-fire a certain amount of hydrogen, but no information has been madeavailable. Similarly, existing gas-fired power plants are also able to handle certain
shares of hydrogen, varying from 10% to 100%, depending on the gas turbine
design. 25 Based on available information on the installed existing gas turbines andtheir maximum hydrogen blending shares from gas turbine manufacturers, thehydrogen-fired capacity from existing gas turbines could amount to more than
70 GW globally 26. Again, this represents a lower bound, since detailed information
was only available for 465 GW of the existing gas-fired capacity.
In addition to the growing number of announced projects, several demonstration
projects have made progress since the GHR 2022, particularly in Asia:•

In July 2023, in Korea, Hanwha Impact achieved a 60% hydrogen co-firing sharein an 80 MW gas turbine, the largest share to date in mid-to-large gas turbines.

•

In Austria, first trials of co-firing hydrogen in an existing 395 MW gas-fired
combined heat and power plant started in July 2023, with the goal to achieve a
15% hydrogen co-firing share in continuous operation.

•

In the United States, a 38% hydrogen co-firing share was demonstrated in 2023
at an existing 753 MW combined-cycle power plant.

•

For ICEs, earlier this year the manufacturer Wartsilä, together with WEC Energy,
demonstrated a 25% hydrogen co-firing share in an unmodified ICE. New ICEs
able to run on pure hydrogen are already offered by manufacturers.

•

The Japanese utility JERA moved forward plans by one year to start the 20% cofiring of ammonia at its Hekinan coal power plant in the fiscal year 2023 (ending
March 2024).

•

In April 2023 the utility Kyushu (Japan) started ammonia co-firing trials at a
700 MW unit of its Reihoku coal power plant.

•

In China, the Anhui Province Energy Group has completed trials of 10-35% cofiring of ammonia at a 300 MW unit of its Wanneng Tongling coal power plant overa 3-month period. The company plans further trials of 50% ammonia co-firing at a
1 GW coal unit.

Other factors, such as the capability of the gas supply pipes and valves to handle certain hydrogen blending shares are
not considered here, but are, of course, critical to assessing specific plants.
26
Derived by taking the maximum co-firing share multiplied by the total capacity for individual plants.

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Chapter 2. Hydrogen use

The State Power Investment Corporation (China) is working on a demonstration
project to test pure hydrogen firing in a 1.7 MW gas turbine by the end of 2023.

Policy developments for hydrogen in the power sector
Since the release of the GHR 2022, several countries have announced or updated
policies or targets for the use of hydrogen and ammonia in the power sector. In
June 2023, Japan reconfirmed its commitment to the use of hydrogen andammonia in the power sector in an amendment to its Basic Hydrogen Strategy
from 2017. By 2030, Japan aims to demonstrate 30% co-firing of hydrogen in largegas turbines and 50% ammonia co-firing in coal power plants. In 2021, Japan set
in its 6th Strategic Energy Plan the goal that hydrogen and ammonia should cover
1% of the electricity generation in 2030. Japan also announced in 2023 plans tohold capacity auctions for low-emission power technologies, with first auctions tostart by October 2023, and to include existing coal power plants to be retrofitted
for co-firing ammonia and the blending of hydrogen in new or existing gas-fired
power plants.
In early 2023, Korea presented its 10th Basic Energy Plan for Electricity Supply
and Demand, which provides revised targets 27 for 2030 of 13 TWh of electricity
generation from co-firing of hydrogen and ammonia at existing gas and coal power
plants, and 16 TWh stationary fuel cells using natural gas or hydrogen. For 2036,
the plan foresees electricity generation of 47 TWh from hydrogen and ammonia.
Korea also announced auctions for electricity generated from hydrogen. 28 A firsttender for 650 GWh for electricity generated from hydrogen, without any
constraints on the emission intensities, was launched in June 2023 for delivery in
2025, with five power plants winning the tender and 715 GWh in total being
awarded. A second tender over 650 GWh will open in October 2023. Tenders for“clean” hydrogen are planned for 2024 for delivery in 2027, at a volume of 3 0003 500 GWh. On the technology side, Korea aims to achieve 50% hydrogen cofiring in gas turbines and 20% ammonia co-firing in coal power plants by 2025. 29
In the longer term, the goal is to develop technologies allowing for 100% hydrogenfiring in gas turbines and 50% ammonia co-firing in coal power plants.
Viet Nam set in its Power Development Master Plan VIII long-term goals for theuse of hydrogen in the power sector, aiming to reach hydrogen-fired capacity ofaround 23-28 GW (4.5-5% of total capacity) by 2050, by converting gas-fired
power plants from domestic natural gas or liquefied natural gas to hydrogen.
Ammonia is also mentioned as an option to reach the phase-out of coal-fired
power generation by 2050, but without any specific targets.

Argus direct (2023), South Korea commits more funds to H2, slashes targets.
Argus direct (2023), S Korea on track to open hydrogen power bidding market.
29
Ibid.
27

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In the United States, in 2023 the Environmental Protection Agency (EPA)
proposed new standards for CO2 emissions from combustion turbines. The
standards will evolve over time and offer several options for compliance. The useof 30% hydrogen blends in turbines with intermediate- to high-capacity factors is
proposed as a compliance option for 2032.
In Mexico, the energy ministry sets in its 2023-2037 national electricity systemdevelopment program the goal to increase the share of hydrogen in the fuel input
mix combined-cycle gas turbine (CCGT) plants to 30% by 2036, supported byconverting 1 024 MW of CCGT capacity to being able to co-fire 30% of hydrogenby 2036.
In the amendment to its Combined Heat and Power (CHP) Act, Germany links
incentives to the requirement that new CHP plants with an electrical capacity
above 10 MW have to be H2-ready, with conversion costs not exceeding 10% of
the costs for building a similar new plant. A strategy for the power sector is being
prepared by the German government, including the requirement that new gas
power plants have to be H2-ready. In addition, the government plans three tenders
for hydrogen power plants and convertible or H2-ready power plants. The first two
tenders, each for a capacity of 4.4 GW, are for plants directly running on hydrogen,and will be supported through the German Renewable Energy Act, while the third
tender of 15 GW is for new or existing power plants, which can initially run on
natural gas, but must switch to hydrogen by 2035. One of the 4.4 GW tenders is
for innovative concepts combining renewable electricity generation with hydrogenproduction and storage and reconversion into electricity.

Creating demand for low-emission hydrogen
In the quest to scale up the production of low-emission hydrogen, uncertainty
surrounding its future demand has been identified by market players as a major
obstacle. This is compounded by the higher production cost for low-emissionhydrogen compared with hydrogen from unabated fossil fuels, the lack ofinfrastructure to deliver hydrogen to end-users, and the lack of clarity aroundregulation and certification. All these barriers are interconnected and cannot be
addressed in isolation or sequentially, but rather must be tackled in a co-ordinatedmanner. For example, a programme to support project developers to reduce thecost gap between the production of low-emission hydrogen and the cost ofincumbent unabated fossil fuel-based hydrogen may not be successful in bringing
projects to market if the regulatory framework is unclear and developers struggle
to demonstrate regulatory compliance, or if there is no demand from end-users
and the developers struggle to find off-takers.

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Significant efforts have been undertaken to develop programmes to support lowemission hydrogen production (such as the Important Projects of Common

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Chapter 2. Hydrogen use

European Interest [IPCEI] in the European Union, the Low Carbon Hydrogen
Business Model in the United Kingdom or the Clean Hydrogen Production Tax
Credit in the United States) and regulations.
Infrastructure development has only come into the policy debate very recently,
with most efforts taking place in Europe, where European transmission system
operators have started to plan the development of hydrogen infrastructure throughthe European Hydrogen Backbone initiative. Activity intensified after Russia’s
invasion of Ukraine, when European countries started developing new gas
infrastructure to diversify supply away from Russian gas. This drew attention to
the need to carefully consider how any new gas-related infrastructure could
potentially support the future development of hydrogen in the context of climate
ambitions.
On the demand side, measures to stimulate hydrogen demand have also only
recently started to attract policy attention. Without robust demand, there is nomarket, and the viability of the entire low-emission hydrogen industry isjeopardised. For project developers, securing off-takers for their product isimperative, as it directly impacts their ability to attract investors and maintainfavourable return rates. Realising the massive pipeline of announced projects
dedicated to low-emission hydrogen production will depend on meeting thechallenge of stimulating demand to scale up production and decrease costs.
In this section we explore the current outlook for low-emission hydrogen demand,
starting with options for creating demand in both existing and new applications.
Then we assess the demand that can be created through the plans and efforts
being made by governments and the private sector. Finally, we present some
options to stimulate low-emission hydrogen demand and close the gap between
existing efforts and what is needed to get on track with the NZE Scenario.

A two-pronged approach to creating demand for lowemission hydrogen
Switching to low-emission hydrogen in existing applications
The first priority is to switch the existing demand for hydrogen in industry andrefining from using unabated fossil-based hydrogen to low-emission hydrogen.
Replacing existing dedicated hydrogen production using unabated fossil fuels(80 Mt) 30 with production using water electrolysis would require deploying about
730-940 GW of electrolysis capacity, while retrofitting all existing production

Dedicated hydrogen production accounted for 80 Mt in 2022, with the remaining 15 Mt being produced as a by-product.

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assets with CCUS would require a CO2 capture capacity of 710- 880 Mt per year 31.
This underscores the tremendous opportunity to scale up low-emission hydrogenproduction by replacing existing hydrogen demand.
This substitution involves a like-for-like replacement, so has limited technicalchallenges. However, it is hindered by the higher cost of low-emission hydrogen,especially given that most of the supply from unabated fossil fuels is from existing
plants operating on a marginal cost basis. Closing the cost gap to facilitate thecreation of demand for low-emission hydrogen in these applications – including
equipping existing hydrogen units with high levels of CCUS – requires one of two
options, or a combination of both:•

One option would be to apply a sustained, elevated carbon price that raises costs
for all hydrogen users, but by a lower amount for users of low-emission hydrogen.
If all users face higher costs, it would be easier to pass them on to consumers
and, in many cases, hydrogen costs are not a large component of total production
costs. However, only about 23% of global GHG emissions are covered by a carbon
price today. Moreover, the average level of carbon pricing applied is still low, withless than 5% of GHG emissions covered by a carbon price above USD 50/t CO2.
Furthermore, carbon price volatility in some regions makes it difficult to persuadehydrogen users to switch to a new supply. Even if they are included in a carbon
pricing system, in many cases hydrogen consumers are partially or totally exempt
from the real carbon price: for instance, in the UK and EU Emissions Trading
Systems (ETS), industrial facilities currently receive free allowances (although inthe EU ETS these will be gradually phased out for fertiliser producers from 2026).
To reach cost parity with a facility that produces hydrogen from unabated naturalgas, a carbon price of USD 50-60/t CO2 would be currently needed for the samefacility equipped with CCUS, and USD 230-550/t CO2 for hydrogen produced withrenewable electricity. 32 The EU ETS price has fluctuated in the range of EUR 20100/t CO2 (USD 23-105/t CO2) over the past five years, and – while it peaked atover EUR 100/t CO2 (USD 105/t CO2) in 2023 – it has not yet offered enoughstability or predictability to be bankable for long-duration hydrogen projects andcontracts. In Canada, the minimum federal price started at CAD 20 (Canadiandollars)/t CO2 (~USD 15/t CO2) in 2019 and increased to CAD 50/t CO2(~USD 38/t CO2) in 2022. Other complementary carbon policy instruments, suchas voluntary carbon credit markets may also act as a catalyst to bring down thecosts of low-emission hydrogen (see Box 2.2).

•

Another option is to offer payments to producers of low-emission hydrogen so thatthey can compete on price with other hydrogen supplies, or payments to
consumers to encourage them to use low-emission hydrogen by partially or totally

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31
Assuming 65-70% efficiency and 50-60% load factor electrolysers; and 90-98% capture rate and 85-95% load factor for
carbon capture facilities.
32
Assuming marginal production cost for existing facilities, the CAPEX of CCUS equipment and OPEX for retrofitted facilities
and the full CAPEX and OPEX costs for renewable-based facilities. Assuming a natural gas price of USD 5/MBtu and
USD 25-40/MWh and 25-55% load factor for renewable electricity.

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Chapter 2. Hydrogen use

compensating for the additional cost. The H2Global mechanism uses a
combination of these two approaches, by covering the cost gap between a selling
price and a buying price, which are established through a double-auction model.
Under these options, some costs are borne by taxpayers rather than consumers,
but for users this can offer a faster path to scale up and reach cost parity. Suchsupport schemes are still in their infancy in most regions, and the availability ofsome of the most promising schemes has been delayed. Delays can have a major
impact on projects in today’s dynamic cost environment, in which inflation has
already eaten into the attractiveness of subsidies that were announced a year or
two ago. Electrolyser projects, in particular, are having to renegotiate quoted
prices from suppliers to try to achieve financial viability (see Chapter 5 Investment,
finance and innovation).

Box 2.2

The role of voluntary carbon credit markets in scaling up lowemission hydrogen

In addition to support from public policies, it is essential to mobilise funding in orderto facilitate the financing of low-emission hydrogen projects. One option is theutilisation of carbon credit markets. Carbon credits can complement other funding
sources for low-emission hydrogen initiatives, in a similar way to what is happening
with direct air capture and storage projects. However, as of August 2023, there areno carbon credits issued by low-emissions hydrogen because of the lack of a
globally adopted standard methodology for assessing GHG emissions fromhydrogen production, transport and use that can be used as a reference to develop
a standard crediting methodology. Nevertheless, the Hydrogen for Net Zero
(H2NZ) Initiative is trying to fill this gap and actively formulating novel
methodologies for crediting within voluntary carbon markets, with the aim of
unlocking financial support for low-emission hydrogen ventures. Furthermore,
there is potential to leverage carbon credits to help bridge the price premium gap
for hydrogen-based fuels as SAFs. SAF prices are currently significantly higher
than those of conventional jet fuel, and consequently demand is low, and SAF
producers today have to rely primarily on off-take agreements.

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In order to close the cost gap, governments can also facilitate the creation ofdemand for low-emission hydrogen by adopting regulatory measures such as
quotas or mandates that enforce the use of low-emission hydrogen in existing
applications. Similarly to the adoption of high carbon prices, this would result inhigher supply costs that will be passed on to consumers, but the impact on the
final products is expected to be rather limited: for example, the cost of a car would
increase only marginally when produced with steel produced using low-emissionhydrogen.

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Chapter 2. Hydrogen use

Creating demand in new applications
The second approach to demand creation involves expanding the demand for lowemission hydrogen (and hydrogen-based fuels) in new applications, where other
low-emission alternatives are limited and where hydrogen can therefore play apivotal role in decarbonisation. However, this expansion presents a greater
challenge as it necessitates the adoption of technologies that are, in most cases,
still under development, as well as infrastructure adaptation and expansion, andthe establishment of fit-for-purpose standards and regulations. The adoption ofstandards and regulations is particularly important to avoid the risk of unabatedfossil-based hydrogen filling demand in new applications, which in most cases
would result in higher life-cycle CO2 emissions than the use of incumbent fossil
fuels. To prevent this risk, robust and smart regulations are imperative to ensure
only low-emission hydrogen is used in these applications. 33

Policies to stimulate demand creation
Governments have so far set targets for the deployment of hydrogen technologies
in existing applications – particularly in industry – and in new applications,predominantly in transport. For example, Japan aims to have 800 000 FCEVs on
the road by 2030, while the European Union targets meeting 42% of industrialhydrogen demand with renewable fuels of non-biological origin (RFNBOs) 34 by thesame year. While these targets can signal intent to producers and consumers, inthe absence of other measures, they are insufficient to encourage market players
to fully commit to scaling up the use of low-emission hydrogen, given theassociated higher costs. Robust policies and regulations – and not just targets –are required to create the right investment environment, combining both support
to incentivise project developers and penalties for non-compliance.
There are numerous potential support measures to stimulate low-emissionhydrogen demand in both traditional and new applications, ranging from measuresthat prioritise hydrogen and hydrogen-based fuels (such as mandates for lowemission hydrogen in existing applications) to more technology-neutral sectoral
measures that prioritise decarbonisation (see Table 2.1). The latter includes
instruments such as Carbon Contracts for Difference (CCfD), by which thegovernment covers the difference between the CO2 abatement costs of a project
and a CO2 reference price, but the selection of the technology to reduce theemissions is made by the project developer. Other technology-neutral measures
include mandates for zero-emission vehicles (ZEVs), in which a minimum share

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33This aspect is beyond the scope of the analysis presented in this chapter since it has been addressed in detail in our recent
report Towards hydrogen definitions based on their emissions intensity.
34
The RFNBOs include hydrogen and hydrogen-based fuels produced from renewable energy sources other than biomass.

Global Hydrogen Review 2023

Chapter 2. Hydrogen useof sales has to be met with ZEVs, but the automaker decides whether that is met
with battery electric vehicles (BEVs), FCEVs, or a combination of both.
To a large extent, such policies have so far been announced, but not yet
implemented. As a result, current projections in the STEPS suggest that lowemission hydrogen demand may reach around 7 Mt by 2030, a significant increase
from current use of less than 1 Mt per year. However, this falls short of meeting
global hydrogen demand targets set by governments, which are estimated toreach nearly 14 Mt by 2030, with substantial contributions from traditional
applications in industry and refining sectors, but also from the transport sector(Figure 2.12).
Even if policy action was implemented to meet targets for hydrogen demand, theambition of these targets is significantly lower than the objectives set bygovernments for low-emission hydrogen production. Globally, government targets
for low-emission hydrogen production account for 27-35 Mt by 2030 (see Chapter
6 Policies), far exceeding the demand envisaged by demand targets.
The current pipeline of announced projects for the production of low-emissionhydrogen accounts for up to 38 Mt by 2030 (see Chapter 3 Hydrogen production),
which is relatively well-aligned with the global production targets announced bygovernments. However, the imbalance between demand and supply ambitions for
low-emission hydrogen poses a risk for the announced hydrogen production
projects to reach FID (only 4% have already done so) and, therefore, to achieve
government targets for low-emission hydrogen production. This discrepancy could
also impede the development of low-emission hydrogen supply chains.
At the individual country level, an imbalance in favour of hydrogen production
targets may be acceptable to countries that could become hydrogen exporters,such as Australia, Chile or Middle East countries. For example, in the STEPS, lowemission hydrogen demand in Chile reaches slightly more than 100 kt by 2030,
whereas the production target is for 25 GW of electrolysis (able to produce 2.12.8 Mt H2 35) by 2030. Achieving production targets would require the creation ofdemand for low-emission hydrogen at a level above the production targets inregions that could become hydrogen importers, such as Europe, Japan and Korea.
However, the combined demand for low-emission hydrogen in these three regions
accounts for 1.7 Mt in the STEPS, whereas their production targets account for
6.6-12.3 Mt by 2030 36, i.e. even above their own targets for low-emissionhydrogen demand.

Assuming 65-70% efficiency and 50-60% load factor.
The difference between the lower and the upper range mostly results from consideration of the EU Fit for 55 package forthe lower range and the RePowerEU plan for the upper range.

35

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To rectify this situation, governments must clarify their ambitions with regards todemand. This should include synchronising targets for low-emission production
and consumption, as well as expediting the implementation of concrete supportive
policies that can reduce risk in order to foster adoption among first movers.

Mt hydrogen

Potential demand for low-emission hydrogen created by implemented
policies and government targets, and production targeted bygovernments, 2030
40
Demand30

RefiningIndustry

20

Transport
Power

10

Other
Production0

Demand policies inforce

Demand targets

Total demand

Production targets

Production targets

IEA. CC BY 4.0.
Notes: In Production targets, the dashed area represents policy targets’ ranges. For countries that do not have a production
target, the low-emission hydrogen production is estimated from the capacity targets assuming a capacity factor of 57% andan energy efficiency of 69% for electrolysers and 90% for fossil-based technologies.

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Meeting government targets could generate up to 14 Mt of low-emission hydrogen demand,
far less than the 27-35 Mt envisaged by low-emission hydrogen production targets.

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Chapter 2. Hydrogen use

Examples of policies to stimulate demand for low-emission hydrogen
PolicyMeasures focused on promoting hydrogen and hydrogen-based fuels
Industry
Implemented: Romania passed a law that mandates industrial hydrogen users to meet 50% of theirdemand with low-emission hydrogen by 2030.
Announced: the Netherlands announced that it will set renewable hydrogen mandates for industry from2026; India announced plans to introduce a mandatory low-emission hydrogen purchase obligation for
the fertiliser and refining sector.
Governments can establish a minimum shareof low-emission hydrogen or hydrogen-based
Transport
fuel consumption in a specific sector.
Implemented: Romania passed a law mandating transport fuel suppliers to meet 5% of their fuel sales
with renewable hydrogen-based fuels by 2030.
Announced: In April 2023, the European Council and Parliament reached a political agreement on the
ReFuelEU aviation initiative, which includes a minimum share of 1.2% of synthetic fuels in aviation to be
implemented from 2030, and the FuelEU Maritime initiative, which includes a subtarget of 2% of
RFNBO in maritime fuel from 2034, if these fuels have not reached 1% by 2031.
Cross-sectoral
Implemented: In the United States, Colorado and Illinois passed bills creating a USD 1/kg H2 tax credit
Governments can offer financial benefits tofor the use of “clean” hydrogen in sectors where emissions are hard to abate.
end-users that purchase low-emission
Announced: in August 2023, New Zealand launched a consultation on a consumption rebate schemehydrogen and hydrogen-based fuels.
to be implemented from 2025. The Netherlands and the United States (USD 1 billion budget) have eachannounced they are exploring end-use subsidies for the use of low-emission hydrogen.
Industry and refining
Implemented: the European Commission provides grants through the Innovation Fund and approved
EUR 5.2 billion (USD 5.5 billion) for the Hy2Use (IPCEI) to fund projects aiming to use renewable
Governments can offer subsidies to cover thehydrogen in industrial applications. Governments including Canada, Italy, Poland and Spain have also
capital expenditures of industrial projects
provided subsidies for projects aiming to use low-emission hydrogen in industry and refining.
towards the purchase of fuel cell vehicles orhydrogen-powered equipment and to coverTransport
operating expenses (similar to tax credits for
Implemented: several countries, such as Korea, Japan and the United States have subsidies forfuel electricity or fuel subsidies for hydrogen
FCEVs.
use in transport).
Announced: New Zealand allocated NZD 30 million (New Zealand dollars) (USD 19 million) in its
Budget 2023 to create a Clean Heavy Vehicle Grant for heavy-duty ZEVs, including fuel cell heavy
vehiclesI EA. CC BY 4.0.

Quotas andmandates

ExamplesDescription

End-usesubsidies

CAPEX and
OPEX
subsidies

Government can pay project developers thedifference between their cost per tonne of CO2
avoided (fixed in an auction) and a CO2
reference price.

Industry
Announced: the German government announced a CCfD programme to accelerate the phasing-out offossil fuels in energy-intensive industries, replacing them with low-emission technologies (includinghydrogen), with the first auction expected at the end of 2023.

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Technology-neutral sectoral measures
CarbonContracts forDifference(CCfD)

Global Hydrogen Review 2023

ExamplesDescription

Governments can use their purchasing power
to encourage contractors to prioritise theprocurement of near-zero emission materials
and ZEVs.

Fuel
economy/CO2emissionsstandards

Governments can establish standards onvehicle fuel economy or CO2 emissions, which
can incentivise the adoption of ZEVs, includinghydrogen vehicles.

ZEV
mandates

Governments can mandate a minimum shareof ZEVs, which can encourage FCEV
adoption. Credits related to meeting ZEVmandates are often combined with fueleconomy/CO2 standards.

Carbontaxes

Governments can apply a tax to CO2 or other
GHG emissions in specific sectors or acrossthe whole energy system to penalise emitters

Emissions
Trading
Systems(ETS)

Governments may set a limit on CO2emissions in specific sectors, or across thewhole economy. Governments allocate
emissions allowances among entities
operating in those sectors. If companies
reduce their emissions under their allocatedallowance, they can trade the difference withcompanies that emit over their allocatedthresholds and need to purchase allowances
to comply with their ETS obligations.

Cross-sectoral
Implemented: over 30 ETS are already in operation at national (e.g. China, the European Union andthe United Kingdom) and sub-national (e.g. California and Québec) level. Some, such as the European
Union, the United Kingdom and Québec, also cover hydrogen production.

Note: See Explanatory notes annex for the use of the term “low-carbon” and “clean” hydrogen in this report.

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Publicprocurement

Industry
Implemented: in December 2021 the US government launched the Federal Buy Clean Initiative toprioritise procurement of low-carbon construction materials, in particular steel and concrete.
Announced: in March 2023 the United Kingdom launched a consultation on measures to prevent
carbon leakage risk, including public procurement of industrial products such as steel and cement.
Transport
Implemented: in November 2020, Norway set rules for the tender of the largest ferry connection in the
country to use hydrogen; in July 2021, Ireland transcribed into law the EU Clean Vehicles Directive,
which defines procurement targets for clean light- and heavy-duty vehicles for government fleets.
Announced: in July 2023 UK National Highways announced the purchase of “low-carbon” hydrogen to
be used in construction machinery.
Transport
Implemented: in April 2023, the EU Parliament and Council adopted an amended regulation tostrengthen CO2 emission standards for new passenger cars and light commercial vehicles; China iscurrently in Phase V of its fuel consumption standards, which requires carmakers meet fleet-wide
average targets of 4.0 l/100 km by 2025 and 3.2 l/100 km by 2030.
Announced: in April 2023, the US EPA proposed GHG standards for heavy-duty vehicles (HDVs).
Transport
Implemented: California (United States) has a ZEV mandate since 1990. The current policy requiresthat ZEVs (and plug-in hybrid electric vehicles) represent 100% of new car sales by 2035.
Announced: as an outcome of consultation, the United Kingdom has proposed a zero-emission car andvan mandate that would require 100% ZEV sales from 2035.
Industry
Implemented: Since 2017, Chile has been applying a carbon tax on the power and industry sectors,
notably on installations with an installed thermal power exceeding a specified threshold capacity. The
carbon tax in Portugal also covers industry sector emissions.
Transport
Implemented: Denmark, Ireland and Portugal have a carbon tax in place covering emissions that areoutside the scope of the EU ETS, in particular emissions from the transport sector.
I EA. CC BY 4.0.

PolicyChapter 2. Hydrogen use

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Chapter 2. Hydrogen use

First steps from industrial stakeholders
The private sector has made first moves in adopting low-emission hydrogen,driven by various factors including compliance with decarbonisation policies,
government signals favouring hydrogen adoption, public reputationconsiderations, and strategic decisions to lead in technology development andnew markets. As a result, many companies have initiated off-take agreements for
low-emission hydrogen and hydrogen-based fuels.
Most of these agreements are still preliminary, often in the form of MoUs or Heads
of Agreement, but they can lay the groundwork for potential transactions. An
estimate of more than 2 Mt of low-emission hydrogen demand can be unlocked
by 2030 from the off-take agreements that have been publicly announced bycompanies, but only around half of that demand comes from firm deals (Figure2.13).

Mt hydrogen

Potential demand for low-emission hydrogen that can be achieved withannounced private off-take agreements by 2030
1.50

By type of agreement
Firm off-takes
Preliminary off-take

1.25

By sector
Industry

1.00

Chemicals
Iron & steel

0.75

Other industry
Transport
Road

0.50

Shipping
Aviation

0.25
0.00

Other transport
Other/Unknwon
By type of
By sector
agreement
Industry

By type of
By sector
agreement
Transport

By type of
By sector
agreement
Other

Refining
Power
Not specified

IEA. CC BY 4.0.
Notes: “Unknown” includes off-take agreements for which the end use of hydrogen and hydrogen-based fuels has not been
disclosed. Only off-take agreements disclosing the amount of low-emission hydrogen and hydrogen-based fuels agreed
and stating that they will take place before 2030 have been included.
Source: IEA analysis based on announcements of off-take agreements for hydrogen and hydrogen-based fuels.

The private sector has signed off-take agreements accounting for more than 2 Mt of lowemission hydrogen demand.

The industrial sector has been at the forefront of this movement, with off-takeagreements for almost 1.3 Mt of demand for low-emission hydrogen. Around halfof this demand comes from firm agreements, reflecting a strong commitment totransitioning to cleaner energy sources. Within the industrial sector, the chemical

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subsector accounts for a significant 85% of the volumes agreed, showing thattraditional applications for hydrogen are more prepared to take up low-emissionhydrogen in the short term.
Several notable agreements have been forged for low-emission ammonia supply.
For instance, Linde has committed to supply low-emission hydrogen to OCI for the
production of 1.1 Mt of ammonia in a new plant in the United States. Additionally,
Iberdrola and Teal have secured agreements to provide 0.9 Mt of low-emissionammonia to Trammo.
In the steel sector, H2 Green Steel has been proactive in signing customer
contracts for over 1.5 Mt of DRI per year (constituting around 60% of their planned
initial production capacity), which would require around 100 kt of hydrogenproduced from electrolysis and renewable electricity.
Although the transport sector has shown slower progress compared to theindustrial sector, some significant agreements have been made. The shipping
sector, in particular, has seen substantial activity, with prominent logistics
companies signing agreements for synthetic methanol and synthetic marine diesel
to decarbonise their operations. In the aviation sector, although the focus has been
on lower-cost biojet fuels, hydrogen-based fuels are expected to gain ground in
the future due to their greater resource potential and life-cycle emissions
reductions. Presently, the majority of deals in the aviation sector originate from US
companies.
The refining and electricity generation sectors have also seen a limited number ofoff-take agreements, but they represent considerable volumes. For example, Yara
and CF Industries secured a tender to supply 90 kt of hydrogen in the form ofammonia to JERA for co-firing in coal power plants. VERTEX and Essar Oil UK
have agreed to supply hydrogen produced with natural gas and CCUS to the
Stanlow refinery in the United Kingdom. There have been also some off-takeagreements linked to development of international hydrogen trade for which theend use of hydrogen and hydrogen-based fuels has not been disclosed or is
expected to cover numerous applications in the destination region, such as theone between DAI Infrastructure and Freepan Holdings (for 800 kt NH3/yr) or theone between RWE and Hyphen (300 kt NH3/yr).
Although the current demand for low-emission hydrogen that can be generated
from these deals stands more than to 2 Mt, this should be considered a
conservative estimate of the private sector's preparedness to adopt low-emissionhydrogen and hydrogen-based fuels. Many agreements have not been madepublic, or – if they have – the details of the deal are undisclosed due to thecompetitive nature of the market and companies' desire to protect their strategies.
Moreover, within refining and the industrial sector, some companies are alreadydeveloping projects to produce their own low-emission hydrogen to meet part of

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their total hydrogen demand, without the need to sign an off-take agreement withan external supplier. This mirrors the way in which those companies produce anduse their own hydrogen from unabated fossil fuels today. Some advanced
examples include projects developed by Shell and Sinopec for the use of lowemission hydrogen in refining, or by Yara for the use of low-emission hydrogen in
fertiliser production. Looking ahead, the pipeline of announced projects indicatespotential self-produced low-emission hydrogen volumes of more than 2 Mt in theindustrial sector and over 1 Mt in refining. However, firm commitments for selfproduction of low-emission hydrogen presently represent less than 1 Mt in industry
and around 0.3 Mt in refining.

International co-operation to aggregate demand
Both governments and the private sector acknowledge the formidable challengeof scaling up the production and use of low-emission hydrogen at the required
pace through individual action alone. Recognising the importance of collaboration
on a global scale, international co-operation has emerged as a key pillar in the
pursuit of this objective.
In recent years, governments and companies have launched a series of initiatives
to foster collaboration in the deployment of low-emission technologies, including
those related to hydrogen (Table 2.2). These ambitious endeavours aim to bring
together diverse stakeholders, comprising numerous governments and private
sector players, united in their pursuit of common goals for the widespread adoptionof low-emission technologies and fuels, along with ambitious emission reduction
targets.
While various initiatives have been set in motion, it is noteworthy that, with the
exception of the Green Hydrogen Catapult, most lack a specific focus onhydrogen. Instead, their primary emphasis lies on the broader adoption of lowemission technologies and the reduction of emissions across various sectors. The
transport sector garners significant attention, with a secondary focus on theindustrial sector. Certain initiatives, such as the First Movers Coalition and theMission Possible Partnership, encompass commitments spanning multiple subsectors crucial for hydrogen, including industry (aluminium, cement, chemicals
and steel) and transport (aviation, shipping, and trucking).

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Selected international initiatives for the deployment of low-emission
technologies
Initiative

Description and pledges

First Movers Coalition

Mission Possible
PartnershipGreen Hydrogen Catapult
Clean Energy Ministerial
Industrial Deep
Decarbonisation Initiative
SteelZero
C40 cities
Clean Energy Ministerial
Global Commercial Drive
to Zero Campaign
Accelerating to Zero
EV100+
Federal Buy Clean
Initiative
Mission Innovation Zero
Emissions Shipping
MissionClydebank Declaration

Coalition of companies using their purchasing power to create early markets
for innovative clean technologies across sectors in which emissions are hard
to abate, including commitments on aluminium, aviation, carbon dioxide
removal, cement and concrete, shipping, steel and trucking.
Private-led coalition driving industrial decarbonisation across the entire value
chain of the highest-emitting heavy industry and transport sectors, withstrategies for aluminium, aviation, cement and concrete, chemicals, shipping,steel and trucking.
Global private-led initiative whose goal is to drive a massive low-emissionhydrogen scale-up (80 GW) to be used in trucking, aviation, shipping,fertilisers, steel and methanol.
Government initiative aiming to stimulate global demand for low-carbon
industrial materials by encouraging governments and the private sector to buy
low-carbon steel and cement, including through a Green Public Procurement
Pledge.
Coalition of companies currently pledging to procure 50% low-emission or
responsible steel by 2030 and 100% near-zero steel by 2050.
Global network of mayors of the world’s leading cities with common emission
reduction goal, including a target to reduce embodied emissions of new
constructions by 50% by 2030.
Coalition of leading countries committed to working together to enable 100%zero-emission new truck and bus sales by 2040 with an interim goal of 30%
ZEV sales by 2030.
Coalition of governments from leading and emerging markets, regional
governments, automotive manufacturers, fleet operators, and more,committed to all sales of cars and vans being zero-emission by 2040, and nolater than 2035 in leading markets.
A private industry pledge where signatories commit to transition their medium
and heavy-duty vehicles to zero-emission by 2040 in leading markets.
The US government pledges to prioritise the procurement of low-carbon
materials made in the United States, such as steel and cement, using theirimportant purchasing power to help national industries.
Coalition of governments and maritime companies with pledges to deploy atleast 200 ships using zero-emission fuels, use at least 5% of zero-emission
fuels in shipping and deploy fuelling infrastructure in at least 10 large ports by
2030.
Coalition of governments aiming to establish at least six zero-emission
maritime routes before 2030.

Based on the commitments made by these initiatives, we have estimated apotential to create demand for low-emission hydrogen in the range of 0.8 to 3 Mt
by the year 2030 (Figure 2.14). All four sectors covered by these initiatives(industry, road transport, aviation and shipping) can achieve similar levels ofhydrogen demand, with central estimates ranging between 0.4 and 0.6 Mt in eachsector by 2030.
However, despite the positive intent of these initiatives, the implementation of theirpledges and their real impact remains to be seen. In addition, to ensure that theinitiatives can most effectively contribute to the adoption of low-emissionhydrogen, there are some issues that need to be addressed. Many sectoral
initiatives, particularly in the transport subsector, share a very similar membership,

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with commitments often overlapping, resulting in duplication of efforts instead of ameaningful cumulative impact.

Mt hydrogen

Potential demand for low-emission hydrogen that can be achieved withthe commitments of international initiatives, 2030
1.00

0.75

0.50

0.25

0.00

Road
Industry

Shipping
Transport

Aviation

IEA. CC BY 4.0.
Notes: Aviation includes hydrogen demand to produce synthetic kerosene and for the hydrogenation of biofuels. Dashedareas denote the variability between the most conservative and boldest estimates. For industry, in the First Mover
Coalition, the steel demand of members was estimated based on their industrial activity. For the Industrial Deep
Decarbonation Initiative, it is assumed that all 9 currently member countries make a pledge to use 10% low-emission steel
in their public procurement. For road transport, cumulative sales of fuel cell electric vehicles (FCEVs) in line with the Drive
to Zero and Accelerating to Zero campaigns in countries that signed the declarations were assumed to result in 0.4-1.4%
and 0.05-0.15% of 2030 fuel consumption in the heavy-duty and light-duty fleets, respectively, being hydrogen. For
shipping, in line with the Zero Emissions Shipping Mission and Clydebank Declaration, 5% and 10% of energy was
assumed to come from low-carbon fuels respectively, with campaigns assumed to cover 5-10% and 0.1–0.3% of global
demand respectively; the lower and upper limits were found by assuming 50% of demand being served by synthetic
methanol and up to 100% served by low-emission ammonia. For aviation, the First Movers Coalition and Clean Skies forTomorrow Coalition provide sustainable aviation fuel targets of 5% and 10% respectively: these are translated intohydrogen demand with the lower limit using hydrogen only in biofuel upgrading, and the upper limit also including synthetic
fuel production. Initiatives which did not have a target that could be translated into a hydrogen volume were not included.

Pledges from international initiatives could create up to 3 Mt of demand for low-emissionhydrogen, but estimates are uncertain since pledges are mostly technology-neutral.

While these initiatives serve to signal potential hydrogen demand, theirtechnology-agnostic nature introduces uncertainty on how much demand they caneffectively create, as shown by the wide variability of the projections presented in
our analysis. This is hindering potential hydrogen suppliers from accurately
gauging the extent of the demand they can anticipate. In an effort to address thischallenge and provide greater clarity, during the 27th Conference of the Parties(COP 27) (under the framework of the Breakthrough Agenda dialogues) the First
Movers Coalition pledged to present a comprehensive estimate of hydrogen
demand arising from their members' commitments at COP 28. An initial estimate
made by the First Movers Coalition suggests that the commitments of its members
can generate between 0.5 and 0.9 Mt of hydrogen demand by 2030. The Coalitionis expected to release further details of this estimate, including the sectoral
breakdown, later this year. If other initiatives were to follow suit and transparently

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communicate potential estimates for hydrogen demand resulting from theiractivities, it would significantly bolster the signal sent to low-emission hydrogenproducers, thereby catalysing further progress.
An important observation is that these initiatives predominantly target new
applications of hydrogen, but there is an obvious absence of a dedicated coalition
bringing together companies from the sectors that already use hydrogen today:
the chemical and refining sectors. Only the Mission Possible Partnership has
activities within the chemical sector and, more concretely, on ammonia production,
but does not have any specific commitment. An initiative of this nature, with ashared objective of adopting low-emission hydrogen in existing applications,presents a ripe opportunity to expedite the rapid scaling up of low-emissionhydrogen production and use in the short term.

Closing the ambition and implementation gap with the
Net Zero Emissions by 2050 Scenario
While governments and the private sector have taken first steps to promote theadoption of low-emission hydrogen, these actions are insufficient to align withgovernments' climate objectives and to scale up low-emission hydrogenproduction accordingly, which is crucial to drive down costs.
The gap between current actions and the demand for low-emission hydrogenrequired to put the world on a pathway compatible with achieving net zero
emissions by 2050 is even more significant when considering the speed of
deployment needed in the short term. In the NZE Scenario, demand for lowemission hydrogen reaches 70 Mt by 2030, compared to the 3-14 Mt that could beachieved through current government and private sector activities. The disparity
is even more pronounced when compared to off-take deals already signed by theprivate sector (Figure 2.15). In this context, there is clearly an urgent need forbolder action to stimulate demand for low-emission hydrogen.
Governments must take the lead and implement policies that encourage action in
the private sector, combining support measures with regulatory frameworks to
enforce the adoption of low-emission hydrogen in sectors where it is the only
decarbonisation alternative: refining, ammonia production and methanol
production. In other priority sectors such as steel, shipping, aviation and longdistance road transport, where alternative mitigation options exist (e.g. iron ore
electrolysis in ironmaking; battery electric trucks), regulatory structures should
also be designed to provide technology-neutral incentives for equivalent options.
International regulatory bodies, such as the International Maritime Organizationand the International Civil Aviation Organization, should also take action toaccelerate the adoption of fuel standards and mandates of sustainable fuels ininternational transport, ensuring that all players are subject to the same rules,

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which can unlock large demands for hydrogen-based fuels in shipping andaviation. Policies addressing the fuel supply side (such as phasing out fossil fuelsubsidies, which the IEA has long been recommending) can also help bridge thecost gap between low-emission hydrogen and fossil-based alternatives.

Mt hydrogen

Potential demand for low-emission hydrogen from announced policies
and targets, private off-take agreements, commitments of international cooperation initiatives and the Net Zero Emissions by 2050 Scenario, 2030
80

Policies

70

In force

60

Targets

50

Off-take

40

Firm off-takes
Preliminary off-take30

Initiatives

20

Low

10
0

High
Policies

Off-take agreements

Initiatives

NZE 2030

NZE 2030

IEA. CC BY 4.0.
Notes: NZE = Net Zero Emissions by 2050 Scenario. In “Initiatives”, the dashed area corresponds to the range between themost conservative (low) and boldest (high) estimates of the demand that can be generated by international initiatives.

Actions from governments, international co-operation initiatives and the private sector fallvery short of the effort needed to get on track with the NZE Scenario.

Public procurement is another potentially powerful policy tool that governments
can leverage to create demand for low-emission hydrogen. Public procurement
represents on average 13-20% of GDP today, and governments can make use ofthis purchasing power to create demand for low-emission and near-zero emission
materials and products in infrastructure projects (such as steel or cement) that canbe produced using low-emission hydrogen, for example. It can also be used tocreate demand for alternative fuels (which can include hydrogen and hydrogenbased fuels) for public transport and public service (e.g. refuse collection) andother government vehicles (potentially even including applications in shipping andaviation).
A one-size-fits-all approach will not work for stimulating demand in all sectors. In
some areas, where hydrogen end-use technologies are not yet commerciallyavailable, incentives combined with innovation and demonstration efforts may be
more appropriate. In other sectors where technologies are readily available, morecoercive measures like mandates and ambitious emissions standards can drive
faster adoption.

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However, imposing regulations for the adoption of low-emission hydrogen inindustries with globally traded products, such as steel and fertilisers, requires
caution. The individual adoption of stringent regulations at the national level,
without co-ordination across countries to ensure a level playing field, can impact
the competitiveness of these industries (Figure 2.16), which could struggle to findconsumers outside of certain niche markets where consumers are willing to pay a
premium for low-emission or near-zero emission products. This may result inindustry relocation to other areas where these measures are not adopted andwhere regulations to address GHG emissions are laxer, leading to an increase inglobal emissions and, ultimately, slowing down the adoption of low-emissionhydrogen. The adoption of carbon accounting mechanisms for imported products
can help to prevent this risk, but such regulations should comply with World Trade
Organization principles to make sure that they do not constitute a barrier to global
trade.

USD/t ammonia

Domestic production cost of ammonia in Europe considering different
shares of renewable hydrogen compared with the cost of delivered
ammonia from the Middle East
900
800
700
600
500

USD 150/t CO2
USD 100/t CO2

400
300
200
100
0

No CO₂
price

UnabatedNG

With CO₂
price

Produced fromunabated NG

Producedfrom VRE

Imported from the Middle East

10%

20%

30%

Unabated NG with renewablehydrogen quota
Domestic production in Europe
IEA. CC BY 4.0.

Notes: VRE= variable renewable energy sources; Unabated NG = natural gas-based production without carbon capture,utilisation and storage. Cost of domestic production in Europe computed with a natural gas price of USD 1.5-6/MBtu, CO2
price of USD 100-150/t CO2 and renewable electricity price of USD 25-40/MWh. To ensure a minimum load of 85% for thesynthesis process when fed by renewable hydrogen, the cost of compressed hydrogen storage is included. Cost ofammonia imported from the Middle East computed with a natural gas price of USD 1.5-3/MBtu and a transport cost of
USD 20/t NH3.
Sources: Based on data from McKinsey & Company and the Hydrogen Council; NREL (2022); IEA GHG (2017).

Unilateral adoption of domestic quotas for low-emission hydrogen in supply chains
exposed to global trade without additional measures to reduce the low-emission premium
can affect the competitiveness of local industries.

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Reaching the scale-up needed to achieve climate goals requires more than justindividual action. Governments will need to work together and co-ordinate action
to unlock the necessary level of demand. Agreeing on minimum quotas for lowemission hydrogen use in sectors with commercially available end-use
technologies, or those expected to become commercial by 2030, can provide theconfidence needed in markets to significantly boost demand while helping to tackle
the risks of industry relocation and carbon leakage. The NZE Scenario can provide
guidance for establishing such quotas. The adoption of quotas for the use of lowemission hydrogen in refining, ammonia production and methanol production inline with the NZE Scenario can unlock a level of demand equivalent to 40-50% of
current government production targets and 35-65% of the potential production
from announced projects for low-emission hydrogen production by 2030 (Table
2.3). This would allow for a significant scale-up of low-emission hydrogenproduction and drive down its production cost to enable wider uptake in othersectors, thereby reducing the economic burden on governments when helping tobridge premium costs.
Low-emission hydrogen demand and share of sectoral hydrogen demand inrefining, ammonia production and methanol production in the Net Zero
Emissions by 2050 Scenario, 2030

Production of ammonia

Low-emission hydrogen
demand(Mt)
3.5

Share of low-emissionhydrogen in total sectoral
demand15%

Production of methanol

3.5

20%

Refining

7.0

20%

Application

Note: The share of low-emission hydrogen demand for ammonia is calculated excluding production equipped with CCU for
urea synthesis.

These quotas could be complemented with quotas for low-emission fuels inshipping and aviation. The European Union has taken the first step in this direction
by mandating the use of SAF (including RFNBO) as part of RefuelEU Aviation
Initiative. In the NZE Scenario, almost 15% of shipping and aviation demand is
met by low-emission fuels by 2030. These quotas will not send a direct demand
signal for low-emission hydrogen and hydrogen-based fuels, but it can be
expected that they would lead to important demands for low-emission hydrogen,nevertheless. For example, meeting just 0.5% of aviation demand with synthetic
kerosene by 2030 could lead to close to 1 Mt of hydrogen demand.
International co-operation is vital in this endeavour. Countries should leverage
existing platforms and forums, such as the Hydrogen Energy Ministerial, the Clean
Energy Ministerial Hydrogen Initiative, the G7 and the G20, to foster dialogue,
co-ordinate policies, and reach a global agreement on promoting low-emissionhydrogen adoption.

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In summary, achieving the necessary demand for low-emission hydrogen as
quickly as possible requires a comprehensive approach that combines incentives,
regulations, and international co-operation. Bold actions from governments andthe private sector are crucial to drive up demand to a level consistent with a net
zero emissions future.

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Chapter 3. Hydrogen production
Overview and outlook
Current status
Global hydrogen production reached almost 95 Mt in 2022, an increase of 3%
compared to 2021 (Figure 3.1). 37 As in 2021, production was dominated by theunabated use of fossil fuels. Natural gas without carbon capture, utilisation andstorage (CCUS) accounted for 62% of global production, while unabated coal,mainly located in China, was responsible for 21% of global production. By-producthydrogen, which is produced at refineries and in the petrochemical industry during
naphtha reforming, and often used for other refinery and conversion processes(e.g. hydrocracking, desulphurisation), accounted for 16% of global production.

Mt H₂

Hydrogen production by technology, 2020-2022
100
90

By-product
16%

80

Coal
21%

70
60

Fossil fuels w/
CCUS 0.6%

Naturalgas w/o
CCUS
62%

40
30
20

Electricity
Fossil fuels w/ CCUS

Oil 0.5%50

By-product
Coal
OilNatural gas w/o CCUS

100Electricity 0.1%

2020

2021

2022

IEA. CC BY 4.0.
Note: CCUS= carbon capture, utilisation and storage.

Global hydrogen production grew by 3% in 2022 to reach 95 Mt, but low-emission hydrogenproduction accounted for less than 1% of all production.

Low-emission hydrogen production in 2022 was less than 1 Mt (0.7% of global
production), very similar to in 2021 and almost entirely from fossil fuels withThis includes 75 Mt of pure hydrogen production and around 20 Mt H2 mixed with carbon-containing gases in methanol
production and steel manufacturing. It excludes around 30 Mt H2 present in residual gases from industrial processes used
for heat and electricity generation: as this use is linked to the inherent presence of hydrogen in these residual streams,
rather than to any hydrogen requirement, these gases are not considered here in the demand and supply of hydrogen. Byproduct hydrogen from the chlor-alkali industry is not included here.

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Chapter 3. Hydrogen Production

CCUS. 38 Production from water electrolysis continued to be relatively small, still
below 100 kt H2 in 2022, which represents 35% growth compared to the previous
year.
On a regional level, China accounted for almost 30% of global production,reflecting large domestic demands for refineries and the chemical industry. Morethan 70% of global production was in China, the United States, the Middle East,
India and Russia in 2022 (in descending order by share of production).

Outlook up to 2030
A large number of low-emission hydrogen production projects are underdevelopment according to our tracking of announced projects. Annual productionof low-emission hydrogen could reach more than 20 Mt in 2030, if all theannounced projects for hydrogen produced from water electrolysis and fossil fuelswith CCUS are realised 39 (Figure 3.2). The corresponding number in the Global
Hydrogen Review 2022 (GHR 2022) was 16 Mt H2 by 2030 40, implying a morethan 30% increase in the announced projects of low-emission hydrogenproduction within one year.
Half of the produced hydrogen from the announced projects by 2030 comes fromprojects that are today undergoing feasibility studies, followed by projects that areat very early stages (more than 45% in terms of production level). Projects thatare currently under construction or have taken a final investment decision (FID)
account for only 4% of the announced projects in terms of production. Of theseprojects, almost half are linked to existing hydrogen uses in refineries and thechemical industry (Figure 3.3). Electrolyser projects dominate among theannounced hydrogen production projects: more than 70% of low-emissionhydrogen production in 2030 could come from electrolysis. However, 55% of theannounced electrolyser projects are at early stages of development. Given thatfurther developing these projects takes time, efforts over the coming years will be
critical to ensuring that these projects can become operational by 2030.
Based on the announced projects 41 so far, in terms of production Europe andAustralia account for almost 30% and 20%, respectively, of all announced
electrolytic hydrogen projects in 2030 (Figure 3.2 and Figure 3.4).

See Explanatory notes annex for low-emission hydrogen definition in this report.
This could increase to 38 Mt H2, if projects at a very early stage of development (e.g. only a co-operation agreement among
stakeholders has been announced) are included.
40
The annual production of low-emission hydrogen in the GHR 2022, including projects at the very early stage ofdevelopment, was 24 Mt by 2030.
41
The regional discussion of announced projects includes early-stage projects.
38

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Chapter 3. Hydrogen Production

Low-emission hydrogen production by technology route, maturity andregion based on announced projects and in the Net Zero Emissions by 2050
Scenario, 2030

IEA. CC BY 4.0.
Notes: FID = Final investment decision; CCUS = carbon capture, utilisation and storage; NZE = Net Zero Emissions by
2050 Scenario; RoW = rest of world. In the left-hand side figure, the ‘2022’ label refers to operational projects, and the label
FID 2030 includes projects that are under construction and projects that have reached FID. “FID” includes projects thathave reached at least the FID, therefore under-construction projects are also included; “Feasibility” includes projects
undergoing a feasibility study; “Early stage” includes projects at very early stages, such as those in which only a cooperation agreement among stakeholders has been announced. The right-hand side figure includes operational projects
and projects that have taken FID, at advanced planning and at early stages.
Source: IEA Hydrogen Projects, (Database, October 2023 release).

Announced projects correspond to low-emission hydrogen production of 20 Mt, and 38 Mt
when early-stage projects are included, but only 4% have reached final investment decisionor are under construction.

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The front runners in Europe are Spain, Denmark, Germany and Netherlands, withthe four countries accounting for almost 55% of Europe’s electrolytic hydrogenproduction. In 2022, in the second round of funding approvals for hydrogen-related
Important Projects of Common European Interest (IPCEI), the European
Commission focused on projects boosting the supply of low-carbon and renewablehydrogen and announced the first auctions of the European Hydrogen Bank forthe end of 2023. Taking advantage of its good renewable sources for solar PV andwind, Australia’s low-emission hydrogen production via water electrolysis could
reach close to 6 Mt by 2030, with many of the projects aiming to reach export
markets. Hydrogen production from electrolysis in Latin America could reachalmost 6 Mt by 2030 based on announced projects, in particular in Chile(representing 45% of the electrolytic hydrogen production of the announced
projects in Latin America), Brazil and Argentina (representing a 30% of theelectrolytic hydrogen production). In the United States, 9 GW of electrolyser
projects were announced in the past 12 months following the announcement of
the Clean Hydrogen Production Tax Credit. In addition, significant development ofelectrolysers was realised in China. According to the latest announcements, manyGlobal Hydrogen Review 2023

Chapter 3. Hydrogen Production

projects in China are currently under construction (almost 40% in terms of
production level) and further project developments are expected for the future (Box3.1). In Africa, hydrogen production from announced electrolyser projects could
reach 2 Mt by 2030. More than 20 projects with an electrolyser capacity at or
above 100 MW have been announced in Kenya, Mauritania, Morocco, Namibia
and South Africa, with 9 projects having a planned electrolyser capacity in theorder of 1 000 MW or more.
Low-emission hydrogen production by status and by sector based on
announced projects, 2030

IEA. CC BY 4.0.
Notes: FID = Final investment decision. “Operating & FID” includes projects that are operating and that have reached atleast FID, therefore projects under construction are also included; “Feasibility” includes projects undergoing a feasibility
study; “Early stage” includes projects at very early stages, such as those in which only a co-operation agreement among
stakeholders has been announced. “Other/undefined” includes projects for which the use has not been specified, and otherhydrogen uses.

Low-emission hydrogen production projects under construction or having reached final
investment decision are often linked to existing hydrogen uses.

For hydrogen production from fossil fuels with CCUS, the United States could
account for 4 Mt by 2030, based on announced projects. Europe could reach morethan 3 Mt H2 in 2030, with projects produced primarily located in the
United Kingdom, the Netherlands and Norway.

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Production from the announced projects corresponds to more than half of the lowemission hydrogen production of almost 70 Mt H2 by 2030 envisaged in the Net
Zero Emissions by 2050 Scenario (NZE Scenario). The remaining gap of 30 Mt H2
between all the announced projects and the NZE Scenario is composed of
25 Mt H2 for production via electrolysis, and 8 Mt H2 for production from fossil fuelswith CCUS.

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Map of announced low-emission hydrogen production projects

Note: Map also includes announced projects starting after 2030.
Source: IEA Hydrogen Projects, (Database, October 2023 release).

Announced projects are so far concentrated in Europe and Australia, but a growing number
are planned in Africa, China, India, Latin America and the United States.

Electrolysis
Current status

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Water electrolysis (hereafter simply referred to as electrolysis) accounts for just
0.1% of today’s global hydrogen production, but installed capacity and the numberof announced projects have been growing rapidly in recent years. About
600 projects with a combined capacity of more than 160 GW have beenannounced since the GHR 2022. By the end of 2022, the global installed waterelectrolyser capacity for hydrogen production reached almost 700 MW, a 20%
increase compared to the previous year (Figure 3.5).

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Global electrolyser capacity by technology, 2019 – 2023, and by region, sizeand status based on announced projects by 2030

IEA. CC BY 4.0.
Notes: ALK = alkaline electrolysers; FID = final investment decision and under construction; PEM = proton exchange
membrane electrolysers; RoW = rest of world; Aus & NZl = Australia and New Zealand; 2023e = estimate for 2023
capacity, based on projects planned to start operations in 2023 and that have at least reached FID. “Other” technology
refers to solid oxide electrolysis, anion exchange membrane electrolysis or a combination of different technologies. The unit
is GW of electrical input. Only projects with a disclosed start year are included.
Source: IEA Hydrogen Projects, (Database, October 2023 release).

Global installed electrolyser capacity could reach more than 2 000 MW by the end of 2023.
Based on announced projects, 175 GW could be reached by the end of the decade, andeven 420 GW including early-stage projects.

Plants with a combined capacity of 120 MW started operations in 2022. This is
only roughly half of the new capacity additions seen in 2021; however, 2021 was
an exceptional year that included commissioning of a single project in China witha capacity of 150 MW. China is likely to again lead the list of the largest
electrolysers being commissioned in 2023, with a 260 MW plant by Sinopec
having started operations in July 2023, and more than 550 MW of projects underconstruction. Based on projects that have at least reached FID or are underconstruction, installed global capacity could more than triple to 2 GW by the endof 2023 (equivalent to about 0.2 Mt hydrogen production), assuming all projects
are realised as planned, though several projects are suffering from delays.

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Alkaline electrolysers accounted for 60% of the installed capacity by the end of2022, followed by proton exchange membrane (PEM) electrolysers with around30%. Based on announcements, this is expected to change in the coming years,
with PEM gaining market share over alkaline electrolysers, although many future
projects have not yet decided or disclosed which electrolyser technology will be
deployed. Solid oxide electrolysers (SOEC) represent less than 1% of installedcapacity today. In terms of geographical distribution, China and Europe eachGlobal Hydrogen Review 2023

Chapter 3. Hydrogen Production

accounted for one-third of the installed capacity at the end of 2022, while for theUnited States and Canada the combined share was 10%.

Rapidly growing number of announced projects
Based on announced projects, global installed electrolyser capacity could reach
175 GW by 2030, an increase of 30% compared to the announcements in the
GHR 2022. The capacity in 2030 increases to 420 GW when projects at earlystages of development 42 are also taken into consideration (Figure 3.6).
Electrolyser capacity in 2030 based on current announcements by status,and progress since the Global Hydrogen Review 2022

IEA. CC BY 4.0.
Notes: GHR = Global Hydrogen Review; FID=final investment decision; RoW = rest of the world. “FID” includes projects
that are under construction and projects that have reached FID; “Early stages” includes projects at concept status, such as
those in which only a co-operation agreement among stakeholders has been announced. The lower number in the capacity
range excludes the “Early stage” projects. The percentage shares include “Early stage” projects. Only projects with adisclosed start year are included.
Source: IEA Hydrogen Projects, (Database, October 2023 release).

Based on all announced projects, electrolyser capacity could reach 420 GW by 2030, butmore than half of the projects are at early development stages.

Europe could be home to one-third of this capacity, followed by Latin America andAustralia with 20% each one. However, recent progress in China (Box 3.1) andthe impact of the Inflation Reduction Act (IRA) in the United States are likely tochange this picture, with these two countries expected to take a larger share of
total installed capacity than can be seen in the announced projects today.
The realisation of all announced projects is still highly uncertain, as less than 4%of the capacity of all announced projects has reached FID or is under construction.
Almost 40% of the capacity is undergoing or has completed a feasibility study.
e.g. projects for which only a co-operation agreement among stakeholders has been announced.

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Since the publication of the last edition of the Global Hydrogen Review in
September 2022, more than 3.8 GW of electrolyser projects have reached FID or
started construction. This is mainly due to construction starting on the NEOM
Green Hydrogen Project in Saudi Arabia, which is planned to go online in 2026,
and is the biggest project in the world to have started construction. Recently,
financial closure has been achieved for the Green Hydrogen Project in Oman,
expected to produce 100 kt of ammonia per year, and planned to have a capacityof 3.5 GW once at full scale.
The scale-up in installed electrolyser capacity is also accompanied by a trend
towards larger projects being announced. While the average size of electrolyser
plants is about 12 MW today, it could grow to several hundreds of MW in few years
and to 1 GW by 2030, with GW-scale projects representing more than 75% ofannounced capacity for 2030.

Electrolyser supply chains
By the end of 2022, the available manufacturing capacity publicised by electrolyser
manufacturers reached as high as 13 GW/yr, half of which was in China, to servea rapidly growing domestic market, and a further one-fifth in Europe (Figure 3.7).
However, output to date has been much lower than this: we estimate it at justabove 1 GW/yr in 2022 based on water-splitting projects entering operation andthe historical market for chlor-alkali electrolysers, which continue to dominate
factory output. Nonetheless, there appears to be sufficient capacity to realise the
1.1 GW of projects under construction for delivery in 2023 and 5 GW for 2024.
Given the large gap between current output and stated manufacturing capacities
by manufacturers, it also seems feasible that manufacturers could ramp up output
by several gigawatts in two to three years if they receive orders from projects
seeking to take advantage of financial incentives in North America and Europe.

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Based on companies’ announcements, global electrolyser manufacturing capacity
could reach 155 GW/yr by 2030, with one-quarter of the manufacturing capacity
located in China, one-fifth each in the United States and Europe, and 6% in India.
However, 20% of the expansion plans by 2030 have been announced without adisclosed location, which means that the geographical distribution could change,for example if influenced by policy support to stimulate local demand and local
manufacturing (such as the IRA in the United States, the Net Zero Industry Act inthe European Union or the incentive schemes for electrolyser manufacturing inIndia).

Global Hydrogen Review 2023

Chapter 3. Hydrogen Production

Electrolyser manufacturing capacity by region and technology according toannounced projects and in the Net Zero Emissions by 2050 Scenario, 20212030

IEA. CC BY 4.0.
Notes: ALK = alkaline electrolyser; NZE = Net Zero Emissions by 2050 Scenario; PEM = proton exchange membraneelectrolyser; RoW = rest of the world; SOEC = solid oxide electrolyser. The manufacturing capacity for 2023 is an estimate
including facilities under construction that are planned to be operational by the end of 2023.
Source: IEA analysis based on announcements by manufacturers and personal communications.

Electrolyser manufacturing capacity almost doubled between 2021 and 2023. Announced
plants could cover 90% of the needs in the Net Zero Emissions by 2050 Scenario.

Three-quarters of manufacturing capacity today is for alkaline electrolysers – ofwhich 70% is in China – while PEM and SOEC account for 2 GW/yr and
1.5 GW/yr, respectively. Part of the manufacturing capacity for these twotechnologies, however, is used to produce fuel cells in the same factories, given
the technology similarities, which means that the capacity used for electrolysers
may be lower. By 2030, PEM manufacturing capacity could grow to reach almost
one-quarter of the global capacity, with the share of alkaline electrolysers declining
though still dominant at 54%.
Only 8% of the announced manufacturing capacity has reached FID or is underconstruction. About 30% of the overall announced manufacturing capacity is an
expansion of plants that already exist, or a later expansion of new manufacturing
plants to be built, announced without a specific target year. Since planned
expansions of existing plants often have shorter lead times compared to building
a greenfield plant, companies may take more time to decide whether to move
forward with these plans based on future demand developments. This adds further
uncertainty on whether announced expansions will eventually be realised.

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Overall, the announced manufacturing capacities of 155 GW/yr by 2030 represent
90% of the 170 GW of manufacturing capacity envisaged in 2030 in the NZE
Scenario.

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Chapter 3. Hydrogen Production

Global electrolyser capacity from announced projects, and cumulative
output from announced manufacturing capacity compared to the Net Zero
Emissions by 2050 Scenario, 2025-2030

IEA. CC BY 4.0.
Notes: FID = final investment decision; NZE = Net Zero Emissions by 2050 Scenario. The manufacturing output has been
computed assuming an 85% utilisation rate of the cumulative announced manufacturing capacity, and one year between
the full-scale operation of the manufacturing facility and the installation of the manufactured electrolyser. Manufacturing
capacity announced without a disclosed target year has been allocated to 2030.
Source: IEA analysis based on announcements by manufacturers and personal communications, and on IEA Hydrogen
Projects, (Database, October 2023 release).

Announced manufacturing capacity could be sufficient to support the deployment ofannounced electrolyser projects by 2030.

If all the announcements from manufacturers are realised on time and at scale,the potential output of the electrolyser manufacturing facilities would be sufficient
to support the deployment of all the announced production projects by 2030
(Figure 3.8). If only the announced capacity that has reached financial closure(FID) or is under construction (i.e. is committed) is considered, the potential output
would be not only sufficient to satisfy the production projects that have reached
FID, but is such that by 2030 it could also cover the demand of electrolysers fromproduction projects currently undergoing feasibility studies. The imbalance
between committed production projects and manufacturing capacity could,
however, mean that if production projects for 2030 that are currently at feasibility
study stage progress more slowly than planned, this would result in 2030 in a low
utilisation rate of the committed manufacturing plants.

The cost of electrolytic hydrogen

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The installed cost of electrolysers has increased significantly in the past few years
due to increases in materials and labour costs. The capital cost for an installed
electrolyser (including the equipment, gas treatment, plant balancing, andGlobal Hydrogen Review 2023

Chapter 3. Hydrogen Productionengineering, procurement and construction cost) ranges between USD 1 700/kW
and USD 2 000/kW (for alkaline and PEM respectively, based on data fromindustry and project developers), a year-on-year increase of about 9% comparedto the capital cost range observed in 2021. However, in Europe, some project
developers have observed even higher inflation values, up to 40% in certain
cases. Alkaline electrolysers manufactured in China are, in terms of CAPEX, muchcheaper than those manufactured in Europe or North America, at around USD
750-1 300/kW for an installed electrolyser, but could be as low as USD 350/kW
according to some sources. The cost figure reflects technical standards andconditions in China. For exports, adjustments to be made to Chinese electrolysers
to comply with standards in other countries may lead to higher costs. The inflationon the CAPEX of the electrolysers could translate into a 20% cost increase in thelevelised cost of hydrogen production (assuming all other parameters remain
constant), as the CAPEX today represents the main cost component.
Recent inflation and increases in labour cost have had a considerable impact on
projects under development, whose first cost estimates have been revised
upwards in several cases (see Chapter 5 Investment, finance and innovation). The
cost of Saudi Arabia’s NEOM Green Hydrogen project has risen from USD 5 billion
to USD 8.5 billion, according to a statement from the beginning of 2023, due to
inflation, supply chain-related cost increases, and an enlargement of the project
scope to include, for example, transmission lines and some other infrastructure
equipment. Similarly, the German Bad Lauchstädt Energy Park project has seen
costs rise by 50% from the first estimate.
Based on the deployment of electrolysers in the next decade envisaged in current
announcements, the capital cost could decrease due to economies of scale andmass production. 43 Based on capacity deployment of the announced projects, thecost of an installed electrolyser could go down compared to 2023 by 50% by 2025
and by 60% by 2030, reaching about USD 720-810/kW (Figure 3.9). Based on theelectrolyser installations required to meet needs in the NZE Scenario, the cost
reduction could reach 65-70% by 2030, leading to below USD 600/kW installed
cost. Such a cost reduction alone could halve the share of CAPEX in the levelised
cost of hydrogen (assuming all the other parameters remain constant) to around25%.

To assess the cost reduction, a learning rate of 18% has been used for the electrolyser stack, representing about half ofthe system cost, and between 5-12% for the other components and the balance of plant.

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Evolution of electrolyser installed capital costs based on deployment fromannounced projects and in the Net Zero Emissions by 2050 Scenario, 20212030, and the share of capital cost in the levelised cost of hydrogenproduction

IEA. CC BY 4.0.
Notes: CAPEX = capital expenditure; CF = capacity factor; LCOH = levelised cost of hydrogen; NZE = Net Zero Emissions
by 2050 Scenario; y-o-y = year-on-year variation. Left-hand side chart: “Projects” refers to the capacity deployed according
to announced projects, which is 55 GW by 2025 and 175 GW by 2030; in the case of the NZE Scenario, this is 590 GW by2030. The learning rate for the electrolyser stack is 18%, while for the other components it is 5-12%. Right-hand side chart:
electricity cost of USD 20/MWh, electrolyser efficiency of 69% lower heating value, 8% cost of capital.
Sources: IEA analysis based on data from McKinsey & Company and the Hydrogen Council, communications withcompanies and the IEA Hydrogen Projects, (Database, October 2023 release).

While electrolyser CAPEX increased in 2023 by 15% compared to 2021, CAPEX could be
reduced by 60-70% by 2030.

Box 3.1

Electrolysis development in China

China currently produces more hydrogen than any other country around the world,with around 33 Mt produced in 2020, mainly from coal and natural gas, but recently
significant growth has been realised in the production of hydrogen through waterelectrolysis. By 2022, 30% of global electrolyser capacity was installed in China.
Since the beginning of 2023, China has made significant progress on hydrogenproduction through water electrolysis, and by the end of the year, the installed
electrolyser capacity is expected to reach 1.1 GW, which would represent 50% of
the global share. As of September 2023, half of this expected capacity is alreadyin operation, while the rest is under construction.

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Besides the strong growth in total installed electrolyser capacity, one of the world’s
largest electrolyser plants is going to be commissioned by the end of 2023; theChifeng Ammonia Demonstration Project, with a yearly hydrogen production of
24 200 t H2/yr (around 140 MW of electrolyser capacity). By 2024, 8 electrolytichydrogen projects, which are currently under construction with electrolyser

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Chapter 3. Hydrogen Production

capacity greater than 125 MW are planned to start their operation in China next
year. The electrolytic hydrogen project planned by Sinopec at its chemical facilityin Ordos is one of the 8 hydrogen projects that are under construction, and it could
be among the largest in the world, with 30 kt of annual hydrogen production(corresponding to about 350 MW of electrolysis, assuming a 50% capacity factor).
Project announcements for electrolyser developments in China represent
significant growth in the coming years, following wider global trends. Compared to2023, the expected installed electrolyser capacity in China is set to triple to 3.3 GW
by 2024, and to reach almost 5.4 GW by 2025.
Electrolyser capacity in China

IEA. CC BY 4.0.
Notes: FID/Construction = projects that have reached final investment decision (FID) or are under construction.
Electrolyser capacity from 2023 to 2025 includes announced projects under construction or that have reached FID,
assuming they will start operation based on schedule.
Source: IEA Hydrogen Projects, (Database, October 2023 release).

Furthermore, the average project size is growing fast: the number of projects witha capacity in the range of 100-500 MW is increasing in China. About 60% of theannounced projects in 2023 are included in this category. An example is the Kuqa
project from Sinopec, with a capacity of 260 MW and having started operation inJune 2023. Larger-scale facilities of 500-1 000 MW are planned to be installedfrom 2025 onwards. By that year, giga-scale projects will represent almost 20% of
the capacity that has at least reached FID. Besides the progress in electrolyser
deployment, Chinese companies have also developed larger and more efficientelectrolysers. In December 2022, Peric Hydrogen Energy Technologies presented
the largest single unit hydrogen alkaline electrolyser, with a hydrogen capacity of
2 000 Nm3/h or about 9 MW 44, and Longi Hydrogen unveiled in February 2023 a
new alkaline model that – with a direct current electricity consumption of
4 kWh/Nm3 (corresponding to 44.5 kWh/kg H2) – is more efficient than mostelectrolysers on the market.

Assuming an electricity demand of 52 kWh per kg H2 or 4.7 kWh per Nm3 H2.

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Fossil fuels with CCUS
Sixteen hydrogen facilities 45 around the world are equipped with CCUS, capturing
around 11 Mt CO2 per year. Most facilities are retrofitted hydrogen production
units in refining and fertiliser production in North America, with first operation
dating from the early 1980s. Only around 1 Mt of the captured CO2 is injected in
dedicated storage (at the Quest facility in Canada), and the remainder is injected
for enhanced oil recovery (EOR) or used in applications such as the food andbeverage industry or for boosting yields in greenhouses. Moreover, most facilities
were retrofitted with partial capture, meaning only process emissions which havea high concentration of CO2 are captured (Box 3.2). This results in only around
0.6 Mt of H2 production qualifying as low-emission out of the 0.8-1.2 Mt
produced 46, with 0.35 Mt from natural gas reforming (4 Mt CO2 per year captured),and 0.25 Mt from coal and oil gasification (7 Mt CO2 per year captured).
Hydrogen is one of the leading applications in CCUS deployment plans. More than
one-quarter of CO2 capture capacity under construction or in planning involveshydrogen or ammonia production across a range of applications, including
dedicated production, refineries, fertiliser and iron and steel.
In the United States, while CO2 demand for EOR was the primary driver for the
first plants to capture emissions, the 45Q tax scheme first introduced in 2008 andincreased through the IRA in 2022 up to USD 85 per tonne of CO2 stored (around
USD 0.80/kg H2 47), and up to USD 60 per tonne of CO2 used (around
USD 0.55/kg H2), continues to support development, with more than 30 hydrogenprojects with CCUS currently in planning. In Canada, the sector is benefiting fromboth CCUS and “clean” hydrogen investment tax credits, as well as funding forcarbon storage hubs. In Europe, the United Kingdom is leading gas-CCUS
hydrogen project development, supported by government-funded industrial
decarbonisation programmes, followed by the Netherlands and Norway. In total,
Europe could account for around 40% of low-emission production by 2030. 48
If all announced projects are realised, low-emission hydrogen production fromfossil fuels with CCUS could increase almost fifteen-fold from around 0.6 Mt per
year in 2022 to around 8 Mt per year by 2030, with potential to increase to
10 Mt H2/yr if accounting for very early-stage projects (Figure 3.10). The vast
majority comes from gas reforming, and less than 1 Mt from coal or oil gasification.

Only projects with a capture capacity above 100 000 t CO2 per year are considered here.
Low-emission hydrogen production is estimated from the plant CO2 capture capacity, and therefore only includes hydrogenproduction for which CO2 is captured and stored. The range of total hydrogen production is estimated assuming a 40-60%
overall unit capture rate for gas-based production and 90-95% for coal and oil-based production (Box 3.2), including projects
capturing CO2 for utilisation.
47
Assuming gas-based production, 0.9105 kg CO2 emitted per Nm3 H2 and 90% capture rate.
48
This could decrease to one-third, if projects at a very early stage of development (e.g. only a co-operation agreement
among stakeholders has been announced) are included.
45

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This is still around10 Mt per year short of the circa 17 Mt of low-emission hydrogenproduction from fossil fuels with CCUS needed in 2030 in the NZE Scenario.
Production of low-emission hydrogen from fossil fuels with carbon capture
utilisation and storage, historical and from announced projects, 2018-2030

IEA. CC BY 4.0.
Notes: CCUS = carbon capture, utilisation and storage; FID = final investment decision. FID refers to projects underconstruction or which have at least taken FID. Only includes projects with an announced operating date before 2030,
assuming they will start operation on schedule.
Source: IEA Hydrogen Projects, (Database, October 2023 release).

Despite recent momentum, planned carbon capture, utilisation and storage-basedhydrogen production remains low, and is concentrated in North America and Europe.

Projects under development are likely to need further policy and financial support
to come to fruition. To date, only 6% of planned production for 2030 is currently
under construction, though 2 of the 11 FID taken for CCUS-based projects in 2022
were for merchant hydrogen or ammonia production, which could suggest higher
investor confidence in the sector.

Box 3.2

Can high plant capture rates be achieved?

Along with low methane emissions from fuel supply, high plant capture rates are
essential to minimise residual emissions from fossil fuel-based hydrogen-CCUS
production routes, or maximise CO2 removal from biomass-based production (seesection Emerging production routes below).

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While capture efficiencies as high as 99% can be achieved with marginal additionalenergy input, overall plant capture rates also depend on process configuration andpoint of capture. Most operating steam methane reforming (SMR) facilities today
operate at partial capture: only the CO2 in the shifted syngas is captured, and notGlobal Hydrogen Review 2023

Chapter 3. Hydrogen Production

the CO2 resulting from fuel combustion from the reformer furnace. This typicallyresults in overall plant capture rates between 40% and 60%.
Process modelling studies have shown that plant capture rates of 96% and up to
99% can be achieved in a SMR plant by burning the unconverted off-gas withnatural gas in the reformer furnace, and capturing CO2 from the furnace exhaust,
at levelised costs 50-60% higher than unabated SMR. In the autothermal reformer(ATR) process, most of the process CO2 is available for capture in the shiftedsyngas, resulting in overall capture rates between 93-98%. The gas partial
oxidation (POx) process developed by Shell is reported to yield overall plant
capture rates up to 99%. Plant capture rates between 94% and 98% have also
been simulated for coal gasification. To date, no operational plant has achieved
these levels of capture, but two ATR projects targeting 90-95% capture are
currently under construction in North America (see Chapter 5 Investment, financeand innovation).

Supply chain challenges for fossil-based hydrogenproduction with CCUS
Large-scale hydrogen production with CCUS does not face the same supply chain
manufacturing constraints as electrolytic hydrogen. While large-scale hydrogenplants require mass-manufactured equipment such as compressors, pumps, fans,heat exchangers, separation columns and storage tanks, the manufacturing ofthese devices can benefit from synergies with other industries in which thisequipment has been used for decades, notably oil and gas, chemicals and power
generation. Producers can therefore access a large and diverse pool of suppliers
located in different regions with well-established manufacturing facilities andsupply chains.

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Plant and infrastructure development lead times for the plant are likely to be themain bottleneck. Given that most operating plants are capital-intensive first-of-akind facilities, project lead times have historically been long, ranging from 1.5 to10 years, with an average of around 4 years. Permitting and financing often
constitute an important hurdle, taking on average almost as long as construction.
Projects that require the development of new CO2 management infrastructure forCO2 transport and storage also tend to have longer lead times, due to long leadtimes associated with developing and permitting new storage resources, or thedifficulty of co-ordinating infrastructure with capture developments. This was thecase of the Alberta Carbon Trunk Line project, for example, which took around 10
years to reach commissioning.

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Siting new hydrogen facilities close to industrial clusters can leverage local
hydrogen demand and help share construction costs for CO2 transport and storage
infrastructure with other emitters, which could cut overall project lead times once
infrastructure is in place. Around two-thirds of planned CO2 capture capacity forhydrogen production are being developed as part of CO2 transport and storage
hubs catering for multiple industrial sources. Co-ordination of capture andinfrastructure developments within these CCUS hubs, and design of legal andregulatory frameworks which are fit for purpose, will be crucial to avoid delays.

Comparison of different production routes
Hydrogen production costs
The cost of hydrogen production depends on the technology and cost of theenergy source used, which usually has significant regional differences. Prior to theglobal energy crisis sparked by Russia’s invasion of Ukraine, the levelised cost ofhydrogen production from unabated fossil-based sources was in the range of
USD 1.0-3.0/kg H2 (Figure 3.11). In 2021, these production routes offered thecheapest option to produce hydrogen, compared with the use of fossil fuels with
CCUS (USD 1.5-3.6/kg H2) or the use of electrolysis with low-emission electricity(USD 3.4-12/kg H2).

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The cost of hydrogen produced using electrolysis is driven by the capital cost ofelectrolysers and the cost of the electricity used to power the electrolyser. As
discussed above, the capital costs of electrolysers are set to decrease significantlyin the short term, thanks to economies of scale and further technology innovation.
The cost of renewable electricity has already decreased sharply in the last decade(80% reduction in the cost of solar modules between 2010 and 2020). The recent
increases in commodity prices may slow down further cost declines in the nearterm but are unlikely to stop them altogether over the longer term. If large-scale
deployment takes place as envisaged in the NZE Scenario, the production costsof electrolytic hydrogen using electricity from solar PV could fall to USD 1.6/kg H2
by 2030 in regions with excellent solar irradiation, such as Africa, Australia, Chile,
China and the Middle East. While solar PV-based electrolysis could become thecheapest way to produce hydrogen by the end of the decade, locations withexcellent wind resources (offshore or onshore) could also see a significant drop in
the levelised cost of hydrogen, reaching values under USD 2.1/kg H2 in the northwest European region and under USD 2.3/kg H2 in the United States.

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Chapter 3. Hydrogen Production

Levelised cost of hydrogen production by technology in 2021, 2022 and in
the Net Zero Emissions by 2050 Scenario in 2030

IEA. CC BY 4.0.
Notes: CCUS = carbon capture, utilisation and storage; PV = photovoltaic; NZE= Net Zero Emissions by 2050 Scenario in2030. Solar PV, wind and nuclear refer to the electricity supply to power the electrolysis process. NZE values refer to 2030.
Natural gas price is USD 5-15/MBtu for 2021, USD 6-36/MBtu for 2022 and USD 1-8/MBtu for 2030 NZE. Coal price is
USD 40-180/tonne for 2021, USD 50-360/tonne for 2022 and USD 30-70/tonne for 2030 NZE. Solar PV electricity cost is
USD 22-120/MWh for 2022, USD 13-80/MWh for 2030 NZE, with capacity factor of 12-35%. Onshore wind electricity cost
is USD 25-130/MWh for 2022, USD 25-120/MWh for 2030 NZE, with capacity factor of 15-53%. Offshore wind electricity
cost is USD 50-225/MWh for 2022, USD 30-125/MWh for 2030 NZE, with capacity factor of 32-67%. The cost of capital is6%.
The dashed area represents the CO2 price impact, based on USD 15-140/t CO2 for the NZE Scenario. More technoeconomic assumptions will be made available in a separate forthcoming Annex.
Sources: IEA analysis based on data from McKinsey & Company and the Hydrogen Council; IEA GHG (2014); NETL
(2022); IEA GHG (2017); E4Tech (2015); Kawasaki Heavy Industries.

With natural gas prices subsiding from their 2022 highs, renewable hydrogen could
become competitive with hydrogen from fossil fuels by 2030.

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Electricity costs are a major component of the cost of hydrogen produced fromelectrolysis, accounting for 25-45% of total levelised cost from solar PV today. Low
electricity costs and high capacity factors for the electrolyser favour lower
electricity cost shares and lower overall hydrogen production costs, while
reductions in electrolyser CAPEX increase the share of electricity costs in the totalhydrogen production costs (Figure 3.9). Bringing down the cost of low-carbon
electricity will be critical to reach low hydrogen production costs from electrolysis.
Electricity costs of USD 20/MWh are equivalent to hydrogen costs of USD 1/kg H2(at 70% efficiency, lower heating value) – when leaving out any CAPEX and fixed
OPEX costs for the electrolyser. Taking into account CAPEX and fixed OPEX,
electricity costs would need to be even lower, as illustrated in Figure 3.12, in whichhydrogen production costs from solar PV at locations with excellent solar
conditions could fall to USD 1.6/kg H2 by 2030, assuming drastic cost reductions
for electricity to USD 13/MWh, that align with the NZE Scenario. Even withhydrogen costs approaching USD 1/kg H2, it is important to keep in mind thathydrogen does not become a low-cost fuel: a hydrogen price of USD 1/kg H2,

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when expressed in natural gas price units, translates into USD 8.8/MBtu, or inelectricity price units into USD 30/MWh.
Levelised cost of hydrogen production based on different renewableelectricity prices and on different costs of capital in the Net Zero Emissions
by 2050 Scenario, 2030

IEA. CC BY 4.0.
Notes: NZE = Net Zero Emissions by 2050 Scenario; WACC= weighted average cost of capital. Left-hand side figure:points represent electricity and hydrogen production costs for different regions around the world, taking local renewable
resource conditions into account. The cost of capital is 6%. Right-hand side chart: the capacity factor for solar PV is 28%,
for onshore wind is 40% and for offshore wind is 56%. Techno-economic assumptions will be made available in a separate
forthcoming Annex.

Renewable electricity costs and the cost of capital are key factors in hydrogen production
costs. Doubling cost of capital from 5 to 10% increases production costs by almost 40%.

Hydrogen production from renewable electricity is a capital-intensive production
route. Upfront investments are not only required for the electrolyser, but also forrenewable electricity generation. For hydrogen production using electricity fromsolar PV, a 1%-point increase in the weighted average costs of capital (WACC)
results in 2030 in the NZE Scenario roughly in a cost increase of around
USD 0.2/kg H2. In the current context of growing interest rates, increasing WACC
can have a profound impact on the economic viability of projects and theirhydrogen production costs. For example, a WACC increase from 5% to 10%
results in an almost 40% increase in hydrogen production costs, depending on the
renewable electricity source. For project developers in emerging and developing
economies in particular, access to financing can be a major barrier, reflected in a
WACC that is often higher compared to advanced economies. An increase in
WACC from 6% to 15% for example would increase the cost of hydrogenproduction from solar PV by more than 70%. 49

The 6-15% range reflects the costs of capital being observed for utility-scale solar PV projects in emerging markets anddeveloping economies.

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49

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Box 3.3

Chapter 3. Hydrogen Production

Sizing renewable electricity for electrolytic hydrogen production

Many electrolyser projects for hydrogen production include dedicated renewableelectricity plants, often solar PV, onshore or offshore wind. For example, the NEOM
project under construction in Saudi Arabia plans to use 4.6 GW of solar PV andonshore wind capacity to provide electricity for a more than 2 GW electrolyser, withthe hydrogen being used in a Haber-Bosch synthesis process for ammonia
production. The investments for renewable electricity generation often account forthe majority of the overall investments of a hydrogen project in which an
electrolyser is combined with a dedicated renewable electricity supply.
The design of such a project, in particular in terms of the installed electrolyser
capacity and the renewable generation capacity, depends on various factors. If the
produced hydrogen is used in further synthesis processes, such as the HaberBosch process for ammonia synthesis, a relatively stable hydrogen supply andhigh full load hours for the synthesis process are desirable. This can be achievedby a larger capacity ratio of renewable generation to the electrolyser (and thedesign also depends on the overall economics in combination with othermeasures, such as adding hydrogen storage or also using grid electricity for someof the time, if available). In such a configuration, part of the renewable electricity,
if not stored in batteries or used otherwise, may be curtailed, but overall, such adesign can help to increase the overall full load hours of the electrolyser and thesynthesis process. Similarly, relatively low CAPEX costs for renewable generation
capacity in comparison to the electrolyser CAPEX can favour a larger capacity ratioof renewable capacity to electrolyser. Relatively low CAPEX for the electrolyser
and the synthesis process (or relatively high renewable CAPEX) may favour aconfiguration with a lower capacity ratio of renewable generation to theelectrolyser, i.e. overall, the benefits of lower investments in renewable capacityoffset the lower utilisation of the electrolyser (and a potential downstream synthesis
process).

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These relationships are illustrated for the case of production of ammonia, using a
Haber-Bosch synthesis process, an electrolyser and solar PV for the electricity
supply as well as battery storage and hydrogen storage tanks. In the base casewith a solar PV CAPEX of USD 600/kW and an electrolyser CAPEX of
USD 615/kW, a solar PV to electrolyser capacity ratio of 1.8 results in the lowest
ammonia production costs. Halving the solar PV CAPEX leads to an optimal
design with a capacity ratio of 2.9, while the capacity factor of the Haber-Boschsynthesis process increases from 82% to 84%. With lower solar PV costs, the cost
curve also becomes flatter, i.e. with lower solar PV costs, the impact of theelectricity costs on the ammonia production costs becomes less pronounced. If thesolar PV CAPEX increases to USD 900/kW, the optimal solar PV to electrolyser
capacity ratio decreases to 1.5 and the capacity factor of the Haber-Boschsynthesis to 80%.

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Chapter 3. Hydrogen Production

Combining solar PV and onshore wind can be another way to increase the capacity
factor of the electrolyser and the Haber-Bosch synthesis. Including onshore windin the base case increases the capacity factor of the Haber-Bosch synthesis to87% compared to 82% when using only solar PV as the renewable electricity
option. The ammonia production costs decline by 4%. In the case that both solar
PV and onshore wind are available, higher solar PV CAPEX does not necessarily
lead to a lower renewable to electrolyser capacity ratio. At the location considered
here, renewable generation shifts with higher solar PV CAPEX to onshore wind,
but also to a replacement of grid electricity by onshore wind, so that the overall
renewable to electrolyser capacity with higher solar PV CAPEX is actually larger
than in the base case for solar PV CAPEX.
Ammonia production cost from solar PV and from solar PV and onshore
wind hybrid systems

IEA. CC BY 4.0.
Notes: LCOA = levelised cost of ammonia production; CAPEX = capital expenditure.
The analysis is based on the following assumptions: solar PV CAPEX is USD 600/kW in the base case, USD 300/kW inthe low solar PV CAPEX case and USD 900/kW in the high solar PV CAPEX case, reflecting the regional CAPEX range
for utility-scale solar PV in the Net Zero Emissions by 2050 Scenario in 2030. CAPEX for onshore wind is kept constantat USD 1 270/kW. CAPEX for electrolysers is USD 615/kW, for battery storage USD 180/kWh and for hydrogen storage
tanks USD 350/kg H2. Firm grid electricity is available at costs of USD 100/MWh in addition to renewable electricity
available for the electricity needs of the Haber-Bosch synthesis. Location with annual average capacity factor of 26% forsolar PV and 40% for onshore wind. Further techno-economic assumptions will be made available in a separate
forthcoming Annex.
Analysis was done by determining the cost optimal configuration for given technology costs, hourly solar PV and onshore
wind capacity factors and given renewable to electrolyser capacity ratios. The left figure only considers solar PV as arenewable electricity source, while the right figure considers hybrid systems of solar PV and onshore wind.

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Various regions around the world have excellent renewable resource conditions
to produce hydrogen from renewable electricity at low costs (Figure 3.13).

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Chapter 3. Hydrogen Production

Hydrogen production costs and share of solar PV from hybrid solar PV andonshore wind systems, 2030

Notes: LCOH = levelised costs of hydrogen production. For each location, production costs are determined by optimising
the mix of solar PV, onshore wind, electrolyser, battery and hydrogen storage capacities, resulting in the lowest costs.
Onshore wind has been excluded in permafrost regions due to more challenging requirements for the foundation of windturbines, so that solar PV is the sole hydrogen production option, which explains the high solar shares in these regions.
Based on an electrolyser CAPEX of USD 615/kW, regional solar PV and onshore wind CAPEX reflecting 2030 values in
the Net Zero Emissions by 2050 Scenario and a weighted average cost of capital of 6%.
Source: Analysis by IEK-3, Research Centre Jülich using the ETHOS model suite.

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Various regions around the world have excellent renewable resources for low-costhydrogen production. Costs could fall below USD 1.5 kg H2 by 2030.

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Chapter 3. Hydrogen Production

If these low-cost renewable resources exceed the amounts needed domestically,
these resources can be an opportunity for countries to export the renewableelectricity in the form of hydrogen or products using hydrogen (e.g. steel,ammonia) to regions that have demand but limited potential for low-emissionhydrogen production. The overall costs and thus the competitiveness of theseexports will not only depend on the hydrogen production costs, but also thetransport costs, as illustrated in Box 4.1 in Chapter 4 Trade and infrastructure.
Using a single renewable resource, such as solar PV or offshore wind, can be thecheapest option for renewable hydrogen production in many locations. A hybrid
approach that combines solar PV and onshore wind, for example, can lead tohigher CAPEX costs, but results in higher full load hours of the electrolyser, suchthat this combination can result in the lowest production costs at some locations.
his holds true even for some excellent solar PV locations in Northern Africa andAustralia as long as wind capacity factors are sufficiently high. Combining solar
PV with wind reduces the hydrogen production costs despite higher costs for windelectricity. The higher full load hours realised by this hybrid approach can also
benefit the economics and operation of subsequent synthesis processes, such as
ammonia production. Other options to increase the full load hours of theelectrolyser also exist, such as oversizing the renewable generation capacity, as
discussed in Box 3.3.
Levelised cost of hydrogen production with carbon capture, based on
different natural gas prices and on different costs of capital in the Net
Zero Emissions by 2050 Scenario, 2030

IEA. CC BY 4.0.
Notes: LCOH = levelised cost of hydrogen; MBtu = million British thermal units; TTF = Title Transfer Facility; WACC=
weighted average cost of capital. Weekly average historic natural gas closing prices for TTF in Europe and Henry Hub in
the United States have been used to calculate the hydrogen production cost from natural gas with carbon capture,utilisation and storage (CCUS) in the left-hand side figure. The capture rate is 93%.
Sources: Based on data from McKinsey & Company and the Hydrogen Council; NETL (2022); IEA GHG (2017).

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Natural gas prices are the key cost factor for hydrogen production from natural gas with
CCUS. Doubling the weighted average cost of capital from 5% to 11% increases the
production costs by around 3% to 17%.

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Chapter 3. Hydrogen Production

The cost of producing hydrogen from natural gas with CCUS is strongly influenced
by the natural gas price and its fluctuations (Figure 3.14). Gas price levels of up
to USD 70/Mbtu, as seen in Europe in 2022 following the Russian invasion of
Ukraine, mean that hydrogen from natural gas becomes a very expensive option.
Since then, natural gas prices have fallen in Europe to an average of
USD 14/MBtu over the first months of 2023. At this gas price, hydrogen production
from natural gas with CCUS would cost around USD 3/kg H2. In the United States,
average gas prices in the first half of 2023 have been much lower, at
USD 2.7/MBtu, corresponding to a cost of hydrogen production with CCUS of
USD 1.2/kg H2. For hydrogen production from natural gas with CCUS, reachingproduction costs of USD 1/kg H2 requires the gas price to be below USD 1/MBtu.
The impact of the WACC on the cost of hydrogen production from natural gas with
CCUS is much lower than for renewable hydrogen produced with electrolysis,given that the cost of production from electrolysis using renewable electricity isalmost entirely based on CAPEX, whereas for production from natural gas the
CAPEX share is 5-30%. A 2%-point WACC increase from 3% to 5% results in acost increase of around USD 0.1/kg H2. A doubling of the WACC from 5% to 11%
results in a cost increase of 3-17%, depending on the gas price and the impact of
WACC changes being larger at lower gas prices.

Emissions intensity of hydrogen production routes
The emissions associated with hydrogen production can vary significantly
between production routes, depending on the fuel, technology and the rate at
which carbon capture and storage (CCS) is applied. In addition to direct emissions
occurring in the production of hydrogen, indirect emissions from the production,
conversion and transport of the required input fuels, such as natural gas orelectricity, can affect the overall emissions associated with hydrogen production.
Based on the methodology developed by the International Partnership on
Hydrogen and Fuel Cells in the Economy (IPHE) and using IEA data for the
production technologies and upstream and midstream emissions, Figure 3.15
provides an overview of the emissions intensities of different production routes. 50

50More details can be found in the IEA report Towards hydrogen definitions based on their emissions intensity.

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The direct emissions of hydrogen production from natural gas without CCS using
SMR are around 9 kg CO2 equivalent per kg of hydrogen (CO2-eq/kg H2). Further
emissions occur in the production, processing and transport of natural gas, either
in the form of methane emissions from venting or leakages, or as CO2 emissions
from flaring methane at gas fields or linked to the energy being used to produce
and transport natural gas (e.g. emissions linked to the electricity for compressing
natural gas). The global upstream and midstream emissions from gas production
today range from 4.5 kg CO2 equivalent per gigajoule of produced natural gas

Global Hydrogen Review 2023

Chapter 3. Hydrogen Production(kg CO2-eq/GJNG) to 28 kg CO2-eq/GJNG, with a median value of 15 kg CO2eq/GJNG. Using this median value, upstream and midstream operations result in
additional emissions of 2.4 kg CO2-eq/kg H2, and total emissions of 1013 kg CO2-eq/kg H2 for the SMR production route from natural gas without CCS.
Applying CCS to the various direct CO2 sources at the SMR hydrogen plant can
reduce the direct emissions to 0.7 kg CO2-eq/kg H2 (capture rate 93%) and thetotal emissions to 1.5-6.2 kg CO2-eq/kg H2 when including the upper and lower
end of global upstream and midstream emissions for natural gas supply today.
Hydrogen production from coal gasification without CCS results in total emissionsof 22-26 kg CO2-eq/kg H2, depending on the upstream and midstream emissions
for coal mining, processing and transport, which range between
6-23 kg CO2-eq/GJcoal with a median of 8 kg CO2-eq/GJcoal. More than 80% of theemissions intensity of hydrogen production from coal is from direct emissions at
the production plant and less than 20% is linked to coal mining, processing andtransport. Applying CCS with a total capture rate of 93% reduces the emissions
intensity of the coal pathway to 2.6-6.3 kg CO2-eq/kg H2, a range similar to that ofnatural gas SMR with CCS.
The emissions from water electrolysis are determined by the emissions ofelectricity generation and transport. Using the current average global CO2 intensityof 460 g CO2-eq/kWh results in an emissions intensity for hydrogen of 24 kg CO2eq/kg H2, similar to the emissions for hydrogen from unabated coal, but theemissions intensity can be as low as 0.5 kg CO2-eq/kg H2 in a country such as
Sweden, which has one of the lowest emission factors for grid electricity
production in the world today (10 g CO2-eq/kWh).

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Nuclear electricity can be another source for hydrogen production. Although thedirect emissions of a nuclear power plant are zero, the nuclear fuel cycle ofuranium mining, conversion, enrichment and fuel fabrication results in emissionsof 2.4-6.8 g CO2-eq/kWh. Taking those emissions into account, the emissions
intensity of hydrogen production from nuclear electricity is in the range of
0.1-0.3 kg CO2-eq/kg H2. Following the IPHE methodology and the global
assumption for renewable electricity regardless of its application, renewableelectricity from wind, solar PV, hydropower and geothermal energy has zero
upstream and direct emissions, i.e. the emissions associated with the
manufacturing of solar PV systems or wind turbines are not taken into account. As
a result, water electrolysers using these forms of renewable electricity also havezero emissions.

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Chapter 3. Hydrogen Production

Comparison of the emissions intensity of different hydrogen production
routes, 2021

IEA. CC BY 4.0.
Notes: CCS = carbon capture and storage; POx = partial oxidation; SMR = steam methane reforming.
Upstream and midstream emissions include CO2 and methane emissions occurring during the extraction, processing, andsupply of fuels (coal, natural gas) or production, processing, and transport of biomass. Error bars for natural gas and coal
represent the impact of the observed range of upstream and midstream emissions today on emissions intensities. For
natural gas, the lower bound corresponds to best available technology today (4.5 kg CO2-eq/GJ), and the upper bound to
the 95% percentile of the world range (28 kg CO2-eq/GJ). For coal, the lower bound corresponds to the 5% percentile(6 kg CO2-eq/GJ) and the upper bound to the 95% percentile (23 kg CO2-eq/GJ) of global upstream and midstream
emissions of coal supply. The 2021 world grid average is based on a generation-weighted global average of the gridelectricity intensity, with the error bars representing the 10% percentile (50 g CO2-eq/kWh) and 90% percentile(700 g CO2-eq/kWh) across countries. The grid electricity intensities include direct CO2, methane (CH4) and nitrous oxide(N2O) emissions at the power plants, but not upstream and midstream emissions for the fuels used in the power plants.
Electrolysis refers to low-temperature water electrolysis with an assumed overall electricity demand of 50 kWh/kg H2,
including compression to 30 bar.
Hydrogen production from natural gas via SMR is based on 44.5 kWh/kg H2 for natural gas in the case of no CO2 capture,on 45.0 kWh/kg H2 for natural gas in the case of 60% capture rate, and on 49 kWh/kg H2 for natural gas and 0.8 kWh/kg H2
for electricity in the case of a 93% capture rate. Hydrogen production from natural gas via POx is based on demands of
41 kWh/kg H2 for natural gas and 0.6 kWh/kg H2 for electricity in the case of a 99% capture rate.
Hydrogen production from coal is based on gasification, with demands for coal of 57 kWh/kg H2 and for electricity of
0.7 kWh/kg H2 in the case of no CO2 capture, demands for coal of 59 kWh/kg H2 for a CO2 capture rate of 93% anddemands for coal of 60 kWh/kg H2 for a CO2 capture rate of 98%.

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Emissions intensity can vary significantly between different production routes. High
capture rates and minimising upstream emissions will be critical for fossil routes with CCS,
while for electrolytic hydrogen a low emissions intensity of the electricity is important.

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Chapter 3. Hydrogen Production

The emissions intensity of hydrogen production provides a transparent indicator
to be used by governments in regulations, by certification bodies or by market
participants in trade transactions (see Chapter 6 Policies). Nevertheless,stakeholders such as investors, some final consumers of hydrogen-based
products and the general public may also find value in a simpler presentation of
the emission intensities, using intensity levels as presented in Box 3.4.

Box 3.4

Using emissions intensity levels for non-expert users

The precise emissions intensity of hydrogen production is likely to be a key
indicator for governments, regulatory authorities, certification bodies and market
participants. For other stakeholders, it may be less intuitive. Investors, financial
institutions, final consumers of hydrogen-based products and the general public
may struggle to interpret technical details or to quickly grasp the relative scale ofemissions. The importance of communicating in simple terms can already be seenin the extent to which the terms “blue” and “green” hydrogen are being used byexperts and non-experts alike.
When shifting from describing hydrogen using colours to using a more accurate
measure of emissions intensity it is not necessary to entirely do away with thesimplicity of distinguishing between a small set of hydrogen archetypes. A systemthat groups the emissions intensity into a smaller set of distinct levels could provide
a valuable complement, allowing for easily accessible communication of theemissions implications.
One possible approach could be to use a set of distinct, technology-neutral levels,
ranging from emissions intensities below zero (level “A”) to an upper value, as
illustrated in the figure below. The proposed levels reflect known hydrogenproduction routes that can achieve lower emissions than unabated fossil-basedroutes, while also considering potential for future improvement in the production
technologies and fuel supply chains, such as reductions in upstream andmidstream methane emissions in natural gas supply. Systems could also be
designed to include unabated fossil-based production routes or more granularity
at lower levels, to better reflect existing regulations set up by countries.

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If hydrogen use becomes widespread across the energy sector and relevant to thewider public then some stakeholders, such as the investment community andgeneral public, may appreciate the simplicity of quoting the aggregated “level” ofemissions intensity. For example, hydrogen on sale at refuelling stations could bepresented by its level to inform consumers of their environmental choices in amanner equivalent to energy efficiency labelling of appliances and buildings.

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Chapter 3. Hydrogen Production

Example of a potential quantitative system for emissions intensity levels ofhydrogen production

IEA. CC BY 4.0.
Notes: CCS = carbon capture and storage; CR= capture rate; NG = natural gas; POx = partial oxidation; SMR = steam
methane reformer.
Source: IEA (2023), Towards hydrogen definitions based on their emissions intensity.

Emerging production routes
Other low-emission hydrogen production routes have gained some attention
lately, particularly biomass-based routes, natural hydrogen and methane
decomposition.

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Hydrogen can be produced from bioenergy (either from biomass or waste)using different technologies. The use of bioenergy has the potential to produce
low-emission hydrogen with very low emissions intensity, even reaching negativeemissions intensity when coupled with CCUS (see Figure 3.15Figure 3.1).
However, the emissions intensity of bioenergy-based routes will strongly depend
on upstream emissions of the biomass supply chain. In the case of using waste,
its composition plays an important role. Waste tends to be a mix of materials that
can have both biogenic (e.g. food waste) or fossil origin (e.g. plastics) and canhave a very heterogenic composition, which in the case of municipal solid waste
can vary between different regions depending on cultural habits and even in thesame region between different periods of the year. The biogenic waste fraction
has the potential for producing low-emission hydrogen (depending on upstream

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Chapter 3. Hydrogen Production

supply chain emissions), whereas the plastic waste fraction cannot not result in
low-emission hydrogen unless the production process includes CO2 capture andstorage.
Biomass gasification is the most developed technology. It produces synthesis gas
by breakdown of the organic matter of solid biomass at high temperatures and thepresence of an oxidant (which can be steam, oxygen or carbon dioxide). There
are already demonstration projects operating in Japan and France, both using
wastewater sludge as a feedstock. 51 In addition, some pre-commercial scale
plants are expected to be operative soon. In February 2023, SGH2 reached FID
on a plant to produce 4.5 kt H2/y using its plasma-enhanced gasification
technology in Lancaster (United States). Mote (a US-based company) isdeveloping two biomass gasification projects, with one coupling CCUS to theprocess. Yosemite Clean Energy, in the United States, and OMNI, in Canada,
have also projects at advanced stages of development.
US companies have been leading the development of biomass gasification, but
India has also shown a strong interest in biomass-based technologies. Reliancesuccessfully tested in August 2023 the gasification of torrefied biomass 52 forhydrogen production and plans to develop a pre-commercial demonstrator to
produce 18 kt H2/y using catalytic gasification. The Indian Oil Corporation and theIndian Institute of Science are developing a small plant (88 t H2/yr) to demonstratebiomass gasification (using steam and oxygen as oxidants) for hydrogenproduction, aiming to start operation in December 2023. The Indian governmentis also promoting biomass-based routes and has earmarked funds to specificallysupport 40 kt H2/y of capacity production from biomass as part of its incentive
scheme for “green” hydrogen production. 53
Biomass pyrolysis is another technology alternative, similar to gasification,although it does not involve the use of any oxidant. Pyrolysis produces a
combination of liquid organic products, gases and a carbonaceous residue, withthe liquid fraction being the one with higher yields. For this reason, pyrolysis
seems to be better fit for liquid biofuels production and has attracted less interest
than gasification for hydrogen production. However, Kore Infrastructure has a pilot
plant operating in Los Angeles (United States) since 2021.
Biomethane can be used in reformers to produce hydrogen in the same way as
natural gas. More than 70 facilities are certified in the California Low Carbon Fuel

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51
These demonstration projects aim to use biomass gasification for dedicated hydrogen production. Other projects havedemonstrated the use of biomass gasification for other purposes, such as combined heat and power generation.
52
Argus direct (2023), India’s Reliance eyes green H2 production from biomass.
53
See Explanatory notes annex for the use of the terms “green”, “blue” and “clean” hydrogen in this report.

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Chapter 3. Hydrogen Production

Standard programme for blending biomethane or landfill gas in natural gas
reformers to decrease the carbon intensity of their production facilities.
Methane decomposition has progressed significantly in terms of technology
maturity over the past years, particularly plasma decomposition, in which theenergy demand of the process is supplied by electricity, which ignites the plasma(an ionised gas). The plasma reaches temperatures in the range of
1 000-2 000 °C and splits methane into its elements. Plasma decomposition canalso occur at low temperature, but the technology is at a much earlier stage ofdevelopment. In 2021, Monolith Materials, a technology developer based in the
United States, put into operation the first commercial-scale facility to producehydrogen and carbon in solid form (carbon black) using high-temperature plasma
decomposition. The next phase of this project, called Olive Creek 2, willcommercially generate hydrogen to produce ammonia (200 kt H2/year) from 2025.
There is no other commercial-scale plant currently operating, but companies suchas Graforce (Germany) and Spark (France) are also developing this technology.
Catalytic decomposition is a less developed technology, in which methane isdecomposed at high temperatures (though lower than in plasma pyrolysis) in thepresence of a catalyst. Hazer, an Australia-based technology developer, isbuilding a commercial demonstration plant (100 t H2/yr), with start-up expected forlate 2023. The company has also announced the development of commercial
projects in Canada, France and Japan (2 500 – 10 000 t H2/yr). At a smaller scale,Hycamite, a Finnish company, has secured permits and raised funds to start
construction of a demonstration facility. C-Zero, a company based in the UnitedStates, has raised USD 34 million in funding to build a 146 t H2/yr facility.
A third technology, and the least developed, is thermal decomposition. Ekona, aCanadian developer, is working on a demonstration project with the aim of
becoming operational in 2023. Aurora, another Canadian company, is working on
an innovative process to apply microwave heating to thermal decomposition of
methane.

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The Earth continuously produces natural hydrogen underground through aseries of chemical reactions (oxidation of ferrous iron minerals, water radiolysis,organic matter maturation and outgassing from the Earth's mantle). A growing
number of discoveries of underground natural accumulations of hydrogen havetriggered interest in natural hydrogen as a complement to other low-emissionhydrogen production technologies. Natural hydrogen presents several
advantages: it is an energy source and not an energy vector, thus eliminating theneed for fossil fuels and electricity in its production (resulting in reduced emissions
and avoiding energy transformation losses). Additionally, production is not subject
to intermittency (as in renewable-based production), production sites have alimited land footprint and there is no need for purified water or CO2 storage.

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Chapter 3. Hydrogen Production

However, extracting natural hydrogen requires compression and purification
systems since natural hydrogen accumulations contain different impurities (suchas nitrogen, methane, CO2, helium and argon) and the hydrogen content can vary
widely (2.4-100% in volume) depending on the location, the type of accumulationand the depth. These factors can affect the life-cycle emissions of naturalhydrogen production. Initial studies suggest that these can be low(<1 kg CO2/kg H2) but vary over the lifetime of the well (due to reduced well
productivity), and can be highly impacted by impurities (particularly methane).
Initial estimates suggest that the Earth's hydrogen potential exceeds current
demand and could even be capable of meeting the growing requirements ofdecarbonisation scenarios. However, the potential exploitation of natural hydrogenpresents challenges and remains highly uncertain. Detailed geological surveys
tracking natural hydrogen accumulations are not readily available, impeding acomprehensive understanding of its formation, migration and commercial
exploitability. There is a possibility that the resource is too scattered to be captured
in a way that is economically viable. While proponents claim lower production
costs compared to other methods (in the range of USD 0.5-1/kg H2), such as
natural gas, the exact cost implications remain to be seen.
The number of companies engaged in natural hydrogen exploration has
significantly increased, with 40 active companies as of mid-2023, compared toonly 3 companies in 2020. However, the lack of regulatory frameworks in somecountries has slowed down project development, although progress has been
made in others, with licensing already happening in Australia, France, Mali, Spainand the United States (Table 3.1). So far, development has been spearheaded bysmall wildcatters, but some major energy companies have started to show interestin the technology, including Shell, BP and Chevron joining a consortium led by the
US Geological Survey and Colorado School of Mines, focusing on studying naturalhydrogen.

Country

Location

Developers

StatusAustralia

Yorke peninsulaGold Hydrogen

Drilling permit granted. Exploration from October
2023.

Australia

Eyre Peninsula

H2EX

Permit granted.

Australia

Amadeus Basin

SantosDrilling wells to evaluate resource.

FranceLorraine basin

La Française
d’Énergie

Application for exclusive mining exploration
permit submitted.

Mali

Bourakebougou

Hydroma

Operational since 2012, demonstration.

Spain

Pyrenees

Helios Aragon

Drilling permit granted. Exploration from 2024.

United States

Arizona

Desert Mountain
EnergyApplication for exploration permit submitted*.

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Selected developments for natural hydrogen production

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Chapter 3. Hydrogen Production

Country

Location

Developers

StatusUnited States

KansasNatural Hydrogen
EnergyExploratory drilling completed in 2019.

United States

Nebraska

HyTerraDrilling completed. Potential production from2023.

* The company is focusing on helium production with a secondary focus on developing hydrogen assets located within their
helium fields.

Production of hydrogen-based fuels andfeedstocks
Hydrogen-based fuels and feedstocks, including ammonia, methanol andsynthetic hydrocarbons (synthetic methane and Fischer-Tropsch products such as
diesel and kerosene), are easier to store and transport than pure hydrogen, andcan often make use of existing infrastructure such as natural gas pipelines andend-use technology such as aeroplanes. Despite the advantages with regards tostorage and transport, producing hydrogen-based fuels entails additional costs,
energy and feedstocks to convert hydrogen into these fuels.
During 2022, projects for a cumulated potential low-emission hydrogen production
equivalent of 0.02 Mt have begun operation, bringing the total number of projects
to 80 and the global total production to 0.3 Mt H2, or around half of the total lowemission production in 2022. Most of this increase comes from hydrogen to
produce ammonia for use as a fuel and feedstock, which reached 0.17 Mt H2 in
2022. Synthetic methane continues to be the second largest share of hydrogenbased fuel projects on a hydrogen-equivalent basis, although little to no additional
production began in 2022.
Announced projects are set to rapidly multiply the 2022 production capacity, with
17 Mt of H2 equivalent slated to begin operation by 2030 54 (Figure 3.16) from a
total of 325 projects, over twice the number of projects that were identified in the
GHR 2022. These trends continue to 2030, as ammonia captures around 80% of
announced production. The high share of ammonia could be a sign of the fertiliser
industry’s readiness to directly absorb the low-emission alternative as a drop-in
feedstock for its existing processes. Ammonia does not require carbon, simplifying
supply chains and making it an attractive early mover among hydrogen-based
fuels. Additionally, ammonia can be used as a long-distance carrier for hydrogen,taking advantage of existing know-how on transporting ammonia around the world
established by the fertiliser industry. However, nitrogen oxides (NOx) and nitrous
oxide (N2O) emissions must be minimised when ammonia is combusted as a fuel

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54This could decrease to almost 10 Mt if projects at a very early stage of development (e.g. only a co-operation agreement
among stakeholders has been announced) are excluded.

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Chapter 3. Hydrogen Production(see section on Electricity generation in Chapter 2 Hydrogen use for more
information).
Other hydrogen-based fuels make significant inroads to 2030 in the announced
projects compared to 2022, including Fischer-Tropsch (FT) fuels and synthetic
methanol, driven by demand from the aviation and shipping sector, respectively.

Global hydrogen-based fuel production by fuel, region and status,
historical and based on announced projects
By 2030
20

50%

16

40%

12

30%

20%

8

20%

10%

4

10%

0%

0

50%

0.4

40%

0.3

30%

0.2
0.1
0.0

2019 2020 2021 2022 2023e

Mt H2 equivalent

Mt H2 equivalent

Historic
0.5

By product By region By status

0%

Status
Early stages
Feasibility
FID/Construction
Operational
RegionRoWAustralia and New ZealandCentral and South America
North America
EuropeProduct
FT fuels
Synthetic methane
Synthetic methanol
Ammonia% of all projects (right axis)

IEA. CC BY 4.0.
Notes: FID = final investment decision; FT = Fischer-Tropsch; RoW = rest of world.
Source: IEA Hydrogen Projects, (Database, October 2023 release).

Hydrogen-based fuels production, in particular for ammonia, could grow rapidly by 2030
based on announced projects, accounting for almost 50% of hydrogen production from all
projects.

The announced hydrogen-based fuels projects reflect a broad geographicaldiversity, with significant capacity planned for all major regions in the world.
Australia and North America claim the largest shares of announced projects, eachwith 4.7 Mt H2 equivalent 55 in 2030, coming from around 75 projects combined.
North America claims the largest share of the announced projects, with around
30. Central and South America and Europe are the next largest contenders,accounting by 2030 for around 2.6 Mt and 1.8 Mt H2 equivalent. 56

This could decrease to 0.9 Mt for Australia and 2.8 Mt for North America, if projects at a very early stage of development,
e.g. only a co-operation agreement among stakeholders has been announced, are excluded.
56
This could decrease to 1.7 Mt and 1.2 Mt respectively if projects at a very early stage of development, e.g. only a cooperation agreement among stakeholders has been announced, are excluded.

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55

Global Hydrogen Review 2023

Chapter 3. Hydrogen Production

Overall, only 5% of hydrogen-based fuels projects (in terms of Mt H2 equivalent
production) have reached FID or are under construction, with the most nascentprojects focused on synthetic hydrocarbons.
Converting hydrogen into other fuels and feedstocks adds to the cost of
production. For ammonia from electrolytic hydrogen, the investment cost today
represents more than 50% of the production costs, mainly due to the electrolyser
CAPEX (Figure 3.17). As electrolysis costs fall, so too do overall production costs,
and electricity feedstock could become the main cost component with a 40-50%
share, depending on the region. For ammonia produced from natural gas with
CCUS, the fuel cost share can range from 35% for a gas price of USD 5/MBtu, to
75% at a gas price of USD 35/Mbtu.

2030

Levelised costs of ammonia and synthetic kerosene for electricity-based
pathways in 2022 and in the Net Zero Emissions by 2050 Scenario in
2030
Ammonia2022
Middle East - NG
Middle East
Chile
United States
Europe

CAPEX
OPEX

2030

0

200

400

600

800

Synthetic kerosene

2022
Middle East
Chile
United States
Europe

1 200
1 000
USD/t NH3

Electricity
Natural gas
CO₂ feedstock - low
CO₂ feedstock - highCurrent fossil price

0

200

400

600

1 000
800
USD/bbl

IEA. CC BY 4.0.
Notes: CAPEX = capital expenditure; OPEX= operational expenditure; NH3 = ammonia; NG = Natural gas-based
production, with carbon capture. “Middle East - NG” refers to the integrated steam methane reformer with carbon capture
for the production of ammonia. Values for 2022 refer to electricity production from solar PV in Middle East; 2030 values are
based on the Net Zero Emissions by 2050 Scenario, with the best renewable-based production routes in each region.
Hydrogen storage cost to reach a minimum of 80% capacity factor of the synthesis processes is included. Current fossil
price refers to the prices from May-August 2023 for the production of ammonia from natural gas without CCUS and forfossil kerosene.
Sources: Based on data from McKinsey & Company and the Hydrogen Council; NETL (2022); IEA GHG (2017).

Hydrogen-based fuels from electrolytic hydrogen are today more expensive than fromunabated fossil fuels. By 2030, costs could fall by around 40% due to reductions in the costof renewable electricity and electrolysers.

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For FT liquids such as synthetic kerosene from electrolytic hydrogen, production
costs vary greatly based on the source of CO2. If, for example, biogenic CO2 fromethanol production is used at a cost of USD 30/t CO2, then electrolysis andconversion losses account for three-quarters of production costs, while thesynthesis contributes one-fifth. Biogenic CO2 will be limited by the bioenergy

Global Hydrogen Review 2023

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availability and linked to the future deployment of bioenergy with carbon captureand storage (BECCS). Direct air capture (DAC)-sourced CO2 does not face thesame supply constraints but comes at a much higher cost. DAC technology is stillat an early development stage, with only a few plants in operation worldwide.
Current DAC credits on the market are around USD 600-1 000/t CO2, but withfurther deployment and technology improvements, costs could fall to
USD 200-700/t CO2 by 2030. As a consequence, the production costs of synthetic
kerosene from renewable hydrogen, which today are in the range of USD 450-820
per barrel (bbl), are much higher than conventional kerosene (at almost
USD 100/bbl), but could fall to USD 200-550/bbl by 2030.

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

Chapter 4. Trade and infrastructure
Hydrogen trade could become an important cornerstone for the development ofhydrogen markets. Trade would allow countries with limited domestic resources
for low-emission hydrogen production – but with a need for hydrogen to
decarbonise their energy systems – to import hydrogen from regions with ample
low-cost resources for low-emission hydrogen production that exceed domestic
needs. Exporting countries could therefore benefit economically from exportinghydrogen or products produced from hydrogen, while for importing countrieshydrogen trade can be an opportunity to improve energy security by reducing fossil
energy imports and diversifying the supply countries for hydrogen imports.
Infrastructure to transport and store hydrogen is an important enabler for hydrogen
trade. However, since hydrogen has a relatively low volumetric energy density andlow liquefaction temperature, transporting and storing hydrogen is technicallymore challenging than the handling of fossil fuels today. This includes the need toliquefy or compress hydrogen, or to convert hydrogen into carriers such as
ammonia or liquid organic hydrogen carrier (LOHC). Developing trade in merchanthydrogen would entail complexities requiring careful consideration of the cost,benefits and potential trade-offs in exporting and importing countries alike.

Status and outlook of hydrogen trade
International trade in hydrogen is today at a very nascent stage, not least whencompared to the needs for hydrogen trade in the Net Zero Emissions by 2050
Scenario (NZE Scenario), in which more than 20% of merchant demand forhydrogen and hydrogen-based fuels is met through international trade by 2030.
Today, hydrogen trade flows are limited to a few existing hydrogen pipelines
connecting industrial areas in Belgium, France and the Netherlands, and to a few
pilot projects to demonstrate hydrogen trade by ship. The only exceptions areammonia and methanol, which are already globally traded as feedstocks for thechemical industry. Around 10% of global ammonia demand was met throughinternational trade in 2021, and for methanol the trade share was 20%. However,existing trade is linked to use in the chemical industry, and international trade inammonia and methanol for fuel purposes has only been tested in some first pilot
projects.

Recent trade projects

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Various technology options can be used to trade hydrogen internationally. For
seaborne trade, the shipment of hydrogen in the form of liquefied hydrogen andGlobal Hydrogen Review 2023

Chapter 4. Trade and infrastructure

LOHC have been demonstrated in first projects, while experience in shipping
ammonia exists in the fertiliser industry. In 2020, the first international trade of
102 t H2 took place from Brunei to Japan, using methylcyclohexane as an LOHC.
For liquefied hydrogen, a first cargo of 75 t H2 was delivered in 2022 from Australia
to Japan as part of the Hydrogen Energy Supply Chain (HESC) project, with plansto scale up the trade volumes to 225 kt per year in the 2030s. Kawasaki Heavy
Industry is preparing a feasibility study for another project that plans to ship
36.5 kt H2 per year from the port of Townsville, Australia, to Japan. In 2020, forthe first time, ammonia for use as a fuel was shipped from Saudi Arabia to Japan.
More shipments of ammonia from Saudi Arabia and the United Arab Emirates
occurred in 2022 and 2023 or are planned for later this year (Table 4.1).
Planned and completed trade pilot projects for low-emission hydrogen andhydrogen-based fuels, 2020-2023

Trade pilot projectHydrogen carrier

Year

Quantity traded

Saudi Arabia to Japan

Ammonia

2020

40 t NH3

Brunei to Japan

LOHC

2020

102 t H2

Australia to Japan*

LH2

2022

75 t H2

Saudi Arabia to Korea

Ammonia2022

25 000 t NH3

United Arab Emirates to Germany

Ammonia2022

13 t NH3

Brunei to Japan

LOHC

2022

Chile to United Kingdom

Synthetic gasoline

2023

Saudi Arabia to Japan

Ammonia

2023

Saudi Arabia to India

Ammonia2023

5 000 t NH3

Saudi Arabia to China

Ammonia2023

25 000 t NH3

Saudi Arabia to Korea

Ammonia-

25 000 t NH3

Saudi Arabia to Bulgaria

Ammonia2023

25 000 t NH3

Saudi Arabia to European Union

Ammonia

Saudi Arabia to Chinese Taipei

Ammonia

2 600 L

50 000 t NH3
2023* The shipped hydrogen was produced from unabated coal, although the commercial phase of the project plans to include
carbon capture, utilisation and storage (CCUS).
Notes: This table does not include the already existing ammonia trade in the fertiliser industry. Around 10% of global
ammonia production for the fertiliser industry is already traded today, but this is almost entirely based on ammonia
production from unabated fossil fuels. Projects characterised as “low-carbon” or “blue” ammonia or hydrogen are included,
although information on the emission reduction compared to the unabated production from fossil fuels is not always
available.NH3 = ammonia; H2 = hydrogen; LH2 = liquefied hydrogen; LOHC = liquid organic hydrogen carrier.

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For synthetic hydrocarbon fuels, the pilot phase of the Haru Oni project in Chile
started production of synthetic gasoline in December 2022, and a first shipment of
2 600 litres (L) of synthetic gasoline left Chile for the United Kingdom in March
2023. The current pilot plant has a production capacity of 130 000 L per year

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure(corresponding to the annual fuel consumption of 200 gasoline passenger cars) 57,
with the plan to ramp up the capacity to 55 million L by 2025 (83 000 cars) and
550 million L by 2027 (830 000 cars). Synthetic hydrocarbon liquid fuels orsynthetic methane can take advantage of existing fossil fuel infrastructure.

Announced trade projects
Based on announced export-oriented projects, 16 Mt of hydrogen equivalent(Mt H2-eq) 58 could be exported all around the world by 2030, and this number
could rise to 25 Mt H2-eq by 2040 59 (Figure 4.1). This is based on announced
export plans for which there is an associated hydrogen production project,including those plans at very early stages of development (e.g. projects that have
not yet started a feasibility study). Export-oriented projects represent more than
40% of the low-emission hydrogen production of 38 Mt from all announced
projects in 2030, indicating that the potential export market is a strong driver in thedevelopment of projects. Compared to last year’s edition of the Global Hydrogen
Review, the 16 Mt H2 of announced trade projects represent a more than 25%
increase. Despite this growth in announced trade projects, progress in pre-existing
projects has been slow. Only three projects are at advanced stages ofdevelopment, i.e. having at least reached a final investment decision (FID): theNEOM project in Saudi Arabia, the Green Hydrogen and Chemicals SPC projectin Oman and CF Industries’ plant in Donaldsonville in the United States. All threeof these projects aim to use ammonia as the carrier for a combined export volumeof less than 0.3 Mt H2-eq by 2030.
Three-quarters of the export-oriented projects planned for 2030 or sooner are stillat early stages of development and only less than one-quarter is undergoing afeasibility study. Moreover, less than one-third of the volume that could be tradedby 2030 has already identified a potential off-taker – although only a few havereached FID or signed a binding off-take agreement. This is the case of the NEOM
Green Hydrogen Project in Saudi Arabia: a 30-year off-take agreement has been
secured with Air Products for the low-emissions ammonia produced from 2026
onwards. The realisation of the announced trade projects will depend not only on
the deployment of the production facility and the necessary infrastructure, but also
on securing one or more off-takers for the long run: these two aspects should be
pursued in parallel to ensure that projects are realised on time and are
economically sustainable. Despite the strong momentum around hydrogen export
announcements in the past few years, the small share of trade projects that have
Assuming a fuel efficiency of 6.6 L per 100 km and an annual mileage of 10 000 km.
For hydrogen-based fuels and feedstocks, the equivalent hydrogen amount corresponds to the stoichiometric hydrogen
inputs needed to produce these fuels feedstocks, assuming a 2% hydrogen loss in the reaction. The hydrogenrequirements are 0.18 kg H2 per kg NH3, 0.13 kg H2 per kg methanol, 0.52 kg H2 per kg of Fischer-Tropsch synfuel and0.55 kg H2 per kg of methane.
59
In the case of hydrogen-based fuels as carriers, the hydrogen equivalent amount represents the hydrogen feedstockneeded to produce the carrier chosen for trade.
57

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Chapter 4. Trade and infrastructure

reached advanced planning stages demonstrates significant uncertainty aroundthe ability to develop an export market at scale over the next decade.
Figure 4.1 Low-emission hydrogen trade by status and by carrier based on announced
projects, 2030-2040

IEA. CC BY 4.0.
Notes: FID = final investment decision; LOHC = liquid organic hydrogen carrier. “Compressed hydrogen” includes bothprojects aiming to transport gaseous hydrogen via pipelines and projects planning to ship it in compressed hydrogen
carrier. “Synthetic hydrocarbons” includes projects aiming to trade synthetic methane or synthetic oil products. “No FID”
refers to projects undergoing feasibility study or at early stage, while “FID” indicates projects that have already reached a
final investment decision. “Potential off-taker” refers to projects which have identified a potential buyer or end-user, even if
a binding off-take agreement has not been signed yet. The amount of hydrogen equivalent traded is computed from thecapacity of each plant, by considering average capacity factors (reported in the technical documentation of the IEA
Hydrogen Projects Database) and by assuming that a certain share of production would be available for trade, in the caseof projects aiming at multiple end-uses. For each project, a 50% availability factor is assumed for the first year of operation.
Only projects with a disclosed start year are included.
Source: IEA analysis based on multiple sources, including company announcements.

Planned hydrogen exports could reach 16 Mt by 2030, though almost all projects are at
early stages and fewer than one-third have identified a potential off-taker.

The majority of announced projects – accounting for 80% of potential production– prioritise ammonia for the transport of hydrogen, in many cases aiming for a final
use that does not require reconversion back to hydrogen (Figure 4.1). This
includes use as feedstock in the fertiliser industry, or as a fuel for co-firing in power
generation. Reconversion back to hydrogen requires energy and adds significant
cost, potentially altering the economic competitiveness of the supply chain (seeInfrastructure at ports).

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Many projects are at an early stage of development, and for several of them thecarrier has not yet been chosen. By 2040, about 5% of the traded volume basedon the announced trade projects could be in the form of synthetic liquidhydrocarbons, 4% as compressed gaseous hydrogen via pipeline, and 2% in theform of liquefied hydrogen.

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Chapter 4. Trade and infrastructure

The costs of importing hydrogen compared to domestic production are also
influenced by the form in which the hydrogen will eventually be needed, as
illustrated in Box 4.1.

Box 4.1

Domestic production versus imports – the case of north-west
Europe

The cost of transporting hydrogen from the exporting to the importing region canbe substantial, and so assessing the total cost of supply – for production andtransport – is essential. Depending on the carrier and the transport distance,transport costs can shift the competitiveness in favour of domestic production. For
example, at USD 2.1/kg H2, levelised production costs in Latin America arecheaper than domestic production from offshore wind in north-west Europe.
However, adding the transport costs of USD 2.5/kg H2 (including conversion into
ammonia in the exporting country and its reconversion into hydrogen in north-west
Europe) makes domestic production the cheaper option, although constraints on
renewable resources or alternative uses for the renewable electricity could limit
domestic production.
Supply costs of hydrogen and ammonia in north-west Europe compared toimports

IEA. CC BY 4.0.
Notes: “H2”= hydrogen; “NH3” = ammonia; “LH2” = liquefied hydrogen; “LOHC” = liquid organic hydrogen carrier. Domestic
production in north-west Europe uses offshore wind; production in other regions uses solar PV. “Conversion” includes acompressed hydrogen storage cost to allow for stable input to the synthesis and to the liquefaction processes. The costof capital is assumed at 6%. Costs refer to the Net Zero Emissions by 2050 Scenario (NZE Scenario) in 2030. Moretechno-economic assumptions are available in a separate forthcoming Annex.
Sources: Based on data from McKinsey & Company and the Hydrogen Council; IRENA (2020); IEA GHG (2014); IEA
GHG (2017); E4Tech (2015); Kawasaki Heavy Industries; Element Energy (2018).

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Transporting compressed hydrogen via pipeline can be the most competitive
option in terms of cost, adding only about USD 0.4-0.5/kg H2 for a 3 000 km

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Chapter 4. Trade and infrastructure

distance with a new 48-inch diameter pipeline (75-100% design capacity). This
cost can be even lower if repurposed pipelines are available. However, thefeasibility of this type of infrastructure can have technical and geopoliticalchallenges.
The form in which the imported hydrogen will eventually be used strongly
influences the choice of hydrogen carrier and the supply costs. If hydrogen isconsumed in the form of ammonia and not hydrogen, for example in the fertiliser
industry, the imported ammonia can be used directly, avoiding the costs ofreconverting ammonia back into hydrogen. In this case, importing ammonia from
North Africa, Latin America or the Middle East can actually be cheaper thandomestically producing ammonia in north-west Europe.
Given that some of the technologies required for conversion, shipping andreconversion are at a relatively early stage of development, with just a few pilot ordemonstration projects having been realised so far, the economics of the different
trade options may change in the future, as technologies advance.

Australia is home to half of the trade projects by export volume, thanks to its
abundant renewable resources and its proximity to the Asian market, which could
potentially become one of the biggest importers of low-emission hydrogen andhydrogen-based fuels. Several GW-scale renewables-based hydrogen production
projects are planned in Australia and many of them, such as the Murchison project
and the Australian Renewable Energy Hub, aim to export to international markets.
Central and South America and North America together could represent one-thirdof the exported hydrogen by 2030. Africa and Europe could account for 6% and
8% by 2030, respectively. However, all of the Europe-based exported hydrogen is
set to remain within the continent as the projects aim to connect countries withrelatively good renewable resources (such as Denmark) with demand centres in
the Netherlands and Germany. Large-scale export-oriented projects have also
been announced in Oman and the United Arab Emirates, but they represent only
a few percent of the global trade volume by 2030, with the Middle East region
accounting for 6% of global export by 2040 only.

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Around 60% of the announced projects by 2030 have not yet identified adestination country, and of the projects that have done so, about two-thirds haveidentified a potential off-taker. Based on the current announced projects, Europe
could receive 5 Mt H2-eq by 2030, with one-fifth of it having been produced andtraded inside the region itself. This could double to around 10 Mt H2-eq by 2040,
with two-thirds of these imports in the form of ammonia. Japan could receive
1 Mt H2-eq by 2030, with supply coming predominantly from North America andAustralia.

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

Figure 4.2 Low-emission hydrogen trade by exporting and importing region based on
announced projects, 2030-2040

IEA. CC BY 4.0.
Notes: The amount of hydrogen equivalent traded is computed from the capacity of each plant, by considering averagecapacity factors (reported in the technical documentation of the IEA Hydrogen Projects Database) and by assuming that acertain share of production would be available for trade, in the case of projects aiming at multiple end-uses. For eachproject, a 50% availability factor is assumed for the first year of operation. Only projects with a disclosed start year are
included.
Source: IEA analysis based on multiple sources, including company announcements.

Australia accounts for half of the announced export projects by 2030, while around onethird of the announced exports globally are earmarked for Europe. Still, around 60% of
export projects have not yet identified a destination country.

The major trade routes that can be identified based on announced projects
connect Australia with Europe and with the Asian market (Japan and Korea inparticular), Latin American countries with Europe, and North American countries
with the Asian market (Figure 4.3). On all these routes, ammonia is expected tobe the main carrier to transport low-emission hydrogen by 2030.

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Although more and more countries are publishing national hydrogen strategies, orroadmaps defining hydrogen development milestones for the next decades, not
all of them have quantitative objectives for production, and only a few for expectedtrade volumes (Figure 4.4). The REPowerEU plan sets a target of 10 Mt ofrenewable hydrogen imports into the European Union by 2030, of which 40%
should be in the form of ammonia or other derivatives. Korea aims to import
1.94 Mt H2 by 2030, according to the Basic Plan for Implementation of Hydrogen
Economy. These combined targets together represent almost 12 Mt of hydrogen
imports by 2030, more than twice the volume from announced projects planningto deliver to these destinations (including those at very early stages ofdevelopment). Reaching those targets – and also reaching the ambition levels
reflected in project announcements – will require rapid and concrete actions forreaching FIDs and moving forward with construction, not only of the underlyinghydrogen production projects, but also of the trade infrastructure.

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

Figure 4.3 Potential low-emission hydrogen trade flows based on announcements,
2030

IEA. CC BY 4.0.
Notes: LOHC = liquid organic hydrogen carrier; UAE = United Arab Emirates; Mt = million tonnes. In million tonnes ofhydrogen equivalent, only flows larger than 150 kt H2 equivalent per year are shown.
Source: IEA analysis based on multiple sources, including company announcements.

Several trade projects are under development, with Australia, Central and South America,
North America and Africa as key exporters, while only a few importing countries have been
identified.

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Where a project cannot take advantage of pre-existing terminals or pipelines,
infrastructure will need to be developed in parallel to plant construction, as building
new infrastructure can often be the lengthiest part of all construction, with pipelines
and port terminals taking up to 9 years on average. At the same time, contracts
with off-takers need to be secured to guarantee the economic sustainability of the
project.

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

In the NZE Scenario, 14 Mt of hydrogen equivalent are traded inter-regionally 60 by
2030, corresponding to about 25% of low-emission merchant hydrogenproduction. The volume of the announced trade projects is comparable with thetrade volume in the NZE Scenario. Those projects with a defined destination
represent only half of the trade in the NZE Scenario in 2030 and those with apotential off-taker only one-third. Almost two-thirds of the trade in the NZE
Scenario is in the form of ammonia, while around half of the hydrogen traded in its
pure form is transported via pipeline.
Figure 4.4 Low-emission hydrogen trade by importing region based on announced
projects, policy targets and in the Net Zero Emissions by 2050 Scenario,
2030

IEA. CC BY 4.0.
Notes: NZE=Net Zero Emissions by 2050 Scenario. The amount of hydrogen equivalent traded is computed from thecapacity of each plant, by considering average capacity factors (reported in the technical documentation of the IEA
Hydrogen Projects Database) and by assuming that a certain share of production would be available for trade, in the caseof projects aiming at multiple end-uses. For each project, a 50% availability factor is assumed for the first year of operation.
Sources: IEA analysis based on multiple sources, including company announcements, RePowerEU, Korea Basic Plan for
Implementation of Hydrogen Economy.

Policy targets by countries for hydrogen imports are twice as high as the announced export
projects to deliver to those countries.

One current obstacle for trade is the lack of a common internationally agreed
methodology to determine the emission intensity of hydrogen, which could
potentially lead to a fragmented market for hydrogen (see Chapter 6).

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60
In the scenario analysis, only the trade flows between the model regions of the IEA’s Global Energy and Climate Model(GEC-M) are represented, which means that trade between countries that are part of the same region is not captured. For
announced projects, bilateral trade flows between countries are represented.

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Chapter 4. Trade and infrastructure

Trade contracts
Bilateral trade arrangements, often between companies, but in some cases also
involving government institutions, currently account for the majority of announced
trade projects with an identified off-taker. These bilateral trade contracts withclear pricing mechanisms or fixed prices provide investment security to develop
capital-intensive hydrogen projects such as production facilities or tradeinfrastructure. Auctions are another instrument for awarding trade contracts: bycreating a bidding competition for a contract, auctions can help move the demandand supply-side price levels closer. They also allow the market price to respond
more readily to changes such as production cost declines or increased willingness
to pay.
One of the most developed support instruments for hydrogen trade today is the
H2Global double-auction programme initiated by Germany. Using a market
intermediary, an auction will be held to purchase hydrogen from suppliers outside
the European Union through fixed price 10-year contracts. A separate auction willthen be held to sell the hydrogen to buyers using contracts of roughly 1 year.
H2Global launched first tenders with a budget of EUR 900 million for ammonia,
synthetic methanol and synthetic kerosene produced from renewable hydrogen at
the end of 2022, with deliveries planned to begin in 2024. The tenders were closedby the end of May 2023. The German government has allocated a further
EUR 3.5 billion for future tenders up to 2036. The tender conditions follow the rulesof the EU Renewable Energy Directive II and the delegated act on rules for the
production of renewable liquid and gaseous transport fuels of non-biological origin.
This means that the electricity must come from directly connected renewables,from an electricity grid with at least a 90% renewable share or from a powerpurchase agreement (PPA). For the PPAs, H2Global requires hourly correlation,i.e. renewable electricity generation and its use in hydrogen production must
balance within an hour. This is stricter than the use of monthly correlation (i.e.
balancing within a month) until 2030 stipulated in the final version of the delegatedact. The H2Global initiative is not limited to Germany, but can be used by othercountries, and the Dutch government announced it will use H2Global for auctionsof hydrogen imports in 2024, with allocated government support ofEUR 300 million.

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In 2023, the European Commission established the European Hydrogen Bank tostimulate renewable hydrogen production and use. The European Hydrogen Bank
plans a pilot auction on a fixed premium for renewable hydrogen production within
the European Union for Q3 2023, with a budget of EUR 800 million and with
contracts to be awarded by mid-2024. Similar tenders for renewable hydrogen
imports from outside the European Union are also planned. Joint auctions of theEuropean Hydrogen Bank and H2Global are being discussed.

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Chapter 4. Trade and infrastructure

The use of auctions and tenders is not limited to governments. In February 2022,
the Japanese utility JERA issued a tender for up to 500 000 t/yr of low-emissionammonia to be co-fired in its Hekinan coal power plant, with deliveries starting in
2027-28 and lasting into the 2040s. Two companies, Yara and CF Industries, won
the tender and plan to produce the ammonia in the United States from natural gas
with CCUS.

Status and outlook of hydrogen
infrastructure
Transport and storage are critical elements of the low-emission hydrogen supply
chain. Infrastructure is needed not only to connect regions where low-emissionhydrogen can be produced at low cost with centres of demand and to manage
fluctuations in production and demand, but also to ensure the resilience of thesystem in the event of supply disruptions.
Figure 4.5 Global annual investment in gas infrastructure in the Net Zero Emissions by
2050 Scenario, 2016-2030

IEA. CC BY 4.0.
Notes: H2 = hydrogen; HRS = hydrogen refuelling stations; LH2 = liquefied hydrogen.

Total investment in natural gas and hydrogen infrastructure remains steady, with
USD 35 billion dedicated to hydrogen by the end of this decade in the NZE Scenario.

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In the NZE Scenario, global annual investment in low-emission hydrogen andhydrogen-based fuels transport, including pipelines, storage facilities, terminals
and refuelling stations, reaches around USD 35 billion over the second half of thisdecade. This amount represents approximately 40% of current annual spendingon natural gas pipelines and shipping infrastructure (Figure 4.5). However, as
investment in natural gas infrastructure declines in the NZE Scenario, the overallGlobal Hydrogen Review 2023

Chapter 4. Trade and infrastructurelevel of investment in infrastructure for gas and hydrogen infrastructure combined
remains relatively steady throughout the decade.
The development of energy infrastructure projects generally tends to have longlead times, averaging between 6 and 12 years for natural gas pipelines, port
terminals and underground gas storage facilities. Gas infrastructure projects arelarge civil engineering projects, often spanning several jurisdictions, which canentail delays due to permitting issues and a lack of socio-political support. It istherefore critical to start infrastructure planning well in advance, even before
production and demand are fully established.
Currently, there are around 1 million km of natural gas transmission pipelines inoperation, 60 000 km under construction and over 150 000 km underconsideration. As natural gas consumption declines, repurposing this existing
infrastructure for hydrogen would provide an opportunity to mitigate the risk of
stranded assets. It would reduce the environmental impact associated with
manufacturing and laying new pipelines, thereby lowering investment costs andpotentially reducing lead times. Around 5 000 km of hydrogen pipelines are
already in operation worldwide, mainly in the United States and Europe. Thesepipelines are relatively small, with diameters of less than 18 inches, connecting
refineries and chemical complexes, operating under static loads and all onshore.
However, new hydrogen pipelines connecting countries or continents may belarger, with diameters as large as 48 inches. These pipelines could connect
different countries and even continents, with some of them being offshore, andcould provide a certain degree of flexibility to the system as they should be able
to withstand pressure swings resulting from cyclic loading and some linepack. 61
Such a – rather futuristic – hydrogen transmission system would differ significantly
from existing local networks, and would more closely resemble current natural gas
transmission, albeit on a smaller scale, as hydrogen consumption would be lower
than today’s natural gas consumption, even in the NZE Scenario.
Global underground natural gas storage capacity is around 490 bcm, equivalent
to approximately 12% of annual gas demand. In Europe, this figure is as high as
25% in order to cover seasonal increases in heating demand. Around 90% ofexisting capacity is in porous reservoirs, mainly depleted gas fields. The capacity
requirements and the type of storage needed for low-emission hydrogen are
expected to be different to those for natural gas. Hydrogen demand may be lessseasonal, but countries will still need to determine an appropriate level of storage
for security purposes, considering import dependencies. However, intra-seasonal

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61
Linepack refers to the volume of gas stored in a pipeline. The gas can be compressed, increasing the pressure of thepipeline. Since the pipeline can operate within a safe pressure range, the amount of gas injected into a pipeline may differ
from the amount of gas withdrawn at a specific time, providing short-term operational flexibility to match supply and demand.

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

fluctuations due to the variability of renewable energy generation will mean thathydrogen storage would require underground facilities that can go through multiple
cycles within a year. Depending on geologic availability, salt cavern storage or
lined hard rock cavern storage are favourable options for managing fluctuations inrenewable energy and hydrogen production, even if they are more expensive interms of rated capacity. Porous reservoirs are more commonly available, but theirflexibility to rapidly ramp up and down is still uncertain, and the technology has not
yet been demonstrated for pure hydrogen storage, but they could potentially playa key role in enhancing security.
To transport hydrogen over long distances where pipeline transmission is not
feasible, or in regions without suitable geological conditions for undergroundstorage, hydrogen needs to be converted into denser forms. Among suchalternatives, liquefied hydrogen (LH2) or carriers such as ammonia and LOHCs
are promising options. However, while the conversion of hydrogen to ammonia foruse as ammonia is already well established, if conversion back to hydrogen isneeded the technologies required are not yet available on a commercial scale.

Transport by pipeline
Whenever hydrogen transport by pipeline reaches economies of scale (~100kilotonnes per year [ktpa] for a 20-inch pipeline and ~2 000 ktpa for a 48-inch
pipeline operating at 75% of their design capacity and 50-80 bar), it will become
the cheapest option for hydrogen transport up to a distance of 2 000-2 500 km,
particularly in the case of repurposed pipelines. Large-diameter pipelines may becheaper for longer distances, but their construction is more challenging, especially
if they cross different jurisdictions.
Some regions and countries are already working on the legal and regulatory
adjustments needed to trigger deployment of dedicated hydrogen infrastructure.
In December 2021, the European Commission adopted a legislative proposal torecast the 2009 EU Gas Directive, proposing a Hydrogen and Decarbonised Gas
markets package, which aims to put forward measures to support the creation of
dedicated hydrogen infrastructure. In March 2023, EU energy ministers agreed on
the Council’s position, and the legal acts should be formally adopted once anagreement is reached with the European Parliament. The hydrogen package
proposal seeks to develop competitive hydrogen markets, unbundling 62 hydrogentransmission and setting a series of incentives for repurposing natural gas
infrastructure, and to attract investments for cross-border infrastructure.

Unbundling refers to the separation of activities potentially subject to competition, such as hydrogen production, from thosewhere competition is not possible or allowed, e.g. transmission and distribution, which is a regulated monopoly in theEuropean Union. This would allow the independent transmission system operator model under certain conditions.

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Chapter 4. Trade and infrastructure

Belgium already has an extensive hydrogen network connecting to France andthe Netherlands, spanning around 600 km (the largest network in Europe andsecond in the world after the United States) and owned by Air Liquide. Belgium
passed pioneering legislation on the transport of hydrogen by pipelines, the firstof its kind in the world, which entered into force in August 2023. This law aims toregulate hydrogen transmission networks, establish criteria for designating asingle hydrogen transmission system operator, and entrust it with various
responsibilities, including strategic planning, ensuring free and non-discriminatory
access to the network and guaranteeing the quality of the hydrogen transported.
In May 2023, the Danish government selected the state-owned companies
Energinet and Evida to own and operate Denmark’s forthcoming hydrogenpipelines. This decision follows the Power-to-X tender that Denmark launched in
April 2023. The government also announced its intention to present a financing
proposal for the hydrogen transmission network by the end of 2023.
Also in May 2023, the German Federal Cabinet passed a draft law to create thelegal and regulatory framework for a future hydrogen transmission system,
expected to be operational by 2032. In July 2023, Germany’s gas system
operators presented a draft of a potential hydrogen transport network of 11 200 km
and 60% of repurposed natural gas pipelines, with a final version to be submitted
to the regulator BNetzA for approval by Q3 2023.
In August 2023, the UK government published proposals for hydrogen transportbusiness models, as a result of a consultation process. The proposals suggest a
Regulated Asset Base model alongside an external subsidy mechanism in theearly stages, avoiding very high transport costs when the network is not yet fully
utilised, while preventing excessive returns to developers.

Project announcements for dedicated pipelines
There have been substantial project announcements for hydrogen transmission
pipelines across and between countries during the past year, and a detailed list of
project announcements for the construction of new hydrogen pipelines or the
repurposing of natural gas pipelines for hydrogen can be found in the IEA
Hydrogen Infrastructure Database. 63

63

For release in October 2023.

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In Europe, the European Hydrogen Backbone initiative involves 33 gas
infrastructure operators from 25 EU member states, as well as Norway,
Switzerland and the United Kingdom. This initiative envisions a 33 000 km panEuropean hydrogen pipeline network by 2030, based on repurposed natural gas
pipelines wherever possible. The 2022 revised Trans-European Networks forGlobal Hydrogen Review 2023

Chapter 4. Trade and infrastructure

Energy (TEN-E) Regulation, which focuses on linking the energy infrastructure
between EU countries, now includes support for hydrogen infrastructure. It
identifies three priority hydrogen corridors: hydrogen interconnections in Western
Europe, hydrogen interconnections in Central Eastern and Southeastern Europe,and a Baltic Energy Market Interconnection Plan in hydrogen.
Outside of Europe, China’s first trans-regional hydrogen pipeline has been
included in its Implementation Plan for the Construction of a National Oil and Gas
Network, issued in 2023. This would transport hydrogen from Ulanqab (North
China’s Inner Mongolia Autonomous Region) to Beijing, with a length of more than
400 km and a capacity of 100-500 ktpa. In 2023, the state-owned China Petroleum
Pipeline Engineering Corporation suggested that the country may need 6 000 kmof hydrogen pipelines by 2050. In Oman, the Ministry of Energy has stated thathydrogen pipeline infrastructure will initially be situated around the ports in thesouth of the country, potentially connecting to nearby salt caverns, and later onother northern cities could be connected to the pipeline network, including Muscat.
In June 2023, OQ Gas Networks, Oman’s gas transportation system operator,
signed a memorandum of understanding with Hydrogen Oman (Hydrom) to
explore the development of a hydrogen network.
Figure 4.6 Global hydrogen transmission pipeline length in the Net Zero Emissions by
2050 Scenario and announced projects, 2020-2050

IEA. CC BY 4.0.
Note: km = kilometre.

The length of announced hydrogen pipelines over the next decade is in line with the needsof the NZE Scenario, if projects – most of which are at an early stage – come to fruition.

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No offshore hydrogen pipeline is in operation today. Despite this limited
experience and related uncertainties, several offshore pipeline projects have beenannounced. In June 2023, Gasunie launched a tender for a feasibility study for an

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

offshore hydrogen pipeline in the North Sea, including the design of the offshore
platform (compression/electrolysis) and the pipeline routing. In January 2023,
Norway and Germany commissioned a joint feasibility study to assess large-scaletransport of hydrogen from Norway to Germany, and CO2 transport from Germany
to Norway for offshore storage. The feasibility study is being carried out by Gassco(Norway’s gas operator) and dena (the German energy agency), and in
September 2023 the two countries set up a joint task force to follow up on the
results.
Other offshore pipelines are being considered, albeit still at a conceptual stage,
between Spain and France (H2Med - Bar-Mar); Algeria/Tunisia and Italy (SoutH2
Corridor); Finland, Sweden, Denmark and Germany (Baltic Sea Hydrogen
Collector); Denmark and Germany (H2 Interconnector Bornholm Lubmin).
Offshore pipelines in the North Sea are being considered more generally, such as
the AquaDuctus project (Germany), and as highlighted by the Ostend Declarationof Energy Ministers signed in April 2023 by Belgium, Denmark, France, Germany,
Ireland, Luxembourg, the Netherlands, Norway and the United Kingdom. If
offshore wind is going to be used for hydrogen production, the offshore productionof hydrogen and its delivery to the coast by pipeline can, in some cases, become
an alternative to transporting electricity for onshore hydrogen production (Box 4.2).
Nevertheless, uncertainties in production and demand, and the current limited
regulatory framework, may not be sufficient to provide financial and legal certainty
to potential investors in low-emission hydrogen infrastructure. While the length ofannounced projects adds up to almost 30 000 km by 2030, and is aligned with theneeds of the NZE Scenario (Figure 4.6), the combined length of projects having
reached FID is minimal (Table 4.2). However, as a first step, several calls havebeen launched in 2023 to confirm interest in hydrogen transmission infrastructure,
typically including an initial non-binding phase to understand market needs andconduct feasibility studies. This will be followed by a second binding phase tocontract transmission capacity, which will lead to investment decisions.

Country

LengthDate

StatusAustralia

43 km

May 2023

APA completed pressurised 100% hydrogen testing ina repurposed section of the Parmelia Gas Pipeline.
Detailed conversion plans will follow.

Belgium-

July 2023

Ministers Council agreed on a EUR 250 million
subsidy to develop a hydrogen pipeline network
connecting to Germany and industrial clusters in
Ghent, Antwerp, Mons, Charleroi and Liège.

France150 kmJanuary –GRTgaz launched a non-binding call to confirm
economic interest in the Hynframed project, linking up

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Progress between Q3 2022 and Q2 2023 on hydrogen transmission projects
in new and repurposed pipelines

Global Hydrogen Review 2023

Country

LengthChapter 4. Trade and infrastructure

Date

StatusMarch
2023

the Fos-sur-Mer industrial and port area with storage
facilities in Manosque, expected by 2028. This will befollowed by a binding Open Season process tocontractually determine transmission capacities.
GRTgaz and Fluxys launched a call (non-binding
phase) to assess interest in a hydrogen pipeline
between Valenciennes (France) and Mons (Belgium).
17 companies expressed their interest, and afeasibility study was launched.

FranceBelgium

70 km

June –
September
2022

Germany

50 km

June 2023

FID for Bad Lauchstädt Energy Park, including apipeline to TotalEnergies Refinery.

-

July –
September
2023

FGSZ has launched a call for interest (non-binding
phase) for hydrogen transmission capacity in the
Hungarian network and interconnection points with
Austria, Croatia, Romania, Serbia, Slovakia, Slovenia
and Ukraine.

June 2023

Gasunie reached FID (more than EUR 100 million) for
the first section of its planned hydrogen backbone(1 200 km) in Rotterdam, from the Tweede Maasvlakte
to Pernis. Construction starting in Q3/Q4 2023 andcommissioning expected by 2025.

270 kmMay - July
2023

Publication of the “Intention and proposal forparticipation” for the Delta Rhine Corridor, which
envisages the construction of several pipelines,
including for hydrogen, between Rotterdam, via
Moerdijk, to Chemelot industrial park in Geleen and to
the German border. The Dutch Ministry of Economic
Affairs and Climate and Gasunie invited stakeholders
to contribute to the spatial planning for the design ofthe project.

-

September–
November
2023

Enagás is launching a non-binding call for interest forhydrogen transport infrastructure. Based on the
results, a binding Open Season process could belaunched in 2025.

Hungary

Netherlands

Netherlands

Spain

Box 4.2

30 km

Offshore hydrogen networks or power transmission to shore todeliver hydrogen?

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Less than 10% of announced low-emission hydrogen production by 2030 could
rely on offshore wind, equivalent to about 3 Mt H2. While offshore wind parks aretoday located relatively close to the coast, new projects are being planned further
out to sea. The cost of offshore power transmission for onshore hydrogenproduction increases relatively quickly with distance, whereas offshore hydrogenproduction and subsequent transport incurs fixed costs, such as platforms for theelectrolysers and AC/DC inverters, leading to higher transport costs for shorter

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

distances compared to offshore power transmission and onshore hydrogenproduction. For distances of less than 300 km to shore, power transmission may
be cheaper than offshore hydrogen production and pipeline transport. However,for longer distances, offshore hydrogen production and transmission may become
more cost-effective, especially if it can benefit from the economies of scale ofpipelines. There are some uncertainties about the operating pressures of offshorehydrogen pipelines. While offshore natural gas pipelines operate at higher
pressures, this could increase the risk of embrittlement with hydrogen and further
research is needed.

USD/kg H₂

Cost of offshore hydrogen and power transmission
5

HVAC line

4

Offshore pipeline, 20-inch

3

HVDC line

2

Offshore pipeline, 36-inch

1

Offshore pipeline, 48-inch

0

100

300

500

700

900 1 100 1 300 1 500 1 700 1 900 2 100 2 300 2 500km

IEA. CC BY 4.0.
Notes: HVAC = high voltage alternating current; HVDC = high voltage direct current.

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For short distances of offshore hydrogen transport, non-metallic composite
pipelines are being explored for their light weight (easier transport and laying),
ductility, spoolability and corrosion resistance. Strohm, a developer ofthermoplastic composite pipelines, has signed memoranda of understanding(MoUs) with Evonik, Siemens Gamesa, Seanovent and Lhyfe to explore the useof pipelines from polyamide 12, which has low hydrogen permeation. The HOPE
project, a consortium co-ordinated by French company Lhyfe, aims to produce
4 t H2/day and transport it, for the first time, via a 1 km offshore composite pipelineto the port of Ostend (Belgium) by 2026. Other companies, such as SoluForce andPipelife, have developed a reinforced thermoplastic pipeline for hydrogen
applications up to 42 bar, and Long Pipes has developed a composite pipeline
technology called Hydrogen Highway.

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Chapter 4. Trade and infrastructure

Hydrogen blending
Blends of natural gas and hydrogen are already being used in several town gas
networks in Singapore, Hong Kong and Hawaii, which plan to eventually replacefossil-based hydrogen with low-emission hydrogen. 64
Since the GHR 2022, a few hydrogen blending demonstration projects haveentered operation around the world (Table 4.3); nevertheless, hydrogen blending
in distribution networks may sometimes meet strong local opposition. For
instance, the United Kingdom’s first hydrogen village trial proposal is no longer
under consideration by the government due to a lack of support from residents.
Hydrogen blending projects in gas distribution pipelines entering operation
between Q3 2022 and Q2 2023
Project name
ATCO Community
Blending project
ATCO Alberta
blending projectGasvalpo Energas
Coquimbo
NTPC-GGL in
Surat
Floene Seixal
20HyGrid project –Delgas Grid
Dominion Energy
UtahCountry

Location

Blending
volumeAnnounced size

Australia

Cockburn

2-5%

2 700 customers

CanadaFort
Saskatchewan

5%

2 100 customers

Chile

Coquimbo

5-20%

2 000 customers

India

Surat

5%

200 customers

Portugal

Seixal20%

82 customers

Romania

Dârlos20%

75 customers

United States

Delta

5%

1 800 customers

Hydrogen blending in the transmission network is also being considered, as it
could enable the co-utilisation of the existing network until dedicated infrastructure
is in place, if deblending and purification technologies become available and costefficient. This would likely require a system of guarantees of origin, such as thatin place in the Netherlands. In February 2023, Kogas (Korea) selected DNV toassess the feasibility of blending hydrogen into the country’s 5 000 km
transmission network, as it aims to achieve 20% blending by 2026. In March 2023,
the European Union altered the EU Gas Proposal, so that the maximum blendingof hydrogen into the natural gas transmission system would be 2% instead of 5%
to ensure a harmonised quality of gas. In April 2023, China National Petroleum
Corporation announced that it had transported blended hydrogen (24%) using a
397 km gas pipeline in Ningxia for 100 days. In May 2023, Xcel Energy(United States) awarded Worley a study to assess the feasibility of injecting

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64
A list of hydrogen blending projects and their status can be accessed through the IEA Hydrogen Infrastructure Database(October 2023 release).

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

blended hydrogen in its 58 000 km distribution pipelines and 3 500 km
transmission pipelines, including the assessment of blending rates. In June 2023,
Portugal’s REN announced that it had started adapting its high-pressure naturalgas grid (1 375 km) to allow it to carry up to 10% hydrogen. However, deblending
technology is not yet available on a large scale. In January 2022, Linde
commissioned the world's first full-scale demonstration plant in Dormagen(Germany), which can produce hydrogen with a very high purity from blends of 560% using membrane separation followed by pressure swing adsorption.

Underground hydrogen storage
As hydrogen supply expands, underground geological facilities could be needed
for storage to balance supply fluctuations caused by variable renewable electricity
used in electrolysers and from seasonal changes in demand, as well as to bolster
energy security. Salt caverns have been utilised for hydrogen storage in Teesside(United Kingdom) since 1972 and in the Gulf Coast in Texas (United States) since
1983, primarily for chemical and petrochemical processes, with a total capacity of
500 GWh.
New salt cavern facilities for hydrogen storage have been announced and somehave made a degree of progress on planning, but none of them have reached FID
yet. A detailed list of project announcements for the construction of newunderground hydrogen storage facilities or the repurposing of natural gas storage
facilities for hydrogen can be found in the IEA Hydrogen Infrastructure Database. 65
In 2023, for the first time, several calls have been conducted to confirm andquantify interest in underground hydrogen storage facilities (Table 4.4). These
calls provide valuable input for estimating facility sizing and ultimately reaching
the FID. They are often organised in at least two phases, starting with a nonbinding phase, followed by a binding phase if there is sufficient interest. The UK
government’s proposals for hydrogen storage business models suggest aminimum annual revenue floor for storage providers with contracts negotiatedbilaterally between the storage providers and the subsidy provider, protecting
against the demand risk.

Organiser
Géométhane

65

Country

Call date

Phase

Description

FranceFebruaryMarch2023

Nonbinding

Assess interest in hydrogen storage
in two potential salt caverns(200 GWh of hydrogen) in
Manosque.

For release in October 2023.

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Calls for interest for underground hydrogen storage projects

Global Hydrogen Review 2023

Organiser

Country

Chapter 4. Trade and infrastructure

Call date

Phase

HyStock(subsidiaryof Gasunie)

Netherlands

June-July
2023

Nonbinding

TerégaFranceJuneOctober
2023

Nonbinding

Description
Call to reserve capacity (fixedproportion of injection, withdrawal,
and storage capacity) in the A5hydrogen salt cavern (216 GWh) in
Zuidwending. Reservations exceed
the capacity offered, and an auction
will allocate capacity.
Assess interest in hydrogen storage
in a salt cavern (500 GWh) within the
HySoW project (Hydrogen SouthWest Corridor of France).

Furthermore, several salt cavern hydrogen storage projects are progressing. In
June 2022, the Advanced Clean Energy Storage project in Utah (United States)
secured a conditional Department of Energy (DOE) loan guarantee of
USD 504 million. Although FID has not yet been reached, WSP completed drillingand mechanical integrity testing of two salt caverns wells (300 GWh) in May 2023.
From November 2022, the H2CAST project conducted a two-month leak test in
Etzel (Germany), confirming the tightness of the salt cavern and the use of bore
hole equipment with high-pressure hydrogen. The H2CAST project plans to test
the conversion of a first salt cavern, formerly used for natural gas storage, forhydrogen storage by the end of 2023. Meanwhile, the HyPSTER project (Etrez,
France) aims to demonstrate the impact of hydrogen cyclic storage in salt caverns.
In March 2023, it started work to replace the existing equipment in the salt cavernwith hydrogen-compatible equipment in preparation for upcoming tests.
In addition to salt caverns, hydrogen might also be stored underground in porous
media formations such as depleted oil and gas reservoirs or saline aquifers,
although they have not yet been proved for pure hydrogen storage. Hydrogen
reactivity has been observed in porous reservoirs when town gas was injected,
sometimes resulting in very high consumption of stored hydrogen. However, itremains to be assessed whether these findings would also apply to pure hydrogenstorage.

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In 2016, in the Underground Sun Storage pilot project (Austria), 115 000 Nm3 ofgas containing 10% H2 was injected into a depleted gas field for 3 months. About
18% of the hydrogen was not recovered due to diffusion, mixing, dissolution andconversion, while identified methane-producing bacteria converted 3% of thehydrogen. In April 2023, 2 years after the start of the Underground Sun Storage2030 project, the facility to test the storage of pure hydrogen in a depleted gas
field entered into operation in Gampern (Austria), with a capacity of 4.2 GWh ofelectricity storage (i.e. approx. 2.5 GWh of hydrogen storage). Snam (Italy)
verified the possibility of storing up to 100% hydrogen in a lab test unit of two
depleted gas fields, and plans to conduct further tests throughout 2023. In
September 2023, in the HyStorage project, Uniper will carry out the first hydrogenGlobal Hydrogen Review 2023

Chapter 4. Trade and infrastructure

injections, testing different methane-hydrogen mixtures with 5%, 10% and 25%hydrogen content and storing them for 3 months in a porous rock formation at the
Bierwang underground gas storage facility (Germany). In the United States, theDOE is providing USD 6.75 million in funding for the Subsurface Hydrogen
Assessment, Storage, and Technology Acceleration (SHASTA) project. SHASTA,
running from 2022 to 2024, aims to assess the feasibility of storing pure hydrogenand hydrogen blends in porous reservoirs. In addition, in 2023 the DOE awarded
funding for fundamental research to assess the feasibility of using depleted oil andgas fields in Oklahoma, North Dakota and the Appalachian region for hydrogenstorage.

500

1 200

400

900

300

600

200

35

TWh

1 500

bcm

TWh

Figure 4.7 Global underground geological storage capacity for hydrogen in the Net
Zero Emissions by 2050 Scenario and announced projects, 2020-2050
30

Aquifer

25
Depleted gas field

20
15

Hard rock cavern

10
300

100

2020

NZE

2030

Salt cavern

5

2040
2050
Announced projects

2030
2050
Announced projects

IEA. CC BY 4.0.
Notes: bcm = billion cubic metres; TWh = terawatt-hour; NZE = Net Zero Emissions by 2050 Scenario. The NZE Scenario
assumes that storage capacity equals 3% of total annual hydrogen demand in 2030 and 10% in 2050. “Announced
projects” are projects that are not yet operational, including those under construction, with a final investment decision,under feasibility assessment and projects that have been publicly announced, e.g. through a press release or amemorandum of understanding. The year 2050 illustrates announced projects without a specified start year.
Source: IEA Hydrogen Projects, (Database, October 2023 release).

The long lead times associated with underground hydrogen storage projects mean that
accelerated action is urgently required to get on track with the NZE Scenario.

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Despite recent announcements, the capacity of underground hydrogen storage
facilities projects – 5 TWh by 2030 and 30 TWh by 2050 – falls well short of what isrequired in the NZE Scenario (Figure 4.7). In addition, due to hydrogen’s low
density, storing an equivalent amount of energy as hydrogen requires three to fourtimes the volume compared to natural gas at the same pressure. In the NZE
Scenario, 74 TWh (26 bcm at normal conditions) of underground hydrogen storage
would be needed by 2030, compared to 4 800 TWh (490 bcm) of undergroundnatural gas storage today. By 2050, underground hydrogen storage needs would
increase almost twenty-fold, and this substantial rise in physical storage needs
would bring them to a level comparable (in terms of volume) to the long-standing
underground natural gas storage facilities developed over more than half a century.

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Chapter 4. Trade and infrastructure

Infrastructure for shipping
For long distances of more than 2 500 km, the transport of hydrogen or hydrogen
carriers by tanker can be a cost-effective option. In addition to the ships, this would
require dedicated infrastructure at ports, including access to deep-water
infrastructure and facilities to convert hydrogen into hydrogen carriers, in somecases at the exporting port, and, in some instances, facilities for reconversion backto hydrogen at the importing port. Hydrogen can be transported as ammonia,
methanol or synthetic fuels, using an LOHC or in the form of liquefied hydrogen(LH2).

Infrastructure at ports
Currently, export infrastructure for natural gas and ammonia, such as liquefaction
plants, is mainly located in regions with abundant natural gas resources. In contrast,
import infrastructure such as regasification plants is more widespread, due to there
being more importing countries than exporting countries. Worldwide, there are morethan 100 natural gas liquefaction plants in more than 40 ports and more than 160
natural gas regasification plants in nearly 150 ports. Approximately 150 terminals
and ports can handle ammonia (Figure 4.8).
Figure 4.8 Existing and announced port infrastructure projects for hydrogen andhydrogen-based fuels trade

IEA. CC BY 4.0.
Notes: LOHC= liquid organic hydrogen carriers.

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Almost 150 terminals for ammonia already exist and – while ammonia dominates the new
project announcements – port facilities for other carriers are also being planned.

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Chapter 4. Trade and infrastructure

Although the existing ammonia infrastructure could already be used for hydrogenbased fuel trade, current global ammonia trade is around 20 Mt, equivalent toaround 3.5 Mt H2. This is well below the announced 12 Mt H2 by 2030 for ammoniabased projects (Figure 4.1). Meeting this demand would require a tripling of existing
ammonia trade infrastructure within this decade. While some capacity could be
integrated into existing plants, potentially replacing fossil-based ammonia trading,or increasing annual plant utilisation with minor adjustments, realising the fullpotential of announced trade projects would require significant expansion. In
addition, countries with good renewable energy resources that have not previously
played a role in energy or ammonia trade may begin to do so, requiring not only
new ammonia storage tanks but also new deep-water ports and berthing facilities.
Some projects are exploring the possibility of exporting compressed or liquefiedhydrogen, which will require novel infrastructure that is not yet commerciallyavailable. Bringing such innovations to scale in the near future will require significant
innovation efforts. In addition, other trade projects are considering the use ofalternative carriers, such as LOHCs or methanol, which could use the moreabundant oil-related infrastructure in ports, thereby minimising investment
requirements for new infrastructure.
Based on announced projects, around 50 terminals and port infrastructure for the
trade of hydrogen and ammonia could be realised by the end of the decade. Morethan half are new ammonia export terminals, of which more than ten could belocated in Australia. In Europe, particularly in the Netherlands, Belgium andGermany, several ammonia import terminals have been announced. In the port ofRotterdam, OCI reached FID for the expansion of its existing ammonia terminal(June 2022) and it is assessing the feasibility of building a new storage tank,Gunvor contracted McDermott for the Front-End Engineering Design (FEED) of a
new ammonia import terminal (September 2022), and other new ammonia importterminals under consideration in the port are ACE Terminal and Koole Terminals.
Some liquefied natural gas (LNG) regasification terminals have announced theirinterest in importing synthetic methane. In July 2023, the European Union
approved EUR 40 million support for a land-based LNG terminal in Brunsbüttel
(Germany), to replace the current floating one, on the condition that the terminal
be converted to import renewable energy carriers by 2043 at the latest. A detailed
list of low-emission hydrogen infrastructure projects at ports can be found in the
IEA Hydrogen Infrastructure Database. 66
In addition to related port infrastructure, several large-scale ammonia cracking
projects have been announced, although the technology is not yet proven on acommercial scale. Facilities are being considered in Wilhelmshaven, Rostock andBrunsbüttel (Germany), in the port of Antwerp (Belgium), in the ports of Liverpool

For release in October 2023.

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66

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and Immigham (United Kingdom), as well as two facilities in the port of Rotterdam(Netherlands), which could crack ammonia to supply around 1.5 Mt H2 by 2030.

Tankers for hydrogen transport
Existing tankers can carry low-emission hydrogen-based fuels and LOHCs, apartfrom LH2. Ammonia, a gas at ambient temperature, requires liquefied gas tankers,
while methanol, synthetic fuels and LOHCs, being liquids, can be shipped inchemical (including dedicated methanol tankers) or oil product tankers. Currently,
around 40 tankers exclusively transport ammonia, along with up to 200 gas
tankers capable of carrying ammonia. However, meeting the potential tripling ofammonia trade in this decade would require a significant increase in the numberof gas tankers. This may be hampered by the relative technical complexity ofliquefied gas tankers, with only few shipbuilding yards in Korea, Japan and Chinabuilding these tankers. This could potentially create bottlenecks in the short term.
In addition, addressing maritime decarbonisation remains a challenge for alltankers, as the carbon intensity of low-emission hydrogen must account foremissions from possible transport. In 2016, the first dual-fuel methanol tankers
that can run on their methanol cargo were introduced, and by early 2023, there
were 23 dual-fuel methanol tankers. Existing fleets can potentially be adapted for
low-emission marine fuels, contingent on the space needed for new tanks andadditional equipment. The decarbonisation of ammonia, chemical and producttankers must progress in parallel with the growth of low-emission hydrogen trade.

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There are currently no commercially available tankers for shipping liquefiedhydrogen. The Suiso Frontier, with a capacity of 1 250 m3 (~75 tonnes [t] of LH2),
was the only demonstration project, with an LH2 shipment from Australia to Japan
in 2022. However, a valve malfunction in the gas combustion unit for hydrogenboil-off resulted in a fire while the ship was berthed in Australia. Lessons learned
from this incident will be incorporated into a new design of the gas combustion unit
for a larger 20 000 m3 tanker (~1 200 t LH2). Given the critical aspect of dealing
with hydrogen boil-off gas, Shell signed an MoU with Alfa Laval in December 2022
to develop a gas combustion unit for excess hydrogen boil-off. Several companies
are developing liquefied hydrogen tankers, expected to be operational by 2030,
with a hydrogen cargo capacity of up to 160 000 m3 (~9 600 t LH2) (Table 4.5). In
addition, efforts to use hydrogen to power ships may have positive spill-overeffects, as the technologies could be applied to LH2 tankers to allow part of the
cargo to be used as fuel.

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Chapter 4. Trade and infrastructure

Compressed hydrogen shipping is being considered alongside liquefied hydrogenas an option for shipping hydrogen, particularly at smaller scales. In December
2022, Provaris Energy (Australia) received design Approval in Principle from theAmerican Bureau of Shipping (ABS) for a 26 000 m3 (250 bar, 430 t H2) hydrogentanker called H2Neo, with first units expected by 2026, and is developing a larger
120 000 m3 tanker, H2Max (2 000 t H2). In the German OffsH2ore project,
Kongstein has developed a concept for a compressed hydrogen tanker for theoffshore wind industry. Hydrogen produced offshore could be compressed to
500 bar, loaded onto a 400-tonne H2-tanker and shipped to shore.
Announced designs for liquefied hydrogen tankers expected to becommercial before 2030
H2 cargo
containment

Country

Approval inprinciple*

Volume(m3)

Spherical

Korea

Korean Registerof Shipping (KRS)

20 000Samsung Heavy Industries

Type C

Korea

ABS

20 000

Houlder, Shell, CB&I

Spherical

UnitedKingdom

DNV (H2
containment)

20 000Spherical

Netherlands-

37 500MembraneFrance150 000

Kawasaki Heavy Industries(KHI)

Spherical(technologicaldevelopment
completed)

Expected from
Bureau Veritas

Japan

Nippon Kaiji
Kyokai (ClassNK)

160 000

Samsung Heavy Industries

Membrane

Korea

Lloyd’s Register

160 000

Company
Korea Shipbuilding &Offshore Engineering(KSOE), Hyundai Mipo
Dockyard

C-Job Naval Architects, LH2
EuropeTotalEnergies, GTT, LMG
Marin, Bureau Veritas* An Approval in Principle is an independent assessment of conceptual and innovative shipbuilding within an agreed
framework, confirming that the ship design is feasible and that no significant obstacles exist to prevent the concept frombeing realised.
Note: m3 = cubic metre.

Carbon intensity of hydrogen transport
The complexities of transporting low-emission hydrogen over long distances may
result in a potentially higher carbon footprint compared to natural gas, if the energy
inputs required to transport hydrogen are not decarbonised.

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Emissions from hydrogen transmission by pipeline depend on the electricity used
for compression, and emission factors are likely to be lower when compression
takes place near the production site, as low-emission electricity should already beavailable when producing electrolytic hydrogen, for example. However, if thepipeline crosses different regions and countries, low-emission electricity may notalways be available along the pipeline route, so the electricity used forGlobal Hydrogen Review 2023

Chapter 4. Trade and infrastructureintermediate compression stages may significantly increase the emissions forhydrogen transport. Using, for example, electricity with an emission factor of
540 g CO2-eq/kWh (world average emission factor for natural gas-based
electricity generation, including upstream emissions) to compress hydrogen for
5 000 km in a 48-inch pipeline (operating at 100% of its design capacity) would
result in emissions of 1 kg CO2-eq/kg H2. Alternatively, compressors may be
powered by hydrogen from the pipeline, i.e. driven by hydrogen turbines insteadof electrical motors, minimising the emissions associated with transmission to
those associated with the low-emission hydrogen used for compression.
For long-distance transport, hydrogen can be converted into a denser form, either
by liquefaction or conversion into a more easily transportable chemical carrier,such as ammonia or an LOHC. The transport of hydrogen via tanker can lead totwo types of emissions: emissions from converting hydrogen into hydrogen
carriers as well as reconverting it back into hydrogen, and emissions from the fuelused by the tanker (Figure 4.9).

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If hydrogen is liquefied, most of the energy is consumed at the point of export, andin the case of electrolytic hydrogen, this means it could potentially have access to
low-emission electricity, unless the export port is far away from the production site.
However, if hydrogen is transported as a chemical carrier (ammonia or LOHC), itsreconversion to pure hydrogen (if required) would result in significant energy
consumption at the import location. If ammonia cracking and LOHC
dehydrogenation processes use some of the low-emission hydrogen beingtransported to meet their heat requirements, the resulting emissions depend on
the emissions associated with the low-emission hydrogen transported and theelectricity consumption at the facility. For example, if hydrogen with an emission
intensity of 1 kg CO2-eq/kg H2 is transported (using zero-emission marine fuel),
the impact of ammonia cracking and LOHC dehydrogenation would be slightly lessthan 1 kg CO2-eq/kg H2 in addition to the emissions associated with production.
However, if the emission factor for electricity is 600 g CO2-eq/kWh, the emissions
associated with the reconversion to hydrogen could rise to 2 kg CO2-eq/kg H2.

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

Figure 4.9 Emissions of hydrogen transport by pipeline and tanker depending on the
distance and the grid emission factor of the importing region
LH₂

kg CO₂-eq/kg H₂

Pipeline
7

7

6

6

5

5

4

4

3

3

2

2

1

1

0

0
100

5 000

10 000

15 000

20 000Compression, 0 kg CO₂-eq/MWh
Compression, 200 kg CO₂-eq/MWh
Compression, 400 kg CO₂-eq/MWh
Compression, 600 kg CO₂-eq/MWh

100
5 000
Liquefaction

10 000

15 000

20 000km

Shipping, cargo fuelRegasification, 0 kg CO₂-eq/MWh
Regasification, 200 kg CO₂-eq/MWh
Regasification, 400 kg CO₂-eq/MWh
Regasification, 600 kg CO₂-eq/MWh

kg CO₂-eq/kg H₂

NH₃

LOHC

7

7

6

6

5

5

4

4

3

3

2

2

1

1

0

0

100
5 000 10 000 15 000 20 000
ASU+Haber Bosch
Shipping, cargo fuelShipping, marine fuel oil
Ammonia cracking, cargo fuel, 0 kg CO₂-eq/MWh
Ammonia cracking, cargo fuel, 200 kg CO₂-eq/MWh
Ammonia cracking, cargo fuel, 400 kg CO₂-eq/MWh
Ammonia cracking, cargo fuel, 600 kg CO₂-eq/MWh
Ammonia cracking, marine fuel oil

100

5 000
10 000 15 000 20 000
km
Hydrogenation
Shipping, zero emission fuelShipping, marine fuel oil
Dehydrogenation, zero emission fuel, 0 kg CO₂-eq/MWh
Dehydrogenation, zero emission fuel, 200 kg CO₂-eq/MWh
Dehydrogenation, zero emission fuel, 400 kg CO₂-eq/MWh
Dehydrogenation, zero emission fuel, 600 kg CO₂-eq/MWh
Dehydrogenation, marine fuel oil

IEA. CC BY 4.0.
Notes: ASU = air separation unit; LH2 = liquefied hydrogen; LOHC = liquid organic hydrogen carrier; MWh = megawatthour; NH3 = ammonia. The illustrative analysis is based on an emission intensity of hydrogen production of 1 kg CO2-eq/kg
H2, an emission intensity of electricity of 20 kg CO2-eq/MWh at the export port and different grid emission factors at theimporting location. Illustrated values are cumulative, e.g. if the importing region has a grid emission factor of 400 kg CO2eq/MWh, those areas below that value (0 and 200 kg CO2-eq/MWh) should also be considered. Hydrogen transport bypipeline assumes a 48-inch pipeline used at 100% of its nominal capacity. Cargo fuel refers to using the shipped cargo asfuel in the case of LH2 and ammonia. Zero-emission fuel represents a shipping fuel with zero direct greenhouse gas
emissions. For the use of marine fuel oil, the direct emissions are included, but not any upstream and midstream emissions
related to oil production and refining. Emissions include conditioning, i.e. the conversion of hydrogen into other carriers at
the export port and the reconversion back into hydrogen at the import port. Ammonia cracking is assumed to burn imported
ammonia to provide process heat, while LOHC dehydrogenation is assumed to use dehydrogenated hydrogen for process
heat. The areas "Ammonia cracking, marine fuel oil" and "Dehydrogenation, marine fuel oil" illustrate the emissions
associated with the transport of the fuel by ship, i.e. ammonia or dehydrogenated hydrogen used to provide process heat
for the ammonia cracking and LOHC dehydrogenation processes, respectively, without being delivered to the consumer.
Emissions from unburned boil-off hydrogen or fugitive emissions of hydrogen are not considered.

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Hydrogen transport can have a significant carbon footprint, and the maritime sector is not
yet decarbonised, especially with regards to lower density shipping technologies.

Global Hydrogen Review 2023

Chapter 4. Trade and infrastructure

The emissions from the tanker transport will depend on the fuel used for thevoyage. If LH2 is used as a marine fuel, the associated emissions would remain
small and proportional to the emissions associated with the production of thetransported hydrogen, the transport distance, the amount of unburned boil-offhydrogen and other fugitive emissions. Shipping hydrogen in tankers that do not
use low-emission fuels, particularly using marine fuel oil, would result in a highcarbon footprint. For instance, shipping ammonia or LOHC over 15 000 km would
result in emissions of 1.2 kg CO2-eq/kg H2 or 3.9 kg CO2-eq/kg H2, respectively.
These emissions take into consideration that some of the hydrogen is usedinternally in the reconversion process, i.e. it is transported to the import port but
will not be delivered to a final consumer.
As the emissions associated with imported hydrogen increase as marine fuel oil
is consumed during the voyage, the emissions from the use of thatammonia/hydrogen in the ammonia cracking or LOHC dehydrogenation process
also increase, adding to the total emissions associated to shipping.
Ensuring the decarbonisation of tanker transport itself is therefore crucial to enable
the delivery of low-emission hydrogen over long distances without significantly
increasing the carbon footprint, and may pose a challenge for compliance withregulatory frameworks with well-to-point of delivery (or well-to-tank) and well-towheel system boundaries, such as the 3.4 kg CO2-eq/kg H2 of the EU Renewable
Energy Directive II. With hydrogen being an indirect GHG, it is also important tobetter understand and account for potential leakages along the hydrogen supply
chain, including storage, loading/unloading and transport (Box 4.3).

Box 4.3

Hydrogen leakage monitoring

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Hydrogen is not a direct GHG, but it interacts with other compounds in theatmosphere, affecting the concentration of the GHGs methane, tropospheric ozone
and stratospheric water vapour. While hydrogen does not have anIntergovernmental Panel on Climate Change (IPCC)-defined global warming
potential (GWP), the latest scientific estimates suggest that hydrogen could havea GWP over a 100-year time horizon of 11.6 ± 2.8 kg CO2-eq/kg H2. Hydrogen has
a short atmospheric lifetime, and estimates suggest that its global warming
potential over a 20-year horizon would be more than three times higher than its
100-year impact. Given hydrogen’s small molecule size, high diffusivity and low
viscosity, leakage can occur throughout its value chain, with transport and storage
posing higher risks. However, quantitative information on hydrogen leakage
remains limited. Mitigating potential climate impacts will require further research toGlobal Hydrogen Review 2023

Chapter 4. Trade and infrastructuredevelop technologies and operational practices that minimise leaks, as well as
robust leak detection and repair mechanisms.



In March 2023, US company Aerodyne Research, in collaboration with theEnvironmental Defence Fund and with funding from the DOE’s Small Business
Innovation Research Program, unveiled a hydrogen sensor using laser
spectroscopy capable of detecting leaks as low as 10 ppb within a second.
However, the sensor remains expensive (estimated at around USD 100 000
per sensor, compared to devices for methane that can cost a few thousand
dollars) and has not yet reached commercialisation.



In March 2023, US company NETL was granted a patent for an optic hydrogensensor capable of measuring hydrogen at underground storage facilities at the
ppm level, utilising multiple sensing points.



In 2023, the US DOE announced USD 2.2 million funding for improving theunderstanding of hydrogen as an indirect GHG and USD 8.6 million for R&D
activities to develop ppb-level hydrogen sensors.

In January 2023, the Green2TSO-OPTHYCS project started, with a
EUR 2.5 million grant from the EU Horizon Clean Hydrogen Joint Undertaking
programme, led by Spanish Enagás. The project aims to develop new opticalfibre sensors for continuous hydrogen leak detection in production, transportand storage processes.

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To assess hydrogen leakage, new regulations must prioritise detection andmonitoring, particularly in transport and storage. However, partly due to a lack ofsuch regulation, only a few technologies exist for hydrogen leakage detection.
These are currently insufficient as they focus on identifying large, potentiallyexplosive leaks for safety reasons, and lack the speed and sensitivity to measuresmaller leaks. Despite the lack of commercially available technology, several
projects are underway:Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

Chapter 5. Investment, finance andinnovation
Investments in the hydrogen sector
Investment in projects in operation and underconstruction
Government policies and the plans of project developers are translating into an
expanding flow of capital into the low-emission hydrogen sector. Based on projects
in operation and construction, we estimate that spending on electrolyser
installations hit a new record in 2022, at USD 0.6 billion globally, double the 2021
value (Figure 5.1). An additional USD 0.5 billion was spent in 2022 on projects
under construction to produce low-emission hydrogen with carbon capture,utilisation and storage (CCUS). Reaching the USD 41 billion of spending onelectrolyser installations in 2030 envisaged in the Net Zero Emissions by 2050
Scenario (NZE Scenario) would require 70% annual investment growth for theremainder of this decade.

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Since 2021, investment in hydrogen production has been dominated by arelatively small number of very large projects. Several final investment decisions(FIDs) in 2022 mobilised an unprecedented level of spending, even though thecapacity that entered operation in 2022 was lower than in 2021, when a single,
very large 150 MW installation started operation. Among these FIDs, the largest
were for the 2 GW NEOM Green Hydrogen project in Saudi Arabia and 320 MW
Green Hydrogen and Green Ammonia project in Oman, both aiming to produce
ammonia for exports from 2026. These were followed by a 260 MW facility at arefinery in Xinjiang, China, which entered operation in June 2023 and sets a new
benchmark for the scale of an operational plant. Another 80 MW project in China
was commissioned in June 2023 for use in a coal-to-chemicals facility. In Europe,
Shell’s Holland Hydrogen I in the Netherlands (200 MW) will have a capacity tentimes that of Europe’s largest existing plant, and is aiming to supply an existingrefinery by 2025. In Sweden, H2 Green Steel drew closer to an FID for anelectrolyser of over 700 MW and a new steel production plant: it has secured
EUR 3.5 billion (~USD 3.7 billion) of debt and EUR 1.8 billion (~USD 1.9 billion) of
equity since 2022.

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

Investment in electrolyser installations by region (left) and intended use(right), and Net Zero Emissions by 2050 Scenario requirements, 2019-2030

IEA. CC BY 4.0.
Notes: NZE = Net Zero Emissions by 2050 Scenario. 2022 values are estimated annualised spending on projects that areunder construction and due to enter operation in 2023. Estimates are based on capital cost assumptions and announced
capacities of electricity input or hydrogen output volumes per project, and include electrolysers for hydrogen supply used
for energy purposes or as an alternative to fossil fuel use in industry (such as chemical production and oil refining).
“Mobility” includes projects for which the hydrogen output is intended for use in vehicles; hydrogen intended for conversion
to hydrogen-based fuels is included in “Other”. These estimates supersede those published in IEA World Energy
Investment 2023.

Investment in electrolysers is growing fast, but would require 70% annual growth until 2030
to get on track with the NZE Scenario.

Two projects for producing hydrogen from natural gas equipped with CCUS also
took FIDs in 2022. Together, their hydrogen capacity will be three times larger
than all the installed electrolysers in the world today. In the United States, financial
close was reached in February 2023 on a facility in Texas to produce 0.2 Mt ofhydrogen for fertiliser production from 2025, with over 90% of the CO2 captured
and sent to dedicated geological storage. The capacity is equivalent to around
0.8 GW of electrolysis running 90% of the time. A hydrogen energy complex isunder construction in Canada to produce around 0.15 Mt of hydrogen from 2024
to be used in refining, petrochemicals, transportation and power generation, with
95% of the CO2 captured and sent to dedicated geological storage. The capacity
is equivalent to 0.6 GW of electrolysis running 90% of the time. It has grant funding
from the Federal and a provincial government (Alberta). While several similar
projects are well advanced in Europe and the Middle East, the more favourable
investment environment in North America has made it the leader in hydrogenproduction with CCUS.

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As spending on these electrolysis- and CCUS-related hydrogen projects flows
along the value chain to suppliers and contractors, the total market size for lowemission hydrogen is expanding accordingly (Box 5.1).

Global Hydrogen Review 2023

Box 5.1

Chapter 5. Investment, finance and innovation

Sizing the global market for low-emission hydrogen

As demand for low-emission hydrogen and hydrogen-based fuels grows, annual
capital investments in projects will converge towards total spending in the value
chains of these projects. Money that stems from hardware purchases andinstallation contracts will flow to suppliers and fund their procurement of inputs.
The sum of these sales represents the market value of the hydrogen andhydrogen-based fuels sector. In 2022, the USD 1 billion spent on projects to
produce low-emission hydrogen in the same year may not have perfectly matched
the full market value of the sector because some outlay on equipment andcomponent factories must precede project spending. By 2030, however, project
spending on production, transport and conversion to hydrogen-based fuels should
be a reliable proxy for market size. In 2030 in the Stated Policies Scenario(STEPS), market size rises to USD 12 billion, equivalent to the spending on
offshore wind in Europe in 2022. In the NZE Scenario, it rises much more quickly,
to USD 117 billion, roughly the size of the market for rooftop solar PV installationsin the Asia-Pacific region in 2022.
Billion USD (2022)

2022

Electrolysis installations

2030
STEPS

NZE

0.7

4.7

41

CCUS-equipped plants

0.5

0.6

16

Infrastructure

0.2

5.5

36

Hydrogen-based fuels
production

0

2.0

25

Total

1.4

12

117

LNG
infrastructure in
Africa and Europe

Offshore wind inEuropeRooftop solar PV
installations in
Asia-Pacific

Equivalent part of theenergy sector in 2022

Notes: LNG = Liquefied natural gas; NZE = Net Zero Emissions by 2050 Scenario; STEPS = Stated Policies Scenario.

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It is more challenging to project the total market value of the hydrogen andhydrogen-based fuels produced from installed assets in 2030 for several reasons.
Production costs in 2030 will depend to a large extent on uncertain electricity costs
for electrolyser operators, or fuel and CO2 prices for operators of CCUS-equippedplants. The share of these costs that is borne by taxpayers and consumers will
depend on policy decisions that are not yet fully formulated. Finally, costs may bear
little relationship to low-emission hydrogen prices, for which the means of market
discovery remain highly speculative. In some sectors, hydrogen prices may be
pegged to the price of the fuel they substitute, such as natural gas or diesel. Where
long-term contracts are available, such as those underwritten by governments,
prices may follow levelised costs plus the cost of hydrogen transport, storage andGlobal Hydrogen Review 2023

Chapter 5. Investment, finance and innovationa profit margin. In other situations, prices may reflect the prices of low-emission
alternatives, such as bioenergy, direct electrification or low-emission fuel imports.
For hydrogen-based fuels, prices for meeting target shares of sustainable aviationand maritime fuels may be set by the marginal international production cost.
These alternatives could lead to wide differences: if the average global price fordelivered hydrogen (including transport, storage and distribution) were USD 3/kg
in 2030, the total market value in the NZE Scenario would be USD 200 billion; if itwere USD 7.5 per kg in 2030, this would rise to USD 500 billion.

Policy support for new investments
Looking ahead, additional large FIDs are widely expected in Europe and North
America as a result of major policy initiatives and associated funding, which havebeen strengthened due to the ongoing energy crisis and regional ambitions tosecure value chains. The biggest boost to investment is likely to stem from the2022 US Inflation Reduction Act, coupled with the Hydrogen Hubs initiative
launched in 2021 and an expansion of the budget of the Loans Programme Office.
The pay-for-performance approach and magnitude of the tax credit systemcompared to project-based funding competitions has led to speculation that the
Act might lead to the relocation of projects to the United States, especiallyelectrolyser and component factories. This concern was partly fuelled byuncertainty about the environmental requirements for hydrogen to qualify for EU
incentives, which has since been mostly resolved. While many new US projects
have recently been announced, there is only anecdotal evidence to date that thesedevelopers’ other projects outside the United States no longer have their fullcommitment. More clarity is expected by the end of 2023, when the environmental
requirements to qualify for US tax credits are likely to be finalised.

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Among support measures in the European Union, the most notable is theestablishment in March 2023 of the European Hydrogen Bank, a European
Commission funding instrument. Its initial mandate will be “reverse auctions” thataward funding from the existing Innovation Fund to the lowest bidders for support
per unit of hydrogen meeting the European Union’s environmental criteria. The
budget for the first auction will be EUR 800 million (~USD 842 million). The
European Commission is exploring whether it could also carve out a budget tohelp potential external exporters of hydrogen into the European Union, as well as
to support electrolyser manufacturers. This would complement support frommember states via the Important Projects of Common European Interest (IPCEI)
provisions, approved in 2022. Also in Europe, the United Kingdom’s March 2023
budget promised GBP 20 billion (~USD 25 billion) over 20 years to CCUS-

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovationequipped facilities, and 408 MW of electrolysis projects were shortlisted in March2023 as part of GBP 240 million (~USD 296 million) available funding.
Several investments have been made into hydrogen-related infrastructure. These
include an FID by fertiliser company OCI to expand by 200% its 0.4 Mt ammonia
import terminal in the Netherlands by the end of 2023. Also in the Netherlands,
Dutch gas transmission operator Gasunie took an FID for more than
USD 110 million into 30 km of hydrogen pipeline to be operational by 2025.
Some concerns have been raised that the substantial public funding available forhydrogen-related investments in Europe and North America might place projects
in emerging markets and developing economies (EMDEs) at a disadvantage. Thisis because, in some cases, project developers might prioritise projects in locations
where public support leads to the highest profits. Some developers may also seek
to establish and ensure access to domestic value chains, for example in light of
the US Inflation Reduction Act incentives. However, there are also reasons tobelieve that this need not preclude investment elsewhere. Unlike for other energy
technologies, the US hydrogen tax credits have no local content requirements,and hydrogen incentives proposed by the EU Net Zero Industry Act are not highly
restrictive in this regard. In addition, a range of multilateral and bilateral sourcesof funds have been announced since 2022 to address fundamental investment
challenges in EMDEs (see below). Instruments such as the German H2Global
programme have been designed to offer stable contracts for purchase of lowemission hydrogen from overseas.

Cost inflation for new low-emission hydrogen projects

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Inflation has gripped the global economy since 2022, significantly increasing theprices of equipment and interest rates on loans. Within the energy sector, thesefactors particularly raise costs for developers of capital-intensive energy supplies
such as those from renewable electricity generation, batteries or electrolysis
hydrogen. Some hydrogen projects with feasibility studies that were conducted
before mid-2022 have had to rework their cost estimates and re-evaluate theirfinancial plans to accommodate cost increases of more than 50%. While mostintense in Europe and least consequential in China, cost inflation is depressing
investment activity around the world. It increases the gap between available public
support and production costs, it means that public funds cannot be shared acrossas many projects and it creates a much larger financial package to be financed foreach project. However, this recent reversal in the trend towards lower costs for
low-emission hydrogen plants is not expected to be permanent and, with costs
rising more slowly now, the main impact may be delays to FIDs rather thancancellations.

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

There are several different sources of cost inflation:•higher equipment costs•

higher labour costs for installation and operation•

higher interest rates for debt (also known as the cost of capital)•

more competition to work with a small number of engineering, procurement, andconstruction (EPC) contractors that can offer guarantees that enable borrowing at
a lower cost of capital•

higher fuel and electricity prices.

For electrolyser installations, the impacts of these factors can be especiallyharmful (Figure 5.2). Like renewable electricity plants, such as solar PV and wind,electrolyser costs are largely borne upfront, with low operational costs after
construction if dedicated renewable electricity capacity is installed to supply theelectrolyser. An increase in the cost of capital from, for example, 5% to 8% (in linewith a 3 percentage-point rise in risk-free rates), raises today’s project cost bynearly one-third. However, electrolyser installation and operation are unlike thosefor solar PV due to the need for pipework, pressurised equipment, specialist gas
handling expertise, interfaces between electrical, chemical and moving parts andother elements that require sophisticated engineering. 67 The higher labour inputs
for electrolyser installations have meant higher recent cost increases comparedwith solar PV, for example.
These cost increases exacerbate an existing tension in the sector caused by adisconnect between policy targets, cost expectations and the status of
manufacturing today, especially in Europe and North America. In many cases,
prospective buyers of electrolysers ask for prices that reflect the anticipated costsof an established, mass-manufactured electrolyser sector. Such prices are often
needed to meet investors’ required rates of returns, given the magnitude of public
incentives available. However, with considerable competition between suppliersof promising electrolyser technologies, some are not yet manufacturing their mostefficient designs at sufficient scale to meet buyers’ cost expectations.
Furthermore, they are unable to provide standard industry performance
guarantees as the experience is not yet available. Without such guarantees, thecost of capital for a project is higher.
Cost increases for hydrogen production projects have coincided with a relaxationof natural gas prices, particularly in Europe. Spot gas prices across north-east
Asian, North American and European markets dropped by close to 60% between
mid-December 2022 and the end of the first quarter of 2023. While low-emission

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67
While it is foreseeable that some of the onsite complexity of installation could be reduced in future with integrated andstandardised equipment packages, these so-called “balance of plant” costs will remain higher than for purely electricalsystems and higher operations and maintenance costs can likewise not be eliminated.

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovationhydrogen competes with natural gas in all potential applications, in existinghydrogen applications it often competes with hydrogen from unabated reformingof natural gas. The brief window in which some hydrogen projects had claimed
cost parity between their proposed hydrogen production and spot natural gas
prices has closed for now, though low-emission hydrogen costs below those forhydrogen from unabated fossil fuels may still be realised in coming years inregions relying on LNG imports for natural gas.

Levelised hydrogen cost (2021 = 100%)

Factors that could contribute to cost inflation for an electrolyser installation
since 2021
200%
Electrolyser equipment

150%

Electrolyser BOP and EPC
100%

Renewable power generationand storage
O&M

50%

WACC
2021

2023
IEA. CC BY 4.0.

Notes: BOP = balance of plant; EPC = engineering, procurement and construction; O&M = operational expenditures andmaintenance costs; WACC = weighted average cost of capital.
Sources: IEA analysis based on input from McKinsey & Company, the Hydrogen Council and various company contacts.

Rising costs due to inflation, particularly an increase in the cost of capital, are having astrong impact on the costs of hydrogen production from proposed electrolysis projects.

Multilateral financial commitments are growing

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Multilateral development banks stepped up their financial commitments in the areaof hydrogen in 2022 and so far this has continued apace in 2023 (Figure 5.3).
Nine-tenths of the funds have been made available as loans to governments of
EMDEs. This money can be used for project feasibility studies, capacity building
and support to project developers. A much smaller share, less than 1%, has beencommitted as technical assistance grants or project equity. Among funders, theEuropean Investment Bank (EIB) and World Bank have made the largest
commitments, notably to India, Brazil and Chile. Moreover, the World Bank Grouplaunched in November 2022 a Hydrogen for Development Partnership (H4D) tofoster capacity building and regulatory solutions, business models, andtechnologies towards the rollout of low-emission hydrogen in developing
countries.

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

Multilateral finance can assist the implementation of hydrogen strategies incountries that have fewer resources to invest in this area. In particular, some of
the finance has been directed to countries that are exploring opportunities toexport hydrogen. For example, the EIB has committed around USD 1 billion fromEU countries – some of which could become hydrogen importers – to Brazil, andover USD 0.5 billion to Namibia. It has also committed more than USD 1 billion to
India.

Billion USD (nominal)

Financial commitments to hydrogen by multilateral development banks, by
source and partner country, by year of announcement, 2021-2023*
5

5

4

4

3

3

2

2

1

1

2021
World Bank

2022
EIB

IDB

2023*
EBRD

ADB

India

2021
Namibia

2022
Chile

Türkiye

2023*
Other

IEA. CC BY 4.0.
Notes: 2023* = year to July 2023 only; EIB = European Investment Bank; IDB = Inter-American Development Bank;
EBRD = European Bank for Reconstruction and Development; ADB = Asian Development Bank; Türkyie = Republic ofTürkiye.

Multilateral development banks are increasing financial commitments with EMDEs in thearea of hydrogen.

There has also been an increase in bilateral financial commitments between
governments. Among the most active bilateral financiers is the German
development bank KfW, which has created a credit fund for hydrogendevelopment projects in EMDEs, and allocated USD 100 million to Chile in 2023.
In June 2023, Invest International, an agency of the Dutch government, granted
USD 44 million to create a fund for hydrogen projects in Namibia and
USD 50 million to a similar initiative in South Africa.

Financial performance of hydrogen firms
Unprecedented levels of investment in hydrogen companies have been mobilised
as near-term expectations for hydrogen projects have risen. To track this trend,
we assembled a portfolio of publicly traded companies whose success depends
on demand for low-emission hydrogen growing. 68 These companies span a range

To try to be as representative as possible the portfolio has been expanded from 33 to 43 members since the Global
Hydrogen Review 2022.

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Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovationof sectors, including electrolyser and fuel cell manufacturing, low-emissionhydrogen and ammonia project development, hydrogen distribution infrastructureand hydrogen-fuelled vehicles.
The total market capitalisation of the portfolio tracks some of the major clean
energy trends since 2019: initial hopes for high growth were buoyed through theCovid-19 pandemic by expectations that governments would ensure a quick
recovery, but rising interest rates in 2022 were compounded by the energy crisisand this led investors to withdraw equity from sectors struggling to meetshareholder requirements (Figure 5.4). By the end of August 2023, amid projectand contract delays, the market capitalisation of the portfolio had dropped back to
its level in July 2020. It would have been lower without the addition ofthyssenkrupp nucera in July 2023 via market listing that raised over USD 3 billion.
Meanwhile, while the monthly investor returns and revenues of this portfolio
performed very strongly up to 2021 and remain almost three times higher than five
years ago, they are now following the downward trend of more general cleantech
indices rather than the recent uptick enjoyed by established and less hardwareintensive technology firms (as represented by the NASDAQ).

Arithmetic return (January 2017 =100)

Monthly returns (left) and market capitalisation (right) of hydrogencompanies, hydrogen funds and relevant benchmarks, 2017-2023
500

100

400

80

300

60

200

40

100

20

2017

2018 2019 2020 2021 2022
IEA global hydrogen portfolio
NASDAQ composite index
S&P cleantech

2023

2017

2018 2019 2020 2021 2022 2023
IEA global hydrogen portfolio (USD billion)
Hydrogen ETFs (USD 10 million)

IEA. CC BY 4.0.
Notes: ETFs = exchange-traded funds; portfolio member tickers: 288620 KS, 336260 KS, 702 HK, ADN US, AFC LN,
ALHAF FP, ALHRS FP, AMMPF US, BE US, BLDP CN, CASAL SW, CI SS, CPH2 LN, CWR LN, F3C GY, FCEL US,
FHYD CN, GNCL IT, GREENH DC, H2O GY, HDF FP, HTOO US, HYON NO, HYPRO NO, HYSR US, HYZN US, HZR
AU, IMPC SS, ITM LN, LHYFE FP, MCPHY FP, NCH2 GY, NEL NO, NHHH CV, NXH CN, PCELL SS, PHE LN, PLUG US,
PPS LN, PV1 AU, SPN AU, TECO NO, VYDR US.
Source: IEA calculations based on Bloomberg (2023).

Since mid-2022, returns from a portfolio of 43 low-emission hydrogen firms have stabilised,
but their market capitalisation has fallen in line with lower valuations for technology firms.

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Even as the value of listed hydrogen companies has been adjusted downwards,
publicly traded dedicated hydrogen funds have largely maintained their value.
These funds are established to invest equity in a blend of private companies andGlobal Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

projects that are scaling up low-emission hydrogen supply and use. Since 2022
these funds have shifted their attention towards projects, which they now expect
to yield higher returns relative to technology companies in the medium term.

Venture capital investment
Start-ups working on hydrogen-related technologies and businesses raised record
amounts of early- and growth-stage equity in 2022. At USD 670 million, earlystage deals 69 matched the outstanding performance in 2021, which was almost
five times higher than in 2020 (Figure 5.5). Growth-stage funding, which requires
more capital but funds less risky innovation, more than doubled to USD 3.1 billion.
This is an even more impressive achievement in light of only a 1% increase overall
in growth-stage equity funding for energy firms (to USD 34.4 billion). However, themacroeconomic conditions that have reduced the amount of capital available forventure investments across the global economy in 2023 are likely to affect growthstage funding in particular, and this year’s level is set to be lower than in 2022.
Venture capital investment in energy start-ups in hydrogen-related areas,for early-stage and growth-stage deals, 2010-2023
Growth stage
Billion USD (2022)

0.7
0.6
0.5
0.4
0.3

3.5
3.0
2.5
2.0
1.5
1.0

0.2

Non-electrolysis H₂ production
Fuel cells
Other

2022

2023 Q1

2021

2020

2019

2018

2017

2016

2015

2014

2013

2012

2023 Q1

2021

2022

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

Electrolysis
Project development
Other mobility

2011

0.5

0.1

2010

Billion USD (2022)

Early stage
0.8

H₂-based fuels
Automotive

IEA. CC BY 4.0.
Notes: Early-stage deals are defined as seed and Series A deals; very large deals in these categories – above a value
equal to the 90th percentile growth equity deals in that sector and year – are excluded and reclassified as growth-stage
investments; “Other mobility” includes aviation and maritime; “Other” includes storage, other infrastructure and industrial
applications.
Sources: IEA analysis based on Cleantech Group (2023) and Crunchbase (2023).

Hydrogen firms achieved higher venture capital fundraising growth than other sectors in
2022, but a wider slowdown in venture capital has dimmed prospects for continued growthin 2023.

Equity investments that provide funds to support entrepreneurs with technology testing and design in return for a stake inthe start-up. These deals play a critical role in honing good ideas and adapting them to market opportunities.

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Chapter 5. Investment, finance and innovation

Notable early-stage deals since mid-2022 included those for: Hysata, anAustralian electrolyser developer raising USD 29 million; Hygenco, an Indian
project developer raising USD 27 million; Levidian, a British developer of methanecracking raising USD 15 million; and Fabrum, a New Zealand designer ofliquefaction equipment, raising USD 14 million. The largest growth-stage deal, atover USD 300 million, was for Monolith, a US developer of methane pyrolysis.
Start-ups in the United States have been the main recipients of venture capitaldeals in hydrogen-related technologies, apart from in two areas: fuel cells, an area
in which Chinese start-ups have dominated fundraising; and project development,
an area led by European start-ups (Figure 5.6).
As the size of hydrogen projects grows, the share of start-ups that are project
developers, not technology owners, has risen. However, growth-stage investment
and acquisitions still tend to favour technology owners. In an analysis of 391 startups founded since 1990 with activities related to hydrogen, 70% were found to
hold at least one patent application. More than 80% of the growth-stage
investment in hydrogen start-ups since 2000 was in companies that had alreadyfiled a patent application. Overall, 55% of all venture capital funding for hydrogen
start-ups went to the 117 companies that had filed patent applications in the period
2011-2020.
Early- and growth-stage equity investment in energy start-ups in hydrogenrelated areas by region, 2018-2022
0%

20%

40%

60%

80%

100%

Electrolysis
Non-electrolysis H₂ production
H₂-based fuels
Project development
Fuel cells
Automotive
Other mobility
United States

Canada

China

India

IsraelRest of world

United Kingdom

Other Europe

IEA. CC BY 4.0.
Sources: IEA analysis based on Cleantech Group (2023) and Crunchbase (2023).

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US hydrogen start-ups have been the main recipients of venture capital deals in all areas
except for fuel cells (dominated by Chinese firms) and project development (by European
firms).

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

Innovation in hydrogen technologies
Innovation in clean energy technologies needs to accelerate for hydrogen to playits role in the clean energy transition. The level of maturity of hydrogen-related
technologies varies widely across the supply chain, with technologies for lowemission hydrogen supply much more developed than for end uses (except forestablished applications in refining and the chemical industry).
Technologies for the production of low-emission hydrogen are well developed andinnovation continues to make major breakthroughs (Figure 5.7). Alkaline andproton exchange membrane (PEM) electrolysers are commercially available, butmanufacturers have a strong innovation focus to keep decreasing equipment
costs. Reducing critical material loads is a good example and this year H2U
Technologies announced the development of a 200 kW iridium-free PEM
electrolyser. Solid oxide electrolysers (SOEC), the most efficient electrolysis
technology, are quickly approaching commercialisation. The two largest
demonstration SOEC started operating in 2023, one by Sunfire (2.6 MW) and theother by Bloom Energy (4 MW). Anion exchange membrane (AEM) electrolysers
are at an earlier stage of development, but the technology is also evolving rapidly
and Enapter launched the world’s first megawatt AEM electrolyser in May 2023.
In addition, direct electrolysis of seawater was demonstrated for the first time in
an offshore platform in China in June 2023. In August 2023 Hysata opened its newelectrolyser manufacturing facility, where it will build a demonstrator (5 MW) of its
advanced alkaline capillary-fed electrolyser – claiming up to 95% efficiency – withthe view to reach commercial-scale units by 2025.

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The production of low-emission hydrogen from natural gas with CCUS requires
the achievement of very high CO2 capture rates at plant level. This technology is
set to be demonstrated at commercial scale for the first time soon, as two large
projects have begun construction since the release of the Global Hydrogen
Review 2022 (GHR 2022). These new plants are expected to become operationalin 2024 and 2025, and are designed to produce low-emission hydrogen via
autothermal reforming, which reduces the cost of raising capture rates above 90%.
This will represent a significant improvement compared with existing CCUSequipped hydrogen plants, which only capture around 60% of the CO2 comingfrom a steam methane reformer (SMR). This lower level reflects the relative easeof capturing CO2 from the natural gas used as a feedstock at an SMR, comparedwith the much higher cost of capturing the remaining 40% that comes from the
combustion of natural gas to generate the heat required in the process.
Meanwhile, Topsoe is pursuing innovations for the electrification of the heat for
the SMR, which would eliminate the need to burn natural gas for the SMR and
therefore only require capturing the feedstock-related CO2. In 2022, Topsoe

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

signed a EUR 45 million (~USD 47 million) loan agreement with the EIB
specifically to support R&D investments in such early-stage hydrogentechnologies.
Most technologies for hydrogen transport and storage are mature, although still at
small scale. Innovation and demonstration efforts are underway to bring thesetechnologies to the scale needed to facilitate the adoption of hydrogen as a clean
energy vector. In April 2023, the world’s first pure hydrogen storage facility in anunderground porous reservoir started operation (~3 GWh of hydrogen).
In end-use technologies, the situation is different: the technologies in sectors inwhich emissions are hard to abate, where hydrogen is expected to play a more
important role for decarbonisation, are much less mature and innovation is taking
place at a slower pace (Figure 5.8). Nevertheless, there are some positive signsof progress, such as in industry, where RD&D in the use of hydrogen for hightemperature heat in ancillary processes moved forward last year. In 2023,
30 international partners from 12 European countries launched HyInHeat todemonstrate the use of hydrogen in ancillary processes in aluminium and steel.
The Japanese utility Tokyo Gas and building materials manufacturer Lixil testedhydrogen instead of natural gas for heat treatment of aluminium 70, finding that thisseemed to have no adverse effect on the quality of products. The European Unionfunded H2GLASS project also started in 2023, bringing together 23 partners fromaround Europe to create a new technology to use 100% hydrogen in hightemperature heating processes in glass and aluminium manufacturing. In 2022,
the results of a pilot project using up to 40% hydrogen (on an energy basis) in themain kiln burner at Hanson Cement's Ribblesdale site (United Kingdom) were
published, showing no significant impact on the kiln burner or clinker quality. In
the transport sector, limited progress has been observed in the past year, althougha noteworthy milestone was achieved in March 2023 when the world’s firsthydrogen ferry entered into operation in Norway. In July 2023, MAN Energy
Solutions announced that it had completed the first successful combustion test of
a two-stroke ammonia marine engine at its research centre in Copenhagen(Denmark).

FuelCellWorks (2023), Tokyo Gas working with LIXIL on technological verification in the use of hydrogen in the
manufacturing process.

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Technology readiness levels of production of low-emission hydrogen and synthetic fuels, and infrastructure

IEA. CC BY 4.0.

Several hydrogen production technologies are already commercial, and others are maturing fast, while more innovation is needed in transportand storage technologies.

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Notes: AEM = anion exchange membrane; ALK = alkaline; ATR = autothermal reformer; CCUS = carbon capture, utilisation and storage; CH4 = methane; DME = dimethyl ether; GHR = gasheated reformer; LOHC = liquid organic hydrogen carrier; NH3 = ammonia; PEM = proton exchange membrane; SOEC = solid oxide electrolyser cell. Biomass refers to both biomass and waste.
Arrows show changes in technology readiness level as a consequence of progress in the past year. For technologies in the CCUS category, the technology readiness level refers to the overall
concept of coupling production technologies with CCUS and high CO2 capture rates. Pipelines refer to onshore transmission pipelines. Storage in depleted gas fields and aquifers refers to purehydrogen and not to blends. LOHC refers to hydrogenation and dehydrogenation of liquid organic hydrogen carriers. Ammonia cracking refers to low-temperature ammonia cracking. Technology
readiness level classification based on Clean Energy Innovation (2020).
Sources: IEA Clean Tech Guide (2023); IEA Hydrogen Technology Collaboration Programme.

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

Technology readiness levels of hydrogen end uses by sector

IEA. CC BY 4.0.
Notes: BF = blast furnace; DRI = direct reduced iron; FC = fuel cell; HRS = hydrogen refuelling station; HD = heavy-duty; HT = high throughput; ICE = internal combustion engine; LD = lightduty; MeOH = methanol; NH3 = ammonia; PEM FC = proton exchange membrane fuel cell; SOFC = solid oxide fuel cell; VRE = variable renewable electricity. “Other” in industry includes allindustrial sectors except methanol, ammonia and iron and steel production. “Other” in transport includes rail and aviation. Arrows show changes in technology readiness level as a consequenceof progress in the last year. Cogeneration refers to the combined production of heat and power. Technology readiness level classification based on Clean Energy Innovation (2020).
Source: IEA Clean Tech Guide (2023); IEA Hydrogen Technology Collaboration Programme.

I EA. CC BY 4.0.

Few key end-use hydrogen technologies are commercial, and innovation is progressing slowly on most fronts.

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Chapter 5. Investment, finance and innovation

Tracking patent applications
In January 2023, the IEA and the European Patent Office (EPO) released the joint
report Hydrogen patents for a clean energy future, assessing trends in hydrogen
patents from 2000 to 2020. This section presents an update of the analysis
including data from 2021, which is the latest data available from the EPO.
Patenting trends on hydrogen technologies in the main world regions, 20012021
IPFs

IPFs by main world regions

Climate-motivated technologies

600

600

450

450

300

300

150

150

0
2001

2005
2009
2013
2017
European UnionJapan
United States
Korea
China

2021

0
2001

2005
2009
2013
2017
2021
Production - Established
Production - Climate
Storage, transport, transformation - Established
Storage, transport, transformation - Climate
End-use - EstablishedEnd-use - Climate

IEA. CC BY 4.0.
Notes: IPFs = international patent families. The calculations are based on the country of the IPF applicants, using fractionalcounting in the case of co-applications. “Established” refers to well-established processes in the chemicals and refining
sectors and “Climate” refers to emerging technologies that could help mitigate climate change by making hydrogen a clean
energy product for a much wider range of sectors that would otherwise use fossil fuels.
Source: IEA analysis based on data from the European Patent Office.

Global hydrogen patenting surges as climate-motivated technologies take the lead, with theEuropean Union and Japan at the forefront.

Since the 2000s, global hydrogen patenting, as measured by international patentfamilies (IPFs), has surged at a compound annual growth rate of 5%. 71 The
European Union and Japan are leading the growth, accounting for 28% and 24%,
respectively, of all IPFs filed between 2011 and 2021. In the European Union,
Germany (12% of the global total), France (6%) and the Netherlands (3%) leadthe way (Figure 5.9). Meanwhile, the United States, with 19% of all hydrogenrelated patents, is the only major innovation centre with a decline in IPFs over thelast decade across all elements of the hydrogen value chain. Korea accounts for
8% of all IPFs filled from 2011 to 2021, with a remarkable compound annual

An international patent family represents an invention for which patent applications have been filed at two or more patentoffices worldwide. It is used as a means of identifying higher-value patents.

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Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

growth rate of 14% since 2001. China’s international patenting activity remains
modest (4%) but is on the rise, while the United Kingdom (3%), Switzerland (2%)
and Canada (2%) also make noteworthy contributions to global patenting.
The number of IPFs in hydrogen end-use technologies, although smaller than for
production technologies, has already been boosted by technologies which are
motivated by climate concerns. However, only in the past decade has there beena significant shift in hydrogen production technologies, moving away fromtraditional unabated fossil-based methods towards new technologies with thepotential to produce low-emission hydrogen. For production technologies, thetransition from established technologies to climate-motivated ones has been
driven primarily by the rapid growth of electrolysis technologies. Accordingly, morethan two-thirds of the IPFs in the hydrogen value chain now come from lowemission technologies.
Over the last decade, IPFs for electrolysis have more than doubled (Figure 5.10).
IPFs for alkaline electrolysis have increased but remain lower than for PEM or
SOEC, reflecting the greater maturity of the technology. While IPFs for PEM havegenerally been higher than those for SOEC, there was a shift in 2021, when thenumber of IPFs for SOEC overtook those for PEM. IPFs for AEM electrolysis,
although still moderate, have shown steady growth, especially in the last two
years.

IPFs

Patenting trends in hydrogen production by technologies, 2001-2021
800
700
600
500
400
300
200

0

CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST
CLI
EST

100

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Electrolysis

From biomass or waste

From gas

From other fossil fuels

Water splitting

By-product

IEA. CC BY 4.0.
Note: CLI = Climate technologies; EST = Established technologies; IPFs = international patent families.
Source: IEA analysis based on data from the European Patent Office.

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Hydrogen production technologies are experiencing rapid growth in patenting, boosted by
the rise of electrolysis and natural gas-based pathways with CCUS.

Global Hydrogen Review 2023

Chapter 5. Investment, finance and innovation

Patenting in hydrogen production from unabated fossil fuels peaked in 2009 andsince then there has been a moderate decline in IPFs. However, recent years
have seen a rise in innovation in natural gas-based technologies driven by climate
concerns (i.e. explicitly including the possibility of CO2 capture and storage), witha growth between 2019 and 2021 of over 70%, and with the United States playing
a major role. 72
Patenting trends in technologies that consume hydrogen, 2001-2021
IPFs

End-usesHydrogen-based fuels and carriers

400

100

300

75

200

50

100

25

0
2001

2005

2009

2013

2017

2021

Automotive

Aviation

Rail

Shipping

Buildings

Electricity generation

0
2001

Iron and steel

2009
2005
Ammonia cracking
Synthetic methane
Upgrading biofuels
Methanol production

2013
2017
2021
LOHC
Synthetic liquid HCs
Ammonia production

IEA. CC BY 4.0.
Notes: HCs = hydrocarbons. IPFs = international patent families. LOHC = liquid organic hydrogen carrier. Synthetic liquidhydrocarbons include synthetic diesel and synthetic kerosene production.
Source: IEA analysis based on data from the European Patent Office.

Patenting activity for key hydrogen-consuming technologies that enable decarbonisation in
sectors in which emissions are hard to abate remains remarkably low.

In hydrogen end-use technologies, around 90% of IPFs were driven by climate
concerns. Patents for hydrogen use in the automotive sector continue to grow atvery high rates, led by Japan (38% of IPFs from 2011 to 2021) and Europe (25%)(Figure 5.11). Aviation and shipping have lower levels of innovation, despite record
annual growth of 10% over the last two decades, with Europe (40%) and theUnited States (33%) dominating aviation and Europe (37%) and Japan (20%)
leading shipping. However, other industrial applications with limited
decarbonisation alternatives, such as steel production or hydrogen- andhydrogen-based fuels turbines, lack significant innovation. Patenting for hydrogen

Further insights on geographical trends by technology type are presented in the report Hydrogen patents for a clean energy
future.

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Chapter 5. Investment, finance and innovation

use in buildings has declined since the 2010s, suggesting a lack of interest due tomore suitable decarbonisation options.
Patent data show an increase in innovation for established hydrogen applications
in methanol and ammonia production since the late 2000s. Europe (50% of the
IPFs from 2011 to 2021, including 14% from Switzerland) and Japan (22%) leadin ammonia production patenting, while Europe (65%) dominates in methanol
production. Over the past decade, patenting for liquid organic hydrogen carriers(LOHCs) and ammonia cracking technologies experienced moderate growth.
However, innovation in the development of hydrogen-based fuels, such assynthetic kerosene, synthetic diesel or synthetic methane lost momentum, andefforts led by Europe (36%) and the United States (22%) have stagnated.

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While there are overall positive signals for growth of IPFs in hydrogentechnologies, this is largely driven by a focus on hydrogen production, particularly
on electrolysis. However, there remains a significant innovation gap on end-use
technologies, especially in sectors where decarbonisation alternatives are limited.
Governments must target innovation efforts accordingly, as there is a risk of amismatch between supply and demand technologies. Recognising that thehydrogen value chain is only as strong as its weakest link, it is critical to address
this gap.

Global Hydrogen Review 2023

Chapter 6. Policies

Chapter 6. Policies
Strategies and targets
Since the release of the Global Hydrogen Review 2022 (GHR 2022),
4 governments have updated their hydrogen strategies and a further
15 governments – mostly from emerging markets and developing economies(EMDEs) – have adopted new national hydrogen strategies. A total of
41 governments, accounting for nearly 80% of global energy-related CO2
emissions, have now adopted hydrogen strategies (Table 6.1).
National hydrogen roadmaps and strategies since September 2022

Government
Algeria
Brazil

Costa Rica
Ecuador
India
IsraelKenya
Namibia
PanamaSingapore
Sri Lanka
Türkiye
United ArabEmirates
United States
Uruguay

Description
Target to produce and export 30-40 TWh of hydrogen and hydrogen-based fuels by 2040.
Focus on pilot projects until 2030 to start up the sector.
The 2023-2025 Triennial Work Plan of the National Hydrogen Program defines thestrategy of the country, with three timeframes: by 2025, deploy low-carbon hydrogen pilot
plants across the country; by 2030, consolidate Brazil as a competitive low-carbonhydrogen producer; and by 2035 consolidate low-carbon hydrogen hubs in Brazil.
Target to install 0.15-0.50 GW of electrolysis capacity, to replace 8-10% of liquefied
petroleum gas (LPG) with “green” hydrogen and to deploy 100-250 fuel cell electricvehicles (FCEVs) and 200-600 fuel cell heavy-duty trucks by 2030.
Target to install 3 GW of electrolysers by 2040 and establish regulations for domestichydrogen use and potentially for export to international markets.
Target to produce 5 Mt of “green” hydrogen by 2030 (with associated 125 GW ofrenewable capacity additions) with additional potential to reach 10 Mt/yr with exports.
Interest in developing a domestic electrolyser manufacturing industry.
Plans explore options to integrate hydrogen into the national energy mix, along withconsideration of underground storage.
Target to install 150-250 MW of electrolysers and to produce 300-400 kt of nitrogen
fertilisers by 2032. Aim to develop a local “green” fertiliser industry to decreasedependency on imported fertilisers.
Target to produce 1-2 Mt of “green” hydrogen by 2030 and 10-15 Mt by 2050. Aims todevelop three hydrogen valleys* to start production and use.
In transport, the country aims to increase hydrogen and derivatives for maritime fuels
bunkering to 5% by 2030. Target to produce 0.5 Mt of hydrogen by 2030.
Aim to transform Singapore into a hub for hydrogen and hydrogen fuels in the Pacific.
Strong focus on electricity generation, with an estimate that hydrogen could meet up to
50% of electricity demand in 2050, as well as aviation and maritime.
Roadmap includes plans to export hydrogen derivatives by 2030.
Target to install 2 GW of electrolysers by 2030, 5 GW by 2035 and 70 GW by 2053.
Support for demonstration projects for “blue” hydrogen production.
Strategy includes a forecast for the production of 1.4 Mt of hydrogen by 2030, 7.5 Mt by
2040 and 15 Mt by 2050, through a mix of electrolysis powered with renewable andnuclear electricity, and natural gas with carbon capture, utilisation and storage (CCUS).
Target to produce 10 Mt of “clean” hydrogen by 2030, 20 Mt by 2040 and 50 Mt by 2050.
Update every 3 years (required by the Bipartisan Infrastructure Law).
Target to install 1-2 GW of electrolysers by 2030 and 10 GW by 2040, with initial focus ondomestic demand in the short term and exports in the long term.

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Table 6.1

Global Hydrogen Review 2023

Government
Belgium(update)Germany(update)Japan(update)Korea(update)

Chapter 6. Policies

Description
Vision structured around four pillars: become an import/transit hub for renewablehydrogen in Europe, expand technology leadership, establish a robust domestic market
and international co-operation.
Target to install 10 GW of electrolysers by 2030, and increased demand in industry andtransport to replace larger shares of natural gas, with over 1 800 km of pipeline
infrastructure.
Interim target for 12 Mt of hydrogen demand by 2040 (complementing previous targets for3 Mt by 2030 and 20 Mt by 2050) and to meet 1% of the gas supply in existing networks
with synthetic methane by 2030, increasing to 90% by 2050. Target to install 15 GW ofelectrolysis globally. Shift focus from FCEVs to the use of hydrogen in applications,notably in steel and petrochemical industries.
Updated target to reach 2.1% of total electricity production with hydrogen and ammonia
by 2030, and 7.1% by 2036. Creation of a framework for a Clean Hydrogen Certification
Mechanism to be released by the end of 2023.

*A hydrogen valley is a geographical area – a city, region, island or industrial cluster – where several hydrogen applications
are combined together into an integrated hydrogen ecosystem that consumes a significant amount of hydrogen, improving
the economics behind the project.
Notes: “Update” refers to strategies and roadmaps published for the first time before September 2022 that have since been
updated. See Explanatory notes annex for the use of the terms “green”, “blue” and “clean” hydrogen in this report.

These announcements of hydrogen strategies serve as the biggest driver ofgovernment funding. India’s National Green Hydrogen Mission includes nearly
INR 2 billion (Indian rupees) (~USD 25 million) subsidy to produce 5 Mt ofhydrogen for domestic consumption and 10 Mt of hydrogen for exports by 2030.
The United States adopted the US National Clean Hydrogen Strategy andRoadmap, revising their strategy to accord with recent carbon capture, utilisationand storage (CCUS), renewables, and sustainable aviation fuel (SAF) production
tax credits and funding opportunities. In addition, Belgium, Germany, Japan and
Korea have updated their existing hydrogen strategies, and a number of countries,
particularly in Europe, are in the process of revising their strategies.
The new and updated strategies show an increase in global ambitions to deploy
hydrogen technologies, as reflected in government targets for low-emissionhydrogen 73 production, which now account for 27 to 35 Mt, compared with 15 to
22 Mt at the time the GHR 2022 was released (Figure 6.1). The biggest
contributors to this increase are the targets of the United States (10 Mt of “clean”
hydrogen), India (5 Mt of “green” hydrogen) and Namibia (1-2 Mt of “green”
hydrogen). 74
On the demand side, however, there has been no increase in ambition, and only
two significant developments. In the European Union there has been a politicalagreement to set binding targets for the use of renewable fuels of non-biologicalorigin (RFNBO) in industry, transport and aviation by 2030, though some targets
were less ambitious than those proposed in the Fit for 55 package in 2021 (e.g.
42% of hydrogen demand to be met with renewable hydrogen, compared to an

74

See Explanatory notes annex for low-emission hydrogen definition in this report.
See Explanatory notes annex for the use of the terms “green” and “clean” hydrogen in this report.

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Chapter 6. Policies

initial target of 50%). Binding targets of this kind can send a clear signal to industry
about a future marketplace for low-emission hydrogen and hydrogen-based fuels.
In Japan, the updated Basic Hydrogen Strategy includes a target to meet 1% of
the gas supply in existing networks with synthetic methane by 2030.
Figure 6.1 Global targets for low-emission hydrogen production, use in industry andfuel cell electric vehicles by 2030
Use of low-emission hydrogen inindustry

35
30
25
20
15
10

0

6%
5%
4%
3%
2%

GHR 2022

GHR 2023

0%

2 000

1 600

1 200

800

400

1%

5

Fuel cell electric vehicles
Number of vehicles (thousand)40

Share of global demand today (%)

Mt hydrogen

Low-emission hydrogen production

GHR 2022

GHR 2023

0

GHR 2022

GHR 2023

IEA. CC BY 4.0.
Notes: GHR = Global Hydrogen Review. For countries that do not have a production target, the low-emission hydrogenproduction is estimated from the capacity targets assuming a capacity factor of 57% and an energy efficiency (LHV) of 69%
for electrolysers and 90% for fossil-based technologies. The dashed area represents the ranges of policy targets.

Global targets for low-emission hydrogen production keep growing, whereas targets forend use remain stalled.

Demand creation
Policy action is an important driver of demand for low-emission hydrogen to both
replace hydrogen produced with unabated fossil fuels in existing applications andto replace fossil fuels in new applications. Action on this front, however, issignificantly lagging behind what is needed to achieve climate goals (see Chapter
2 Hydrogen use).

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Policy efforts in this area have so far been limited, and despite some signs ofprogress, the past year was no exception. In 2022, the number of policies fordemand creation that governments either announced or implemented remained
almost the same as in 2021, with activity has slightly accelerating until August2023. However, this may soon change following the political agreement of theEuropean Commission, Council and Parliament to adopt mandatory targets formember states on hydrogen demand in industry and transport, and mandates forsynthetic fuels in aviation. In addition, the FuelEU Maritime initiative includes thepossibility of introducing a target for 2% of RFNBO in maritime fuels from 2034 if
these fuels have not reached a 1% share by 2031. These agreements are alreadyhaving an effect, with Romania’s parliament passing in June 2023 a law that sets

Global Hydrogen Review 2023

Chapter 6. Policies

mandates for renewable hydrogen use in industry and transport, including
penalties for non-compliant companies. In the same month, the Netherlands
announced plans to introduce subsidies on the demand side during 2024 andobligations for renewable hydrogen in industry (by 2026) and transport (by 2025).
There have also been developments outside of Europe. India announced in 2021
intentions to adopt quotas for refining, fertilisers and steel, which were finally notincluded in the National Green Hydrogen Mission, but remain under discussion
and could be adopted in the near future. New Zealand launched a consultation ona consumption rebate scheme to be implemented from 2025, and the UnitedStates announced a USD 1 billion plan to stimulate demand for low-emissionhydrogen, although details will not be released until later this year. The states ofColorado and Illinois have already passed bills with a tax credit for companies thatuse low-emission hydrogen to replace fossil fuels.

Supporting demand creation in different sectors

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Most policies to support demand creation that have either been announced or put
into place thus far target transport applications (Figure 6.2), such as subsidies forpurchasing FCEVs and for the development of hydrogen refuelling stations (HRS),
and more recently quotas and mandates. Despite industry and refining accounting
for practically all the demand for hydrogen today, the number of policies to create
demand for low-emission hydrogen in these sectors is very low. The low-carbon
fuel standard in California is today the only policy to have been implemented thattargets the stimulation of low-emission hydrogen demand in refining, but theEuropean Union-agreed mandatory target for the use of RFNBOs in transport(which also includes use in refining) is expected to lead to the implementation ofpolicies in member states. In the case of electricity generation, policy action has
been concentrated in Southeast Asia, with Japan and Korea leading
developments. Korea introduced the world’s first hydrogen power bidding market,
with the first tender winners announced in August. Japan announced capacity
auctions for low-carbon technologies, including hydrogen and ammonia co-firing
at fossil fuel power plants, with the first auction expected by October 2023.

Global Hydrogen Review 2023

Chapter 6. Policies

Transport

Industry

Figure 6.2 Number of policies to support hydrogen demand creation announced andentering in force by sector, 2021-2023
2023*
2022

In force

2021
2023*
2022
2021

Announced

Other

2023*
2022
2021
0

5

10

15

20

25

Number of policies

IEA. CC BY 4.0.
Notes: “Other” includes use in buildings, electricity generation and grid blending. 2023* = year to August 2023 only.

Policies for demand creation remain limited and highly concentrated in the transport
sector.

Mitigating investment risks•

Tax incentives: The US Inflation Reduction Act (IRA) passed in 2022 included
numerous tax credits for the production of hydrogen and hydrogen-based fuels(Box 6.1), and Canada announced a Clean Hydrogen Investment Tax Credit. In
2023, Egypt also introduced tax rebates for projects producing hydrogen andhydrogen-based fuels from renewable electricity.

•

Contracts for Difference (CfD): The United Kingdom adopted a CfD scheme
through the UK Low Carbon Hydrogen Business Model. In 2023, Germany
established Carbon Contracts for Difference (CCfD) for energy-intensive
industries, which companies using low-emission hydrogen to decrease GHG
emissions can participate in. Conversely, Japan will introduce a CfD scheme
based on the difference between the price of renewable and fossil fuel-basedhydrogen without the carbon price bench. More jurisdictions have also announcedplans to follow suit with CfDs, including Canada and the European Commission.

•Competitive bidding schemes for hydrogen production: Countries such as
India, the Netherlands and Denmark have implemented schemes to provide direct
payments per kilogramme of hydrogen produced over a certain number of years.

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While demand targets have remained low this year, governments have adopted
various financial tools to provide medium- to long-term stability across the wholevalue chain. Grants and subsidies are already commonly employed to reduce
CAPEX (Table 6.2), and some governments have established other types of
incentives to bolster hydrogen production:Table 6.2

Global Hydrogen Review 2023•

Chapter 6. Policies

Other policies: the creation of one-stop-shops to co-ordinate policy
implementation and regulatory procedures can reduce administrative burdens for
project developers. In 2022, Oman created Hydrogen Oman (HYDROM) with thispurpose, and just one year later, HYDROM announced the results of the firstauction for land allocation to renewable hydrogen projects. The H2Global initiative,
which presents a novel double-auction support mechanism, has received asignificant boost in government funding from Germany and the Netherlands.

Emerging markets and developing economies (EMDEs) have emphasised theimportance of international partnerships and finance. Concessional finance,
foreign loans and crowdsourced loans can reduce upfront costs and signal politicalcommitment to hydrogen, potentially further reducing risks for investors. Advanced
economies have committed funds through bilateral finance and multilateraldevelopment banks to respond to EMDEs’ requests and facilitate hydrogendevelopments in these countries (see Chapter 5 Investment, finance andinnovation).

Box 6.1

Financial incentives in the Inflation Reduction Act

In August 2022, the US Inflation Reduction Act (IRA) entered into force. The Act contains
numerous incentives to accelerate the deployment of a wide range of clean energy
technologies, including hydrogen. The most relevant incentive for hydrogen production is
the new Clean Hydrogen Production Tax Credit (45V), which grants a tax credit for aperiod of ten years for projects that are placed in service before January 2033 andproduce “clean hydrogen” (see Explanatory notes annex for the use of the term “clean”
hydrogen in this report). The amount of the tax credit varies from USD 0.12 to USD 0.6
per kilogramme of hydrogen produced depending on the emissions intensity of thehydrogen production. The value of these credits is multiplied by five if the facility meets
certain labour conditions.
Value of the tax credit granted by the Clean Hydrogen Production Tax Credit
Tax credit (USD/kg H2)

Carbon intensity of hydrogen(kg CO2-equivalent/kg H2)

Base credit

Meeting labour conditions

<0.45

0.60

3.00

0.45-1.5

0.20

1.00

1.5-2.5

0.15

0.75

2.5-4.0

0.12

0.60

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In addition to the 45V tax credit, the Act contains other tax incentives which stakeholders
involved in projects for hydrogen production, investments or associated equipment

Global Hydrogen Review 2023

Chapter 6. Policies

manufacturing may be able to claim. While guidance for many of these incentives isforthcoming, statutory language in the Act already states that in some circumstancesthese credits can be combined, improving the economic feasibility of a project. For
instance, a project developer that produces hydrogen using electricity from renewable or
nuclear electricity may be able to claim the hydrogen production tax credit, while the clean
electricity could qualify for production or investment tax credits as well. In other cases,
the project developer will need to opt for either the 45V or another incentive. For example,
projects producing hydrogen from fossil fuels with CCUS are prohibited from claiming
both the hydrogen production tax credit and the CCUS credit.
Tax incentives available for “clean” hydrogen and hydrogen-based fuels
Incentive

Credit amount

Description

Base

Bonus

Clean Energy Technologies
45 – 45Y
48 – 48E
48C
45U

Tax credit for facilities producing
USD 0.003/kWh of electricity
x5 for labour standards
renewable (45) or clean (45Y)
produced+10% for domestic
electricity
content
Tax credit for investment in+10% if in an energy
renewable energy (48) or clean
6% of qualified investmentcommunity
electricity (48E) projects
Tax credit for investments in
USD 10 billion of allocations foradvanced energy projects, as
investments in advanced
defined in 26 USC § 48C(c)(1)energy projects
Tax credit for qualified facilities
USD 0.003/kWh of electricity
x5 for labour standards
producing nuclear electricity
produced
Transportation fuels

40B

Tax credit for SAF with GHG
emissions <50% than fossil-based
jet fuel

USD 1.25/gallon

USD 00.50/gallon(depending on GHG
reduction)

45Z

Tax credit for production of cleantransport fuels, including SAF

USD 0.20/gallon (nonSAF)
USD 0.35/gallon (SAF),
multiplied by emissions factor
of fuelx5 for labour standards

Carbon sequestration
45Q

Tax credit for CO2 sequestration
coupled with permitted end uses.

USD 17/t CO2 (stored)
USD 12/t CO2 (used in EOR)USD 26-36/t CO2 (DAC
facilities)

x5 for labour standards

Notes: DAC = direct air capture; EOR = enhanced oil recovery; SAF = sustainable aviation fuels. 40B will be replaced by 45Z from2025.

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The cost of producing hydrogen from renewable electricity in the United States is in therange of USD 2.9-5.2/kg H2. However, the 45V and 45Y tax credits combined can reachup to USD 1.5/kg H2 of subsidy over the 25-year life of a project, which can lower the
production cost to USD 1.4/kg H2 in the regions with the most abundant wind and solar
resources. This production cost is within the range of the production cost of hydrogenfrom unabated natural gas. Projects using natural gas with CCUS to produce hydrogen
which choose either the 45Q or 45V subsidy could reach a levelised cost of production in
the same range as that of the unabated production route (or even lower in the case of aGlobal Hydrogen Review 2023

Chapter 6. Policies

retrofitted plant and cheap natural gas prices). The IRA tax credits can also have an
impact on the production of synthetic liquid fuels, such as synthetic kerosene used inaviation. In this case, producers may be able to claim the 45Z tax credit, although it
applies for a shorter timeframe than 45V. The impact of this tax credit could help to reduce
the production cost of synthetic kerosene by around USD 10/bbl, but this is still far fromcurrent kerosene prices (USD 90-130/bbl at an oil price of USD 75-85/bbl).

800

6

USD/bbl

USD/kg H₂

Impact of IRA subsidies on the levelised cost of hydrogen and synthetic kerosene
production
700

5

600

4

500

3

400

2

300 Bio-jet kerosene price200

Unabated natural gas

10

No tax 45Q
credit45V No tax 45V + No tax 45V +credit 45Y credit 45Y

SMR with CCS

Solar PV

Wind

100
0

Jet kerosene priceNo tax 45Z 45V + No tax 45Z 45V +credit45Y credit
45Y
Solar PVWind
IEA. CC BY 4.0.

Notes: SMR = steam methane reforming; CCS= carbon capture and storage. Assuming the plant enters into operation in 2025,with a lifetime of 25 years, and assuming full compliance with prevailing wage and registered apprenticeship requirements. Leftchart: Subsidies 45Q, 45V and 45Y assumed to last for 10 years. Natural gas price of USD 1.5-7.3/MBtu. Assuming a 95% capture
rate for SMR with carbon capture, utilisation and storage (CCUS), and a retrofitted SMR plant for the lower value of the range. The
range for renewable-based hydrogen refers to locations with different capacity factors. Right chart: Subsidies 45V, 45Y assumed
to last for 10 years; subsidy 45Z for 3 years. Current prices of jet and bio-jet kerosene refer to the period May-August 2023.

Despite the financial support provided by IRA incentives, there is still considerable
uncertainty around how these credits will be implemented, and – in some cases – which
projects will be eligible for what level of credit. Further details are expected to be provided
by the US Department of the Treasury in the coming months. In addition, there is also
uncertainty around the concrete details of the methodology to assess the carbon intensityof hydrogen production (e.g. the temporal correlation between the use of grid electricity
and renewable electricity fed into the grid), which are also expected to be clarified by the
US Department of Energy in the coming months. Clarity about the implementation of thesubsidies and the carbon intensity accounting methodology will provide the certainty thatdevelopers require to take firm investment decisions.

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In addition to the tax incentives, the Act includes numerous programmes with grants to
support clean energy technologies, which projects for the production of “clean” hydrogenand hydrogen-based fuels may be eligible for, and to support adoption of end-usehydrogen technologies.

Global Hydrogen Review 2023

PolicyGrants

Policy measures to mitigate investment risks in hydrogen projects in force or announced since August 2022
Country

StatusAustralia

In force

Belgium

In force

CanadaIn force

CanadaIn force

Estonia

In force

EuropeanUnion

In force

EU memberstatesIn force
andannounced

Germany

In force

Italy

In force

Italy

In force

Japan

In force

MoroccoAnnounced

Netherlands

In forceNew
ZealandAnnounced

Description
In the 2023-24 Federal Budget the government announced the Hydrogen Headstart programme with AUD 2 billion(Australian dollars) (~USD 1.4 billion) to support large-scale renewable hydrogen projects.
In October 2022, the federal government approved EUR 6 million (~USD 6.3 million) to support the development of“green” steel projects, using resources from the federal Recovery and Transition Plan.
The Canada Infrastructure Bank launched in September 2022 the Zero-Emission Vehicle (ZEV) Charging and Hydrogen
Refuelling Infrastructure Initiative, a CAD 500 million (Canadian dollars) (~USD 384 million) programme to accelerate
the private sector’s rollout of large-scale ZEV chargers and hydrogen refuelling stations.
In November 2022, the government granted CAD 475 million (~USD 365 million) to Air Products to support thedevelopment of its Net-Zero Hydrogen Energy Complex in Alberta.
In January 2023 the government opened a new subsidy to promote the introduction of “green” hydrogen in hard-toelectrify sectors. The programme counts a total budget of EUR 49 million (~USD 52 million) for the development ofprojects covering the whole supply chain of “green” hydrogen, with maximum support of up to EUR 20 million(~USD 21 million) per project.
In November 2022 the European Commission announced a EUR 3 billion (~USD 3.2 million) call to support large-scale
projects aiming to further innovative technologies, including with relation to hydrogen.
After the first set of Important Projects of Common European Interest (IPCEI) were approved in July 2022, in September
2022 the second IPCEI “Hy2Use” was approved, and EUR 5.2 billion (~USD 5.5 billion) will be used to fund 35 projects
for the production, storage, transport and use of renewable hydrogen in innovative industrial applications.
In 2023, the Commission approved a EUR 550 million (~USD 579 million) direct grant and conditional payment
mechanism of up to EUR 1.45 billion (~USD 1.53 billion) to support ThyssenKrupp Steel Europe in decarbonising its
steel production and accelerating renewable hydrogen uptake.
In April 2023, within the Temporary Crisis and Transition Framework, the European Commission approved an Italian
EUR 450 million (~USD 474 million) scheme to support projects for the production of renewable hydrogen in brownfieldindustrial areas and in sectors in which emissions are hard to abate.
EUR 230 million (~USD 242 million) to support the deployment of HRS in motorways and EUR 300 million(~USD 316 million) to support the deployment of HRS for rail applications
In 2023, NEDO committed JPY 220 billion (Japanese yen) (~USD 1.7 billion) to support the next phase of a liquefiedhydrogen supply chain project between Australia and Japan.
In 2023, Morocco's state-owned chemical company OCP announced an investment of USD 7 billion in an ammonia
plant that uses renewable-based hydrogen.
In 2022, the Netherlands’ Ministry of Economic Affairs and Climate cleared EUR 784 million (~USD 826 billion) in
national subsidies for electrolyser projects linked to the Hy2Use IPCEI.
In the 2023 Budget and in the Interim Hydrogen Roadmap, an NZD 30 million (New Zealand dollars) (~USD 19 million)
Clean Heavy Vehicles Grant was announced for zero emission heavy vehicles, including fuel cell heavy-duty vehicles.
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Table 6.2

Chapter 6. Policies

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Global Hydrogen Review 2023

PolicyGrants(continued)

Country

StatusPolandIn force

Saudi Arabia

In force

Spain

In force

Spain

In force

UnitedKingdom
UnitedStatesCompetitive
bidding
schemes forhydrogenproduction

Chapter 6. Policies

In force
In force

Denmark

In force

India

In force

Netherlands

In force

Description
In April 2023, the European Commission approved a EUR 158 million (~USD 166 billion) grant from the government of
Poland to support LOTOS Green H2, for the production of renewable hydrogen to be used in refining.
In 2023, the government committed USD 2.75 billion through the National Development Fund and the Saudi Industrial
Development Fund to the NEOM “green” hydrogen and ammonia project.
In June 2023, the government approved an addendum to the Spanish Recovery and Resilience Plan which included anincrease of nearly EUR 5.5 billion (~USD 5.8 billion) in funding provided for the Strategic Project for Recovery andEconomic Transformation on Renewable Energy, Hydrogen and Storage.
In April 2023, the government approved funding for EUR 450 million (~USD 474 million) to support a hydrogen project ofArcelor Mittal for the production of “green” steel.
The UK government allocated GBP 38 million (~USD 47 million) for the front-end engineering and demand (FEED) and
CAPEX of 15 low-carbon hydrogen projects.
In September 2022 the government opened the call for the Regional Clean Hydrogen Hubs, which includes up to
USD 7 billion to establish 6 to 10 regional “clean” hydrogen hubs.
In 2023, the Commission approved a EUR 170 million (~USD 179 million) Danish scheme to support renewablehydrogen production.
In 2023, the government approved INR 175 billion (~USD 2.2 billion) for the Strategic Interventions for Green Hydrogen
Transition programme, which will support domestic production of electrolysers and production of renewable-basedhydrogen. The scheme can provide an incentive with an upper cap of INR 50/kg (USD 0.64/kg) for the first year,
INR 40/kg (USD 0.51/kg) for the second year and INR 30/kg (USD 0.38/Kg) for the third year of production.
In 2023, the Commission approved a EUR 246 million (~USD 259 million) scheme to support renewable hydrogenproduction in the Netherlands.
In the 2022 Fall Economic Statement and Budget 2023, the government announced several tax credits to support the
deployment of hydrogen technologies:•

CanadaAnnounced

Tax incentives•

Clean Hydrogen Investment Tax Credit to support 15-40% of eligible costs of projects for hydrogen production,with higher support for those with emission intensity under 0.75 kg CO2/kg H2. The 15% tax credit was
extended to low-carbon ammonia production.
CCUS Investment Tax Credit to provide a 50% credit for equipment associated with point-source CCUS
projects, declining in 2030 and 2040 to incentivise early adoption.

Egypt

In force

In 2023, a bill on incentives for projects for “green” hydrogen and its derivatives was approved. Under the law, suchprojects will get a cash investment incentive ranging between 33% and 55% of the value of taxes to be paid. Incentives
also include exemption from value added taxes for equipment, raw materials and means of transportation.

UnitedStatesAnnounced

As part of the IRA, the US government offers a Hydrogen Production Tax Credit of USD 0.6-3/kg H2 based on the
carbon intensity of hydrogen production (Box 6.1).

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The proposal was in public consultation until June 2023 and the details of the design of the investment tax credit are
expected soon.

Global Hydrogen Review 2023

PolicyTax incentives(continued)

Contracts forDifference(CfD)

Country

Chapter 6. Policies

Status

Italy

Announced

CanadaAnnounced

EuropeanCommission

In force

Germany

In force

Japan

Announced

UnitedKingdom

In force

Germany
and the
Netherlands

In force

India

In force

Oman

In force

Other

Description
The government announced in the Legislative Decree 199/2021 the creation of a tariff mechanism for the promotion ofrenewable hydrogen, and is studying a mechanism to compensate producers for part of the operating costs ofrenewable hydrogen plants, also taking into account investment costs for the production plant.
As part of the Budget 2023, the government will consult on the development of carbon CfD as one of the investment
instruments of the Canada Growth Fund, aimed at de-risking projects by providing predictability on prices.
The European Commissions committed EUR 800 million (~USD 842 billion) from the EU Innovation Fund European
Hydrogen Bank for the first auction to support projects for the domestic production of renewable hydrogen. The Bank
aims to establish 10-year off-take agreements between the buyers and producers by paying a green premium of up to
EUR 4.5/kg H2. The Bank announced that it will also provide support for projects outside of the European Union that aim
to export to the region, but this may be implemented jointly with the H2Global Scheme.
In June 2023, the government announced a Carbon CfD scheme to support heavy industry shifting towards carbonneutral energy sources. Companies will bid in an auction based on the volume of emissions and the additional
estimated cost incurred per tonne of CO2 avoided, which will be paid by government to successful bidders. Winners will
receive a 15-year contract. Among other technologies, the programme will support both renewable and “blue” hydrogen,as long as they comply with the EU taxonomy for sustainable activities, although the level of support for renewablehydrogen will be higher.
Japan will introduce a CfD on the difference between the price of renewable and fossil fuel-based hydrogen without the
carbon price bench. The CfD will apply to companies supplying low-carbon hydrogen or ammonia.
The shortlisted projects of the first Electrolytic Allocation Round were announced in March 2023 and the contracts withthe finally awarded projects are expected to be finalised by the end of 2023. The second allocation round will follow by
the end of 2023.
In 2023, the German government committed EUR 4.9 billion (~USD 5.2 billion) to the H2Global initiative, in addition to
the EUR 0.9 billion (~USD 1.1 billion) committed in 2021. Also in 2023, the Netherlands decided to join H2Global andprovide EUR 0.3 billion (~USD 0.4 billion). H2Global combines a double-auction mechanism, with an intermediaryfunctioning as a dedicated offtake vehicle that sets direct contractual agreements with both producers and buyers ofhydrogen-based fuels, and absorbs existing regulatory uncertainties. The price gap between the low-emission andunabated fossil fuel-based hydrogen products is compensated with the available government funding. The bidding
process started in December 2022, with deliveries expected for the end of 2024, although tender deadlines haverecently been extended.
Renewable hydrogen and ammonia projects entering into operation before the end of 2030 will not pay electricity
transmission charges. For projects being commissioned after 2030, the waiver will be gradually reduced until being
removed for projects commissioned after January 2036.
In 2022, the government established Hydrogen Oman (HYDROM), a fully owned autonomous subsidiary of Energy
Development Oman, with the mandate to structure large-scale “green” hydrogen projects, managing the auction
process for allocating government-owned lands to projects, assisting in the development of common infrastructure andoverseeing the execution of projects. In April 2023, HYDROM released the result of the first auction for land allocation to
renewable hydrogen projects, with 6 projects worth USD 20 billion being awarded.
I EA. CC BY 4.0.

Note: See Explanatory notes annex for the use of the terms “green”, “blue” and “clean” hydrogen in this report.

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Industrial policies to support domestic manufacturing ofhydrogen technologies
Governments are increasingly putting domestic clean technology manufacturing
at the heart of their industrial strategies, with commitments to scale up investments
and diversify supply chains. This is partly to avoid potentially risky levels ofconcentration in the supply chain, especially in the light of China’s outsize role inmuch clean energy technology manufacturing and in processing and refining
many of the critical minerals required for a global clean energy transition.
In addition to the US IRA, which is accompanied by new authority to use
USD 500 million in funding from the Defense Production Act to increase
production of key clean energy technologies including electrolysers, a number ofother governments have announced and adopted policies to support domestic
manufacturing of hydrogen technologies.
Canada’s government announced in its 2022 Fall Economic Statement thecreation of Clean Technology Manufacturing Investment Tax Credits to support
Canadian companies that manufacture or process clean technologies and criticalmaterials. This does not specifically support hydrogen technologies, but itsupports the extraction, processing and recycling of critical minerals used inelectrolysers and fuel cells. In March 2023, the European Commission announced
the Net Zero Industry Act, which includes measures to strengthen manufacturing
to achieve the objective of domestically manufacturing at least 40% of thetechnology required to achieve the European Union’s 2030 climate and energy
goals. In May 2023, India announced the implementation of tenders to support
15 GW of electrolysis manufacturing capacity in the country, with a first call (for
1.5 GW) launched in June 2023. In the same month, the government of theNetherlands launched a consultation on a potential subsidy for manufacturers in
the hydrogen supply chain, including for electrolysers, with a total budget of
EUR 838 million (~USD 882 million).

Promotion of RD&D and knowledge-sharing
Government investment in RD&D in hydrogen technologies increased strongly in
2022. 75 This represents a continuation of the trend observed since the mid-2010s,
which has accelerated in the past two years. The growing interest of governmentsin the development of hydrogen technologies is also represented by the increased
share allocated to hydrogen in clean energy RD&D budgets, which reached its
historical maximum at 7.5% in 2022 (Figure 6.3).

The IEA has collected data on energy RD&D spending in member countries since 2004. Data on RD&D spending in Brazil
has been collected since 2013.

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75

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Chapter 6. Policies

USD million (2022)

Figure 6.3 Government RD&D spending for hydrogen technologies by region, 20182022

2 000

8%

1 500

6%

1 000

4%

500

2%

0

2018

2019

2020

2021

2022

EuropeAsia & Oceania
Americas
Share clean energy
RD&D (right axis)
IEA. CC BY 4.0.

Note: Data includes IEA member countries and Brazil.

Public budgets for RD&D on hydrogen are growing strongly, with the United States leading
the growth in 2022.

Beyond basic R&D, demonstration is a critical enabler for the scale-up of lowemission hydrogen production and use. There have been a limited number of new(or extended) demonstration programmes compared with previous years (Table
6.3), but governments have started to focus efforts on end-use applications,particularly in those applications where hydrogen can play a key role in a net zero
future. This is especially true of heavy industry applications, which are responsible
for the majority of the new demonstration programmes, in line with IEA
recommendations.

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The increase in public RD&D investment results from a combination of theextension and new phases of previously announced programmes, as well as theimplementation of new programmes. Practically all governments have increased
their RD&D budgets, with the United States responsible for the largest share of
growth in 2022. In September 2022, the Regional Clean Hydrogen Hub
programme opened its first call for proposals to develop six to ten hubs. In
addition, as part of the USD 8 billion of funding under the Bipartisan Infrastructure
Bill, the US government earmarked an annual budget of USD 200-400 million forbasic and applied R&D, USD 200 million for electrolyser RD&D, and
USD 100 million for manufacturing and recycling RD&D. In addition to this budget,the United States allocated a total of USD 319 million in FY 2022 for hydrogenprogrammes led by the Hydrogen and Fuel Cell Technologies Office within the
Office of Energy Efficiency and Renewable Energy. Elsewhere, another majorannouncement took place in July 2023, when India published an R&D “green”
hydrogen roadmap, establishing priorities on manufacturing of hydrogentechnologies and infrastructure, although this is not yet reflected in RD&D budgets.

Global Hydrogen Review 2023

Selected government programmes which include support for hydrogentechnology demonstration projects since August 2022

Government
Australia
Belgium

Programme

Description

Hydrogen Direct
Reduced Iron
Production plant
Grant tostrengthen importstrategy

The Australian Renewable Energy Agency announced AUD 0.9
million (Australian dollars) (~USD 0.7 million) funding to Calix Ltd. toevaluate a low-emission method for reducing iron.
Launch of a EUR 10 million (~USD 10.5 million) call for projects
concerning RD&D of infrastructure for hydrogen imports, financed
under the federal Recovery and Transition Plan.
DKK 9.71 million (Danish kroner) (~USD 1.4 million) granted todemonstrate a technology to convert e-methanol to e-SAF in a single
step, towards the aim of operating domestic SAF flights by 2025.
EUR 195 million (~USD 205 million) funding to develop hydrogentechnologies in different areas, including renewable hydrogenproduction, hydrogen valleys, storage, distribution and transport.
The programme, which has a specific call for hydrogen, supports
industrial demonstration with up to EUR 25 million (~USD 26 million),with up to EUR 15 million (~USD 16 million) per partner.
Open for 1 year from April 2023, the scheme provides EUR 20 million(~USD 21 million) for feasibility and environmental studies for pilot
and demonstration projects.
The EUR 40 million (~USD 42 million) subsidy includes funding forhydrogen demonstration projects.
In the Interim Hydrogen Roadmap, the government announced an
allocation of NZD 7.5 million (~USD 4.8 million) toward a range oftrial and demonstration initiatives.
The country earmarked KRW 205.9 billion (Korean won)(~USD 159 million) to develop technologies for electrolysis, fuel cells
and low-carbon power generation, including an ammonia co-firingdemonstration project from 2023-27.
The second call of the programme will allocate EUR 150 million(~USD 158 million) to 0.5 MW to 50 MW electrolysis demonstration
projects for local consumption in sectors which are hard to abate.
To accelerate the design and manufacturing of clean maritime
technologies, up to GBP 60 million (~USD 74 million) funding is being
made available for demonstrations of on-vessel technologies orshoreside infrastructure.

Denmark

ESAF-Aal project

European
Union

Clean Hydrogen
Partnership

Germany

Reallabore derEnergiewende

Netherlands

TSE Industriestudies

Netherlands

DEI+

New Zealand(unknown)

Korea

R&D budget forhydrogen-related
technologies

Spain

H2 Pioneros

UnitedKingdom

Clean Maritime
Demonstration
Competition
Round 3
Hydrogen
BECCS
Innovation
Programme
Red Diesel
Replacementcompetition
Industrial
HydrogenAccelerator (IHA)
Programme
Support ofHydrogen Shot

United States

Clean Hydrogen
Electrolysis,
Manufacturing,and Recycling

Phase 2 of the GBP 25 million (~USD 31 million) programme will
support the demonstration of hydrogen bioenergy with carbon
capture and storage (BECCS) technologies.
Phase 2 of the GBP 32.5 million (~USD 40 million) competition will
demonstrate a low-carbon alternative to red diesel on a construction
and mining or quarrying site and increase TRL to 7 upon completion.
Includes GBP 26 million (~USD 32 million) to finance thedemonstration of end-to-end industrial fuel switching to hydrogen.
Under Stream 2B, each demonstration project can apply for up to
GBP 7 million (~USD 8.6 million).
Through the H2@Scale Initiative, USD 47 million will be awarded for
R&D areas including hydrogen carriers, onboard storage systems,
transfer and fuelling for liquid hydrogen and membrane electrodeassemblies.
Provides USD 750 million over a period of 5 years to reduce the costof hydrogen production to less than USD 2/kg by 2026, advance
manufacturing and innovate the reuse and recycling of relevant
technologies.

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Table 6.3

Chapter 6. Policies

Global Hydrogen Review 2023

Chapter 6. Policies

International co-operation
International co-operation for hydrogen is increasing beyond finance (which iscovered in Chapter 5 Investment, finance and innovation), most notably for trade,as a response to the energy crisis andChapter 5 Investment, finance and innovation
growing concerns about energy security and diversification of supplies. Since therelease of GHR 2022, 31 hydrogen-specific bilateral agreements for co-operation
have been signed by governments around the world, 15 of which focus on trade. In
addition, hydrogen is becoming a more common topic in general co-operationagreements. Since 2022, 31 bilateral co-operation agreements on energy topics
have included hydrogen among the areas cited in the agreement (Figure 6.4).
Figure 6.4 Co-operation agreements between governments on hydrogen since August2022.

IEA. CC BY 4.0.
Notes: “Projects” refers to co-operation agreements to develop hydrogen-related projects. “Technology” refers to cooperation agreements to work on innovation, RD&D and technology development. “Trade” refers to co-operationagreements to develop international hydrogen supply chains. “Co-operation” refers to co-operation agreements with adifferent focus to the other categories. Only co-operation agreements specific to hydrogen and its derivatives are depictedin the figure.

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Co-operation among governments on hydrogen remains strong, with an important focus on
the development of international supply chains.

Global Hydrogen Review 2023

Chapter 6. Policies

The growing interest in hydrogen trade and in the creation of an international
market for hydrogen and hydrogen-based fuels has pushed co-operation beyond
bilateral agreements. In July 2023, in Goa (India), 14 governments signed a joint
declaration for the creation of an International Hydrogen Trade Forum within theframework of the Clean Energy Ministerial Hydrogen Initiative. The aim is for theforum to become the main platform to foster dialogue between potential importingand exporting countries.
Other multilateral co-operations have also strengthened their work on hydrogen.
The G7, in its Climate, Energy and Environment Ministers’ Communiqué,committed to enhance efforts on the development of a global market, including
reliable international standards and certification schemes, as well as building theenabling environment to encourage safe use of hydrogen, promoting relevant
regulations, safety codes and standards. The G20, in the Energy Transitions
Ministers’ Meeting Outcome Document and Chair’s Summary, agreed five HighLevel Voluntary Principles on Hydrogen to support the acceleration of production,utilisation and development of transparent and resilient global markets forhydrogen. At the 27th Conference of the Parties (COP 27), countries under the
Breakthrough Agenda agreed to take action to strengthen demand signals, toaccelerate and expand a co-ordinated programme of work to develop standards
and associated certification schemes, to increase the number and geographicaldistribution of hydrogen demonstration projects and to facilitate access toincreased concessional finance and other mechanisms for EMDEs.

Standards, certification and regulations
Standards, certification and regulation on the environmental
attributes of hydrogen
The establishment of standards, regulations and certification systems that address
the environmental attributes of hydrogen and ensure compliance are of paramountimportance to facilitate the adoption of low-emission hydrogen. Over the past few
years, stakeholders – spearheaded by the International Partnership for Hydrogenand Fuel Cells in the Economy (IPHE) – have concentrated their efforts ondeveloping a common global methodology for GHG emissions accounting
throughout the life-cycle of hydrogen and its derivatives.

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The IPHE has finalised its Methodology for determining the GHG emissions
associated with the production, conversion and transport of hydrogen. This
document will play a crucial role in the development of an International Standard
by the International Organization for Standardization (ISO). The ISO aims topublish a Technical Specification by the end of 2023 and subsequently a draft
International Standard by the end of 2024.

Global Hydrogen Review 2023

Chapter 6. Policies

Governments worldwide are simultaneously taking steps to implement regulations
and certification systems pertaining to the environmental attributes of hydrogen(Table 6.4). There are currently seven national and supranational governmentswith regulatory frameworks in place. A further six countries have announced
forthcoming regulations, although the specific methodologies to demonstratecompliance with these frameworks are yet to be determined.
While these certification systems and regulatory frameworks share certain
similarities in terms of scope, system boundaries and eligibility criteria, there arealso significant divergences. This variability poses challenges for project
developers – particularly those aiming to participate in a potential global market –who need to undertake ad-hoc certification processes for each country they wish
to access, resulting in increased transaction costs.

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Consequently, in the absence of greater interoperability in regulatory frameworks
and certification, trade in hydrogen is likely to be limited to bilateral agreements,
impeding the development of an international market. The establishment of a
global hydrogen market could be greatly aided by collaboration and co-operation
among governments to foster a certain level of interoperability among regulatory
frameworks. A full harmonisation of these certification systems and regulatory
frameworks seems infeasible in the short term, but enabling mutual recognition
among the different certification schemes can be a first step to minimise market
fragmentation. In July 2023, the IEA Hydrogen Technology Collaboration
Programme started a new Task on Hydrogen Certification to work on technicalmatters of harmonisation of certification. The need for mutual recognition ofcertification schemes was also acknowledged in the G20 Energy Transitions
Ministers’ Meeting Outcome Document and Chair’s Summary, and in the G7
Climate, Energy and Environment Ministers’ Communiqué. Referencing theemissions intensity of hydrogen production, based on a joint understanding of themethodology employed for regulation and certification, can be a starting point toenable mutual recognition of certificates, facilitate smoother market access andsupport the growth of a thriving international hydrogen market.

Global Hydrogen Review 2023

Overview of existing and planned regulatory frameworks and certification systems for hydrogen and hydrogen-based fuels

Government

Name

Purpose

Product

StatusCriteria

Australia

Guarantee of Origin
certificate scheme

Voluntary

Hydrogen,hydrogen carriers

Underdevelopment

No eligibility criteria. The only requirement is to implement anemissions accounting methodology for the hydrogen produced.

CanadaClean Hydrogen
Investment Tax Credit

Regulatory, accessto tax credits

Hydrogen,ammonia

Underdevelopment

Production below certain emissions intensity levels (<0.75, 0.75-2,
2-4 g CO2-eq/g H2). For ammonia, only one emissions intensity
level is defined (<4 g CO2-eq/g H2-eq).

Denmark

Guarantee of Origin
certificate scheme

Voluntary

Hydrogen,hydrogen-based
fuelsOperational

Production from renewable electricity.

European
Union

Renewable Energy
Directive II

Regulatory, countagainst renewableenergy targets

Hydrogen,hydrogen-based
fuelsOperational(certification
underdevelopment)

Production from renewable electricity (or grid electricity with<65 g CO2-eq/kWh) meeting criteria on temporal and geographicalcorrelation and additionality of renewable generation.

FranceFrance OrdinanceNo. 2021-167

Regulatory, accessto public support
programmes

HydrogenUnderdevelopment“Low-carbon hydrogen”: production with emissions intensity<3.38 g CO2-eq/g H2. “Renewable hydrogen”: production withemissions intensity <3.38 g CO2-eq/g H2 and renewable sources.

Japan

Basic Hydrogen
Strategy

Regulatory, accessto public support

Hydrogen,hydrogen-based
fuels

Under
development

Production with emissions intensity <3.4 g CO2-eq/g H2.

Korea

Clean Hydrogen
Certification
Mechanism

Regulatory, accessto public support

HydrogenUnderdevelopment

Production with emissions intensity <4 g CO2-eq/g H2.

India

Green Hydrogen
Standard for India

Regulatory, accessto public support

HydrogenUnderdevelopment

Production from renewable energy with emissions intensity<2 g CO2-eq/g H2.

Italy

Guarantee of Origin
certificate scheme

Voluntary

Electricity andrenewable gases(incl. hydrogen)

Operational

Production from renewable sources.

Netherlands

Guarantee of Origin
certificate scheme

Voluntary

HydrogenOperational

Production from renewable electricity.

Spain

Guarantee of Origin
certificate scheme

Voluntary

Renewable gases(incl. hydrogen)

Operational

Production from renewable electricity.

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Table 6.4

Chapter 6. Policies

Global Hydrogen Review 2023

Chapter 6. Policies

Government

Name

Purpose

Product

StatusCriteria

UnitedKingdom

Low Carbon
Hydrogen Standard;
Certification Scheme

Regulatory, accessto public support

HydrogenOperational(certification
underdevelopment)

Production with emissions intensity <2.4 g CO2-eq/g H2.

UnitedKingdom

Renewable Transport
Fuel Obligation

Regulatory, accessto public support

Hydrogen (use intransport)

Underdevelopment

Production from renewable energy (excluding bioenergy) withemissions intensity <4.0 g CO2-eq/g H2.

UnitedStatesClean Hydrogen
Production Standard;
Tax Credit.

Regulatory, accessto public support

HydrogenUnderdevelopment

Production below certain emissions intensity levels (<0.45,
0.45-1.5, 1.5-2.5, 2.5-4 g CO2-eq/g H2) eligible for different levels
of investment tax credits support.

I EA. CC BY 4.0.

Note: the table only includes certification systems established by governments, but some private certification schemes have also been developed or are under development. See more details in
Towards hydrogen definitions based on their emissions intensity.

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Global Hydrogen Review 2023

Chapter 6. Policies

Operational and safety standards
Beyond environmental attributes, the creation of hydrogen value chains requires
the development of a comprehensive portfolio of international standards dealing
with safety, technology compatibility and operational issues.
The European Clean Hydrogen Alliance published in March 2023 a roadmap onhydrogen standardisation, providing a comprehensive overview of standardisation
gaps, challenges and needs, and recommendations to streamline and accelerate
the development of the standards required. The roadmap will help the European
Commission to prepare a request to the European Standardisation Organisations
for identified hydrogen standards.
Regarding safety standards, the European Hydrogen Safety Panel (EHSP) has
updated its guidance on Safety Planning and Management in EU hydrogen andfuel cell projects. The aim is to support EU projects to incorporate state-of-the-art
practices on hydrogen safety by integrating safety learnings, expertise andplanning. In addition, the EHSP has worked on a new document with the statistics,
lessons learned and recommendations from an analysis of the Hydrogen Incident
and Accidents Database. 76
There has also been progress on the development of standards for hydrogen
operations, particularly for new hydrogen applications. SAE International, astandard-developing organisation based in the United States, announced that it isdeveloping high-flow, general purpose prescriptive hydrogen fuelling protocols forthe 35 and 70 MPa pressure classes, with a Technical Information Report
expected in October 2023. The International Electrotechnical Commission
published two new standards for performance testing of fuel cell/battery hybrid
systems in excavators and power-to-methane energy systems based on solidoxide cells, and revised another two standards on safety and performance testingfor fuel cell systems in trucks. The ISO has not published new standards since
GHR 2022, but is currently working on five standards related to fuelling stations
and protocols. In addition, in August 2023 China’s National Standards
Commission released standard guidelines covering safety and operational
aspects of hydrogen production, storage, transport and end use.
A key area in which there has been no notable progress is in the development ofhydrogen leakage measurement, reporting and verification protocols, and thedevelopment of methods and standards to detect and repair hydrogen leakage.
Tapping into the full potential climate benefits of hydrogen technologies will require
minimising hydrogen leakage (see Box 4.3 in Chapter 4 Trade and infrastructure),
which in turn will depend on the development of such methods and standards.

Access and download the full Hydrogen Incident and Accidents database set HIAD 2.0.

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76

Global Hydrogen Review 2023

Chapter 6. Policies

Regulations on infrastructure, permitting and other areas
Governments have also adopted regulations unrelated to the environmental
attributes of hydrogen, in areas such as infrastructure or permitting.
With regards to infrastructure, the Australian government has extended thenational gas regulatory framework to hydrogen and other renewable gases,
allowing for a nationally consistent approach to gas pipeline regulation for allgases covered. At the end of 2021, the European Commission presented a
proposal to revise EU gas market rules to facilitate the development of hydrogen
infrastructure and regulate its use. In March 2023, the European Council took its
position on this regulation and negotiations with the European Parliament havenow begun, with the three institutions aiming to finalise these negotiations by theend of 2023. Also in Europe, in July 2023 Belgium passed its first Hydrogen Law
to regulate the transport of renewable hydrogen through a network of pipelines,
and introduced the function of a grid operator.
Regarding permitting, in the European Union the newly agreed Renewable Energy
Directive includes regulatory provisions to fast-track permitting for renewableenergy projects. EU member states are starting to take action on this front, withsome – like Denmark, Italy and Portugal – including hydrogen in this streamlining
effort.

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In June 2023, the United Nations Economic Commission for Europe World Forumfor Harmonization of Vehicle Regulations adopted amendments to the Global
Technical Regulation No. 13, “Hydrogen and fuel cell vehicles” to improve test
procedures, to extend the regulation to heavy vehicles, and to better reflect thestate-of-the-art with respect to hydrogen vehicles. Acceptance of the draft
amendments means that the first regulation for heavy-duty vehicles fuelled byhydrogen is now in place.

Global Hydrogen Review 2023

Annex

Annex
Explanatory notes
Projections and estimates
Projections and estimates in this Global Hydrogen Review 2023 are based on
research and modelling results derived from the most recent data and information
available from governments, institutions, companies and other sources as of July
2023. Updates will be included in the World Energy Outlook 2023 to be publishedin October 2023.

Terminology relating to low-emission hydrogen
In this report, low-emission hydrogen includes hydrogen which is produced
through water electrolysis with electricity generated from a low-emission source(renewables, i.e. solar, wind turbines or nuclear). Hydrogen produced frombiomass or from fossil fuels with carbon capture, utilisation and storage (CCUS)
technology is also counted as low-emission hydrogen.
Production from fossil fuels with CCUS is included only if upstream emissions are
sufficiently low, if capture – at high rates – is applied to all CO2 streams associatedwith the production route, and if all CO2 is permanently stored to prevent its release
into the atmosphere. The same principle applies to low-emission feedstocks andhydrogen-based fuels made using low-emission hydrogen and a sustainablecarbon source (of biogenic origin or directly captured from the atmosphere).
The IEA does not use colours to refer to the different hydrogen production routes.
However, when referring to specific policy announcements, programmes,
regulations and projects where an authority uses colours (e.g. “green” hydrogen),or terms such as “clean” or “low-carbon” to define a hydrogen production route,we have retained these categories for the purpose of reporting developments inthis review.

Terminology for carbon capture, utilisation and storage

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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 enhanced oil recovery
or 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. in urea
production, CCU is specified.

Global Hydrogen Review 2023

Annex

Scenarios used in this Global Hydrogen Review
This Global Hydrogen Review relies on two scenarios to track progress onhydrogen production and use:The Stated Policies Scenario (STEPS) explores how the energy system would
evolve if current policy settings are retained. These include the latest policy
measures adopted by governments around the world, such as the Inflation
Reduction Act in the United States, but do not assume that aspirational or
economy-wide targets will be met unless they are backed up with detail on how
they are to be achieved.



The Net Zero Emissions by 2050 Scenario (NZE Scenario) is a normative scenariothat sets out a pathway to stabilise global average temperatures at 1.5°C above
pre-industrial levels. The NZE Scenario achieves global net zero energy sector
CO2 emissions by 2050 without relying on emissions reductions from outside theenergy sector.

Currency conversions

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This report provides the stated values of programmes and projects in the currency
stated in their announcement. These values, in many instances, are converted to
US dollars for ease of comparison. The currency exchange rates used correspondto an average value for the year of the announcement based on OECD exchange
rates.

Global Hydrogen Review 2023

Annex

ABS
ADB
AEM
ALK
ASU
ATR
AUD
BECCS
BEV
BF
BOP
CAD
CAPEX
CCfD
CCGT
CCS
CCU
CCUS
CF
CfD
CH4
CHP
CO2
COP
DAC
DKK
DME
DOE
DRI
EBRD
EHSP
EIB
EMDE
EOR
EPA
EPC
EPO
ETF
ETS
EUR
FC
FCEV
FEED
FID

American Bureau of Shipping
Asian Development Bank
anion exchange membrane
alkaline
air separation unit
autothermal reformer
Australian dollars
bioenergy with carbon capture and storage
battery electric vehicle
blast furnacebalance of plant
Canadian dollar
capital expenditurecarbon contract for difference
combined-cycle gas turbine
carbon capture and storage
carbon capture and use
carbon capture, utilisation and storage
capacity factor
contract for difference
methanecombined heat and powercarbon dioxide
Conference of the Parties
direct air capture
Danish kroner
dimethyl ether
Department of Energy (United States)
direct reduced iron
European Bank for Reconstruction and Development
European Hydrogen Safety Panel
European Investment Bank
Emerging markets and developing economies
enhanced oil recovery
Environmental Protection Agency (United States)
engineering, procurement and construction
European Patent Officeexchange-traded fund
Emissions Trading Systems
Eurofuel cell
fuel cell electric vehicles
front-end engineering and design
final investment decision

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Abbreviations and acronyms

FT
FY
G7
G20
GBP
GHG
GHR
GWP
H2
H2I
HC
HD
HRS
HT
HVAC
HVDC
HYDROM
ICE
IDB
INR
IPCC
IPCEI
IPF
IPHE
IRA
IRENA
ISO
JPY
KRW
LCOA
LCOH
LD
LH2
LNG
LOHC
LPG
MeOH
MoU
N2O
NASDAQ
NG
NH3
NOx
NZD
NZE

Annex

Fischer-Tropsch
fiscal year
Group of Seven
Group of Twenty
British poundgreenhouse gases
gas-heater reformer
global warming potential
Hydrogenthe Hydrogen Initiativehydrocarbon
heavy-dutyhydrogen refuelling stations
high throughput
high voltage alternating current
high voltage direct current
Hydrogen Oman
Internal Combustion Engine
Inter-American Development Bank
Indian rupees
Intergovernmental Panel on Climate Change
Important Projects of Common European Interest
international patent familyInternational Partnership for Hydrogen and Fuel Cells in the
EconomyInflation Reduction Act (United States)
International Renewable Energy Agency
International Organization for Standardization
Japanese yen
Korean won
levelised cost of ammonia
levelised cost of hydrogenlight-dutyliquefied hydrogenliquefied natural gas
liquid organic hydrogen carrierliquefied petroleum gas
methanolmemorandum of understanding
nitrous oxide
National Association of Securities Dealers Automated Quotations
natural gas
ammonia
nitrogen oxides
New Zealand dollars
Net Zero Emissions by 2050 Scenario

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Global Hydrogen Review 2023

Global Hydrogen Review 2023

OPEX
O&M
PEM
POX
PPA
PV
RD&D
RFNBO
SAF
SHASTA
SMR
SOEC
SOFC
STEPS
SUV
TCP
TEN-E
TRL
TTF
USD
VC
VRE
WACC
ZETI
ZEV

Annex

operating expenditure
operational expenditures and maintenance costs
proton exchange membrane
partial oxidation
power purchase agreement
photovoltaic
research, development and demonstration
renewable fuels of non-biological origin
sustainable aviation fuel
Subsurface Hydrogen Assessment, Storage, and Technology Acceleration
steam methane reformer
solid oxide electrolyser
solid oxide fuel cellStated Policies Scenario
sports utility vehicle
Technology Collaboration ProgrammeTrans-European Networks for Energy
technology readiness level
Title Transfer Facility
United States dollars
venture capitalvariable renewable electricity
weighted average cost of capital
Zero-Emission Technology Inventory
zero emission vehicle

Units
degree Celsius
metric unit of pressure
barrelbillion cubic metrescarbon dioxide equivalent
grammegallon (United States)
gigajoulegigajoule of coal
gigajoule of produced natural gas
gigawatt
gigawatt-hour
gigawatts per yearinch
kilogrammekilogramme of carbon dioxide equivalentkilometreskilotonnes

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°C
bar
bbl
bcm
CO2-eqg
gallonGJ
GJcoal
GJNG
GW
GWh
GW/yr
inch
kg
kg CO2-eq
kmkt

Global Hydrogen Review 2023

kilotonnes per year
kilowatt
kilowatt electric
litre
million British thermal units
megapascal
million tonnes
million tonnes of carbon dioxide
million tonnes of hydrogen equivalent
megawatt
megawatt-hournormal cubic metre
normal cubic metres per hourparts per billion
tonne
tonne of carbon dioxideterawatt-hour

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ktpa
kW
kWe
L
MBtu
MPa
Mt
Mt CO2
Mt H2-eq
MW
MWh
Nm3
Nm3/h
ppb
t
t CO2
TWh

Annex

International Energy Agency (IEA).
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